I concur in today’s Notice of Proposed Rulemaking to emphasize the critical importance of ensuring that the Bulk-Power System is prepared for extreme weather events in both the near-term and long-term. While this NOPR has the potential to reduce the threat to the reliability of the electric system, I note that we must remain vigilant as much work remains to ensure reliable delivery of power to consumers during times of stress and to resolve resilience concerns on the transmission system.
Climate change and extreme weather are, of course, complex issues of enormous importance to the United States. In my view, this NOPR is another step on the path to mitigating the long-term effects of extreme weather; however, I remain concerned about the grid’s near-term reliability, particularly during the upcoming summer and winter seasons. Still, with that in mind, I am voting in favor of issuing this NOPR because it is needed as an incremental improvement to Reliability Standard TPL-001-5.1 (Transmission System Planning Performance Requirements), which I believe currently contains a reliability gap.
The NOPR proposes to direct NERC to modify Reliability Standard TPL-001-5.1 to require the development of benchmark planning cases based on past extreme heat and cold weather events. Currently, Reliability Standard TPL-001-5.1 does not prescribe specific benchmarks, and I believe determining and using the appropriate benchmark will lead to better planning. While extreme weather can be unpredictable, applying a suitable benchmark study should lead to understanding resource availability and load shedding requirements under harsh conditions. Indeed, using benchmarks may also improve interregional coordination when load shedding and cascading outages occur.
The NOPR also proposes to direct NERC to modify Reliability Standard TPL-001-5.1 to require corrective action plans when performance requirements for extreme heat and cold weather events are not met. Currently, the reliability standards require that responsible entities evaluate possible actions to reduce the likelihood or mitigate the consequences of such events. These entities, however, are not obligated to take corrective actions to ensure such failures do not happen again. I believe this NOPR rightly identifies this gap and assures that transmission planners rigorously address uncertainties surrounding extreme weather events in the planning process.
Looking forward, and beyond the important charge we have proposed here, I believe the Commission should next consider further interregional reliability planning reforms. When we issued a NOPR on regional transmission planning and cost allocation in April, I said in my concurrence:
As we continue to examine those issues, I urge the Commission to act expeditiously to propose interregional reliability planning reforms. Looking beyond regional boundaries is important so that cost-efficient regional and interregional projects can be considered and studied together. We should consider whether neighboring regions should adopt common planning assumptions and methods that allow for region-specific inputs. Additionally, I believe we must consider whether to adopt a requirement for a minimum amount of interregional transfer capacity to protect against shortfalls, especially during extreme weather events.
I note we will continue to develop the record in our proceeding on regional transmission planning and cost allocation, and in response to today’s NOPR. We should examine these and other records closely to determine the best course of further action on this ripe issue.
The regional nature of extreme weather highlights the difficulties facing our industry in addressing highly variable risks. The challenges facing California are very different from the challenges facing Texas. I believe a minimum transfer capability requirement is needed, because enhanced transfer capability may be the best way to take advantage of the diversity of energy sources and the many ways in which we can support the grid. Order No. 1000 was intended to encourage more interregional planning and development, but, simply put, interregional projects are not being constructed, and transfer capacity in effect has been limited. Many commenters also point out the importance of adopting a minimum level of interregional transfer capability.
Indeed, Winter Storm Uri highlighted the need for establishing a minimum level of interregional transfer capability. Almost half of the Electric Reliability Council of Texas (ERCOT) was forced out during the storm, which prompted cascading outages in Texas. The Midcontinent Independent System Operator, Inc. (MISO) and the Southwest Power Pool (SPP) also experienced generation loss during the winter storm, but were able to request assistance from each other and from PJM Interconnection, L.L.C. (PJM) through their transmission interconnections. As such, SPP maintained service for most of its load, except for a small portion of its customers over two of its areas. Conversely, ERCOT was unable to avail itself of sufficient mutual assistance during Uri because of its limited transfer capabilities. Therefore, I believe it is important that we consider proposing a minimum level of interregional capacity to aid in times of severe stress. I urge stakeholders to comment on the steps the Commission can take to facilitate a minimum level of interregional transfer capability, and whether there are ways to support existing interregional coordination methods.
I also encourage stakeholders to comment on whether the Commission should require revisions to RTO/ISO generation and transmission outage scheduling practices. Planned generation and transmission outages are critical for facilitating needed equipment maintenance. Failure to perform such maintenance in a timely fashion can lead to increased risks of failure of such facilities, including the potential for unscheduled, forced outages—outages that could negatively affect the reliability of the grid. Therefore, my preference is to develop a further record regarding whether RTOs/ISOs should have wider discretion to coordinate planned outages to make sure all resources and equipment are available at the time of a reliability event, which sometimes can be incredibly hard to predict.
By way of example, not all RTOs/ISOs are able to delay or cancel planned outages for economic reasons, even though the estimated economic impact of the outage could signal a vulnerability to a reliability issue if there is another outage in the same area. Given our growing need to rely on these facilities during the shoulder months, I believe that planned generation and transmission outages could increasingly be a driver of reliability concerns, especially should an extreme weather event occur. Therefore, I urge stakeholders to comment on the provisions in RTO/ISO tariffs regarding the authority to recall or cancel planned outages, and whether those practices ensure that all possible resources can be called upon to assist during extreme weather events. I am also interested in whether rules requiring replacement capacity in the event of extended outages would address these scheduling issues.
Further, I would support a FERC/NERC joint effort to consult with state and local regulators on these complex issues, especially as more states are taking increasingly ambitious actions throughout the country to stem the effects of climate change and extreme weather. I believe it is beneficial to increase coordination with states and state regulators because climate change and extreme weather issues raise difficult challenges that will be novel to all relevant jurisdictions. State and federal regulators must endeavor to pursue reliability solutions that are in accord with one another. In addition, while state and local action is vital to preventing the worst effects of extreme weather, federal leadership is also critical. State regulators may not have visibility into how the Bulk-Power System may respond to reliability events, so greater coordination with federal authorities would allow them to answer local stakeholders as to how the entire system is performing country-wide. I encourage stakeholders to comment on whether and to what extent FERC, NERC, and state and local regulators can better coordinate on extreme weather reliability matters.
Finally, I note that this NOPR is not set in stone and only asks for comments in response to proposed directives to NERC. There is much good in this NOPR, and there is much more work to be done. I look forward to examining all the comments as we seek to issue a final rule around these topics.
 Transmission System Planning Performance Requirements for Extreme Weather, 179 FERC ¶ 61,195 (2022) (NOPR).
 On August 24, 2021, the Commission approved revised Reliability Standards to address certain reliability risks posed by extreme cold weather. Cold Weather Reliability Standards, 176 FERC ¶ 61,119, at P 1 (2021).
 To its credit, in the wake of Winter Storm Uri, the North Electric Reliability Corporation (NERC) issued a level 2 NERC Alert to industry on cold weather preparations for extreme weather events, which acknowledged the reliability risks associated with more frequent extreme weather conditions. NERC, Alert R-2021-08-18-01 Extreme Cold Weather Events (Aug. 18, 2021) (“The recent extreme cold weather events across large portions of North America have highlighted the need to assess current operating practices and identify some recommended improvements, so that system operations personnel are better prepared to address these challenges. The events have caused major interruptions to resources, transmission paths and ultimately, end-use customers.”).
 NOPR at PP 51-56.
 See infra at PP 6-8.
 NOPR at PP 6, 83.
 Id. at P 83 (“[P]lanning coordinators and transmission planners are required to evaluate possible actions to reduce the likelihood or mitigate the consequences of extreme events but are not obligated to developed corrective action plans. Specifically, if such events are found to cause cascading outages, they need only be evaluated for possible actions designed to reduce their likelihood or mitigate their consequences and adverse impacts [citation removed]. Accordingly, because of their potential severity, we believe that extreme heat and cold weather events should require evaluation and the development and implementation of corrective action plans to help protect against system instability, uncontrolled separation, or cascading failures as a result of a sudden disturbance or unanticipated failure of system elements.”).
 Building for the Future through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 179 FERC ¶ 61,028 (2022) (Phillips, Comm’r, concurring, at P 7).
 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 136 FERC ¶ 61,051 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132 (2012), order on reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff’d sub nom. D.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).
 See Americans for a Clean Energy Grid, Planning for the Future: FERC’s Opportunity to Spur More Cost-Effective Transmission Infrastructure, https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf (“For all of the best efforts of the Commission and regional planning authorities, the current set of transmission regulations have resulted in inadequate levels of infrastructure that have burdened the interconnection process with the task of planning new network facilities – a task that should instead take place in the planning process. Further, existing regulations have created a system that disproportionally yields projects that address only local needs, that address reliability without more broadly assessing other benefits, or that simply replace old retiring transmission assets with the same type and design despite the potential for larger projects to more cost effectively meet the same needs.”).
 See, e.g., AEP Post-Conference Comments, Docket No. AD21-13-000, at 8-12 (filed Sept. 27, 2021) (“The need for regions to assist each other in extreme weather events has become more frequent over the past decade, thus highlighting the value, and limitations, of current interregional transmission capabilities.”); Michigan Public Service Commission Post-Conference Comments, Docket No. AD21-13-000, at 12-13 (filed Sept. 24, 2021) (stating that it supports improving existing interregional coordination methods, such as a target level of interregional transfer capacity a target level of regional transfer capacity, to prepare for extreme weather events); PJM Interconnection, L.LC. Post-Conference Comments, Docket No. AD21-13-000, at 19-20 (filed Sept. 27, 2021) (stating that a DOE National Labs study can identify transfer metrics to evaluate an appropriate level of import/export capability by balancing authority in terms of percentage of load); Public Interest Organizations Post-Conference Comments, Docket No. AD21-13-000, at 22-23 (filed Sept. 27, 2021) (discussing different methodologies for achieving a minimum level of interregional transfer capacity).
 See Testimony of James Robb, NERC President and Chief Executive Officer, before the Subcommittee on Oversight and Investigations Committee on Energy and Commerce, United States House of Representatives, “Power Struggle: Examining the 2021 Texas Grid Failure,” Mar. 24, 2021, https://energycommerce.house.gov/sites/democrats.energycommerce.house.gov/files/documents/Witness%20Testimony_Robb_OI_2021.03.24.pdf.
 FERC-NERC Regional Entity Staff Report, The February 2021 Cold Weather Outages in Texas, and the South-Central United States, at 14, 66, 127, 141, 167 (Nov. 2021) (2021 Cold Weather Report).
 2021 Cold Weather Report at 10-11.
 2021 Cold Weather Report at 183 (“ERCOT, unlike MISO and SPP, … did not have the ability to import many thousands of MW from the Eastern Interconnection, and thus needed to shed the greatest quantity of firm load to balance electricity demands with the generating units that were able to remain online.”).
 See Eversource Post-Conference Comments, Docket No. AD21-13-000, at 5 (filed Sept. 27, 2021) (“As noted by the Commission, ISO-NE already has the ability to deny outages based on economic impact.”); but see MISO Post-Conference Comments, Docket No. AD21-13-000, at 19 (filed Sept. 27, 2021) (explaining that when reliability concerns are present, MISO works with generators to explore rescheduling outages).
 See, e.g., PJM Pre-Conference Comments, Docket No. AD21-13-000, at 9 (filed Apr. 15, 2021) (explaining that coordination with states on climate change and extreme weather events is of utmost importance in the role of retail regulators and other federal agencies); Speaker Materials of Devin Hartman, R Street Institute, at the Technical Conference to Discuss Climate Change, Extreme Weather and Electric System Reliability, Docket No. AD21-13-000, at 1 (filed June 3, 2021) (discussing many reliability deficiencies, which include disjointed state-federal coordination and siloed reliability institutions); see also Motion to Intervene and Comments of the National Association of Regulatory Utility Commissioners, Docket No. AD21-13-000, at 2 (filed Apr. 15, 2021) (“The Commission most certainly should confer with the states . . . where climate change and extreme weather events may implicate both federal and state issues.”).
 See Technical Conference Tr., June 2, 2021, Docket No. AD21-13-000, at 130-131:1-25 (Letha Tawney) (“I would ask FERC to think of the state regulators in our role, in our states, as sort of the face of electricity and natural gas . . . [W]e don’t have good visibility into how the bulk system is going to respond . . . And without good visibility into how the transmission system is adopting to these risks, [then we are] in a difficult position with our local stakeholders.”).
 For instance, Commissioner Clements is right in pointing out that we must also take a close look at existing resource adequacy mechanisms and ancillary service markets. See NOPR (Clements, comm’r, concurring) at PP 26-27.