Utility Integration

FERC should act on these 3 issues in 2022

FERC should act on these 3 issues in 2022
(Image by analogicus from Pixabay )

As the top energy regulator, FERC had a busy year in 2021. FERC was actively involved in the investigation into the Texas winter event, and the joint report with NERC did not find fault with renewables. FERC has opened several lines of inquiry into building the future grid. But FERC needs to do more in 2022.

First, FERC needs to tackle the cost allocation for interregional transmission because that is the lesson learned from both MISO and SPP queue reform that PJM is missing in its current proposal.

Second, FERC issued Order 2222 to bring distributed energy resources (DERs) into the transmission fold because they provide grid services like utility-scale technologies. But distribution utilities are erecting barriers under the safety and reliability excuse. FERC needs to step in here and leverage partnerships with state regulators to clarify the aggregator’s role.

Finally, removing the state opt-out for demand response will provide certainty in the marketplace for aggregators to bid heterogenous aggregations, including distributed resources with rooftop solar/storage.

FERC had a busy 2021

FERC opened the new office of public participation in 2021. Another key development included the addition of Commissioner Willie L. Phillips as the fifth Commissioner after Commissioner Neil Chatterjee’s term ended.

Perhaps the biggest achievement for FERC in 2021 was the issuance of an Advanced Notice Of Proposed Rulemaking (ANOPR) on transmission planning and generator interconnection reform. The industry can expect NOPRs on individual pieces of ANOPR such as generator interconnection related participant funding, cost allocation for network upgrades related to renewable projects located on the RTO seams.

FERC also opened NOPR on transmission line ratings and electric transmission incentives for incentivizing Grid Enhancing Technologies (GETs). Before the end of the year, FERC issued Order 881 mandating RTOs to include Ambient Adjusted Ratings (AARs) in transmission planning and operational planning protocols. While FERC stopped short of mandating Dynamic Line Ratings (DLRs), FERC has opened a new docket on establishing the record on DLR applications and business cases. This DLR docket is good news for renewable developers because, with AARs and DLRs, there is now a mandate to mitigate costly network upgrades such as transmission line rebuilds.

The top issue for 2022 – interregional transmission

There is an issue brewing in PJM with its queue reform process. While most PJM members and renewable developers have voted in favor of PJM’s queue transition proposal, a comprehensive reform around “Affected Systems” studies is not in the package. At both MISO and SPP, these affected systems studies create a traffic jam for completing the interconnection studies. Hence, FERC needs to step in and clarify how cost allocation works for network upgrades when for example, a MISO project creates a need for a PJM upgrade and vice versa.

A session about transmission reform will be presented at DISTRIBUTECH Connect, set for Dallas, Texas January 25, 2022. Connect is free for qualified utilities! Learn about DISTRIBUTECH Connect here.

This affected systems topic is becoming an issue because SPP queue delays amount to more than 2-3 years in some instances, whereas MISO has delays more than a year even with cluster-based queued reforms. PJM is in the same boat with its queue reform process. But PJM has more renewable demand given its capacity market. Both MISO and SPP have not attempted what PJM is planning during queue transition in the next few years because PJM already has a backlog of 140 GW of study requests. Hence, FERC must step in and fix the cost allocation for interregional transmission since it is the key to unlocking the issue of the affected systems.

Second – Compliance filings for FERC Order 2222

To meet the corporate demand for renewable projects, developers are not looking at utility-scale projects alone. Distributed scale solar and storage projects have an established track record for reliability and affordability, the top concerns for state regulators. FERC has established a framework to work closely with state commissioners on transmission cost allocation.

This same framework can be utilized to address the tricky situations around distribution utility (DU) dispatch override over RTO dispatch override for interconnecting DERs to the transmission grid. The uncertainty comes from not knowing situations that potentially warrant a DU to override RTO day-ahead dispatch in real-time because the aggregator is on the hook to pay penalties for nonperformance at the market operator.

FERC already has both CAISO and NYISO compliance filings for Order 2222. PJM and ISO-NE filings are due in February, and both MISO and SPP filings are due in April. Hence, FERC needs to address this DU dispatch override issue sooner than later because of the safety and reliability concerns expressed by the DUs. The energy aggregators do not want DU to erect barriers for DER entry into wholesale energy markets.

Third issue – State Opt-Out for Demand Response programs

Talking about energy aggregators and the benefits DERs provide to the transmission grid, FERC should tackle the state opt-out issue for DR programs head-on in 2022. States such as Illinois (that allow third-party aggregators) benefit from allowing retail demand response program participation in the wholesale markets. This benefit is why there is no state opt-out for Electric Storage Resource (ESR) in Order 841 and DERs in Order 2222. But the issue is with DR compensation Order 745.

Aggregators need this opt-out provision removed for DR programs to help consumers by bundling different technologies such as DR with ESR and rooftop solar. Otherwise, more DR cannot participate in wholesale markets as the recent FERC annual report shows (Table 3-3) – the ratio of megawatts of demand resources to peak demand is constant 6% year over year at RTOs. This data means we need incentives to enable more DR participation in the wholesale energy markets because RTOs need DR resources to reduce the magnitude of resource shortfalls under emergency conditions. After the California blackout in August 2020, the California Public Utility Commission directed its three investor-owned utilities to procure more demand-side resources for 2021 and 2022.

Conclusion

As the top energy regulator in the US, FERC has an important policy-making role in the energy industry. While FERC’s responsibilities include “Regulation of rates and practices of oil pipeline companies,” reviewing “applications for construction and operation of interstate natural gas pipelines” and hydro plant licensing, the actions outlined above in the RTOs are a must for faster interconnection of renewables to build the future grid.

Rao Konidena, author of this piece, will be speaking in a session on Interconnecting Renewable Sources to The Grid as part of DISTRIBUTECH Connect, set for Dallas, Texas January 25, 2022. Connect is free for qualified utilities! Learn about DISTRIBUTECH Connect here.

Tags