Takeaways From the Commission’s October 6 Technical Conference on Transmission Planning and Cost Management (AD22-8)
The record before us suggests we face a once-in-a-generation need for coordinated regional and interregional transmission investment—to upgrade aging infrastructure, facilitate customer access to new, lower-cost resources, and shore up system reliability. Ensuring sufficient cost management is part and parcel not only of protecting customers but also in ensuring a legitimacy to the review process that will facilitate state regulatory and other stakeholder buy-in to the value of any given project development.
As I noted at the conference, I believe the primary issues we face are twofold: (1) ensuring that projects, from local all the way up to interregional, are optimized for cost efficiency, and (2) ensuring that once projects are selected for development, those costs are prudently incurred.
I heard broad support for the Commission to devote more attention to these issues going forward.
I have three main takeaways from that day:
First, we learned that there is a patchwork approach to considering transmission projects across the country. There are real differences on whether states evaluate need and prudence. For example, it’s worth noting the point made by the Office of Consumers’ Counsel from my home state of Ohio. They explained that more than 75% of the costs of new transmission projects may fall between the cracks of review by either regional or state regulatory authorities. How do we ensure that projects are getting the proper level of vetting before we spend customers’ money?
Second, there is broad support for some form of an Independent Transmission Monitor that could act as an “extra set of eyes,” particularly for states who may not have the resources to take a hard look each time. Participants expressed concern over a lack of access to information and the lack of ability to synthesize and analyze that information when it is available. We need to explore ways to level the information playing field and an ITM is one potential approach. There were several different perspectives shared on what an ITM’s role might look like, especially regarding whether its functions would be purely informational and analytical or also encompass some sort of participation akin to an IMM that exists today. While the areas meriting increased oversight are becoming clearer, the job description for an ITM is still in development. I hope you all will help us out by providing more detail around the responsibilities you think an ITM role should prioritize.
Third, I heard some frustration with how the Commission’s prudence standard has been used to flow costs through to customers. There are various concerns about opportunities for challenging prudence and whether the Commission should consider making any changes.
My hope is that we will be issuing a supplemental notice seeking post technical conference comments. I would like to hear from stakeholders on how the Commission can best maximize efficiency in development without slowing down the process in a manner that could frustrate beneficial projects.
And that last point is really important. While ensuring sufficient cost management is a no less than critical component of a successful system wide transmission build out, we will fail in our responsibility as a Commission if it is designed and implemented in a manner that stymies needed transmission development required for ensuring reliability and access to affordable electricity for customers. That is my focus in the coming months, and I look forward to continued engagement on this issue.
2022-2023 Winter Energy Market and Reliability Assessment
Thanks to Staff for coming today and keeping us focused each year on these reliability issues. As I’ve said before, these assessments are a great compilation of data and free to all stakeholders who don’t have other readily available data sources.
I agree with the Chairman’s takeaways – he had four and I have to go back and read them again because I only had two. I very much agree that we should stop and talk about the progress that has been made just in the last year. I commend the Chairman and Staff for staying on top of the Key Recommendations from the FERC-NERC Joint Inquiry into Winter Storm Uri from November 2021. We are tracking our progress and we do see actions taken on a lot of the recommendations included. I’m also encouraged to see that regions are not just standing by in the wake of that storm—this assessment describes some proactive steps that most regions are taking to increase winter readiness.
I was encouraged by reports on demand response by most of the RTOs—new procurement of 7500 MW or more in each of PJM and MISO, and demand response capacity additions in NYISO, ISO-NE, and CAISO. We’ve already heard the story of the critical role that customer response can play in extreme cold and extreme heat. I think there is more opportunity for systematizing that response. Demand response improvements are just one example of the ways regions continue to adapt to the challenge of unprecedented weather—you’ve heard about a few more. We also have 43 GWs of capacity additions online this year, 68% of which is solar, wind, or battery storage.
That’s all good news. We often focus on the problem, but that’s important too. The second part though, is that this does not mean that it is time to get complacent. As discussed, prices will be high. The FERC regulatory framework—our toolbox—wasn’t designed to get at high prices for this winter with all of these competing factors causing them. As we discussed in New England, we have an opportunity in the medium term to address these issues in a lot of different ways, within the market as much as possible, and outside the market if needed, so we don’t come back to the same starting line at the beginning of every winter.
In addition to the prices, while NOAA predicts average winter conditions for the coming season, the assessment highlights that, of course, the potential for generation shortfalls during extreme weather events does not go away. Across the country, the system hasn’t been planned for the set of extreme weather conditions we’re facing. I agree with Commissioner Danly that we should be getting at the systematic causes that FERC has jurisdiction over related to the challenges that extreme weather presents. And even though preliminary data from NERC indicates that each region has cleared its reserve margin, it’s becoming increasingly clear that traditional reserve margin development fails to fully insulate regions from the severe issues that extreme weather conditions can bring, whether it is fuel unavailability, generator freezing, or other increasingly correlated outages.
While regions are taking good steps, markets should continue to evolve to address changing system needs and risks. Similar to the questions I included in my September statement specific to New England, the issues of resource accreditation, seasonal variation, and performance payments are relevant considerations for regions across the country, not just in New England. It is our responsibility to continue to ask ourselves whether markets are evolving to keep pace with the challenge.
Look, this is a marathon, not a sprint—and each year will bring its continuing challenges. More progress will be made on the joint recommendations. I’m glad to hear that the next phase of Cold Weather Reliability Standards passed their final ballot and will soon be in front of the NERC board. We need to get those in effect as soon as possible and continue working to implement other improvements, including the next phase of standards with all due haste.
And while all that is happening, thank you to our Staff and NERC Staff, and others around the country who have been working to keep our lights on this winter and focusing on the resilience that is needed for our communities.