Recently MISO has gained FERC’s approval on two key proposals that matter to its states – to reduce the interconnection queue timeline and allocate transmission costs to subregions. The latter gained more attention than the former because everyone in the industry focuses on transmission as a tool to interconnect renewables sooner than later.
While MISO plans for the long term, MISO also needs to have operating reserves to ride through this summer. And demand response provides those operating reserves if MISO states remove the restrictions for aggregated retail programs to participate in MISO operating reserve markets.
FERC approves MISO’s reduced queue timeline
On March 15, MISO gained FERC’s approval for a reduced Generator Interconnection Process (GIP) timeline that decreased the time it takes to process renewable developer’s interconnection study request from 505 calendar days to 373 days. Renewable developers EDF Renewables, Inc. and NextEra Energy Resources, LLC favored MISO’s filing in docket # ER22-661.
MISO has created a default path and an optional path to Generator Interconnection Agreement (GIA) execution with this filing. Developers must choose between a more timely path to GIA negotiations with less cost certainty (default path) or a less timely path with more cost certainty entering into GIA negotiations (optional path).
This reduced GIP filing shall apply to all requests that have not begun the final system impact study in DPP Phase III as of 03/15/22. MISO has updated its queue timeline.
FERC’s approval of MISO’s December 15, 2021 proposal is a win for MISO states because 75,000 MW of solar is waiting to be interconnected at MISO, with more than a third in Indiana, Michigan, Louisiana, and Arkansas. So, both MISO Midwest and South states benefit from this MISO queue improvement.
FERC approves MISO’s subregional cost allocation for transmission
MISO also received FERC’s approval (ER22-995) on its proposal to allocate costs for Multi-Value Projects (MVPs) to MISO’s midwest and southern states separately.
Before Entergy and other utilities in the South integrated with MISO, MISO had one cost allocation procedure for MVPs. During the 5-year transition period, MISO did not allocate transmission costs across subregions as part of the integration agreement. MISO was working with stakeholders on Long-Range Transmission Planning (LRTP) after the transition period ended. But regulators in the South region didn’t want to pay for transmission costs from the Midwest region. So, MISO had to put together a proposal that allocates transmission costs to each subregion separately.
MISO’s filing and FERC’s acceptance reflect MISO states’ strong preference for high voltage transmission to interconnect renewable generation. But transmission takes at least 10 years to build.
FERC Commissioner Christie calls out MISO states
Commissioner Mark Christie’s concurrence while approving MISO’s subregional cost allocation deserves special mention because it praises the Organization of MISO States (OMS) involvement in MISO’s stakeholder process and provides a cautionary note for all MISO states involved.
For instance, Christie calls out Michigan Public Service Commissioner’s role in the MISO stakeholder process without naming Dan Scripps “OMS emphasized the central role that it played in developing the proposal, including the fact that an OMS board member acted as the chair of the MISO cost allocation stakeholder forum.” Christie’s concurrence comes with a bright red caution with this statement, “I share the concern expressed by parties in this proceeding regarding the allocation of costs within the two subregions based on the postage stamp method for cost allocation. The postage stamp cost allocation method is a pure socialization method, and as set forth further below, MISO’s case on this record for using postage stamps, even if limited to the MISO Midwest Subregion for the next two tranches of portfolios, is underwhelming.”
MISO’s 2022 summer assessment warnings gather both NERC and FERC’s attention
MISO Board could not have asked for a better headline than both NERC and FERC concerned about relying on emergency procedures this summer because the MISO Board needs to approve the first portfolio ($10B) of transmission in July.
MISO’s summer assessment, coupled with CAISO and ERCOT’s summer findings, has gained both NERC and FERC’s attention. For instance, FERC’s Chairman Glick said, “Keeping eye on West, ERCOT, & parts of MISO this summer.” NERC’s summer assessment also called out MISO, “MISO is considered a “high” risk for running short on operating reserves under normal conditions.”
So, what does all this mean for MISO states?
MISO states must remove state opt-out for demand response
Transmission cannot be built overnight; demand response can be if allowed to participate. Most MISO states held back their utility demand response from participating in MISO markets for at least two reasons: 1) Utility DR programs are rate-based by the state commissions for that state’s customers. So, states don’t want these retail programs to be called by the MISO operator in a grid emergency in another state. 2) If a state allows third-party aggregators to bundle these DR programs for wholesale market participation, the incumbent utility will be left to provide service for low-income households because aggregators will cherry-pick industrial and other high-income customers.
What is missing from these 2 often cited reasons is the lost opportunity for demand flexibility to respond to grid emergencies. MISO’s recent Planning Resource Auction indicates Load Modifying Resources (demand response and behind the meter generation) capacity increased by 4.4% in this auction compared to the last auction.
LMRs provide planning reserve benefits, but what about operating reserves? Demand Response Resources at MISO can provide spinning and supplemental reserves but have a 1 MW size restriction. Aggregated demand response programs must be able to respond to economical price signals.
Demand Response Resources can provide operating reserves
At MISO, retail programs such as industrial interruptible load programs, controlled hot water heater programs, controlled air conditioner programs, and load reduction programs registered by Aggregators of Retail Customers (ARCs) are DRR-Type I. Any retail program with an on/off switch is DRR – I. Additionally, behind the meter generators capable of receiving electronic (via ICCP) dispatch instructions from MISO are DRR-Type II. Hence DRR – II resources can comply with MISO instructions. Historically, MISO has 600-800 MW of DRR-I and 80-100 MW of DRR-II registered in the market. (Source Table 15) These DRR amounts could increase if states remove the restriction because DRR can provide operating resources at MISO.
MISO has 5,000-7,000 MW of demand response categorized as LMRs, meaning it is a planning resource capable of providing planning reserves. But we need resources capable of providing operating reserves to reduce the likelihood of rolling blackouts.
Suppose NERC is concerned about capacity shortfalls in MISO. In that case, NERC must insist on resources capable of providing operating reserves, which is missing from MISO states due to their insistence on holding back retail demand response programs from participating in transmission grid emergencies. At MISO, Voltus, an aggregator, exceeded its commitment during July 2021 event. Similarly, during the winter storm in February 2021, ERCOT found that its Emergency Response Service exceeded its obligations when it mattered the most.
Individual MISO states and OMS can signal their willingness to work with MISO when they provide comments to FERC on MISO’s Order 2222 proposal due June 6.