Docket No. RM22-10-000
Today’s Notice of Proposed Rulemaking (NOPR) is an important step to ensure that the North American Electric Reliability Corporation (NERC) builds upon existing practices to better account for extreme weather in transmission system planning. Together with the Notice of Proposed Rulemaking proposing to direct transmission providers to submit informational reports describing their current or planned policies and processes for conducting extreme weather vulnerability assessments,[1] it will facilitate steps to enhance the reliability of the electric system.
NERC already addresses extreme weather in several ways. For example, Reliability Standard TPL-001-4 requires planning coordinators and transmission planners to conduct an analysis of extreme weather events and evaluate potential actions for reducing the likelihood or mitigating the consequences of the event creating adverse impacts.[2] NERC also recently adopted Cold Weather Reliability Standards, which require generators to prepare and implement plans for cold weather, and require the exchange of information between the balancing authority, transmission operator, and reliability coordinator about the generator’s ability to operate under cold weather conditions to ensure grid reliability.[3] Further, NERC has prioritized improving bulk electric system resilience to wide-spread long-term extreme temperature events in its 2022 Enterprise Work Plan,[4] and is pursuing enhancements to reliability standards for the operational planning timeframe to address extreme weather via its Energy Reliability Assessment Task Force.[5] Yet even with these actions, utilities and grid operators remain underprepared for the changing climate and the increasing frequency of extreme weather it is bringing, as is evident in NERC’s 2022 Summer Reliability Assessment. Therein, NERC highlights the elevated risk of an energy emergency due to the increased demand for electricity driven by above average temperatures combined with a reduced capacity because extreme drought conditions threaten the availability of hydroelectric energy for transfer.[6] Had the nation’s utilities and grid operators better planned for climate change and the attendant increased likelihood of these conditions, they would be better prepared for the conditions we are likely to face this summer.
There is no more urgent priority for this Commission than to reform system planning so that it sufficiently contemplates and provides mechanisms to address the impact of extreme weather events on the electricity grid. Across geographies, regulatory regimes, regional resource mixes and market designs, the impact of extreme weather has vastly outpaced regulatory adaptation to it. So, I am glad to support this priority by voting for today’s NOPR, which complements NERC’s ongoing efforts to address the operational time frame and fills a gap by ensuring that Reliability Standards better account for extreme weather in planning. I write separately for two reasons.
First, while it represents an important step in tackling extreme weather’s myriad impacts on the transmission system, strong follow through from NERC will be required to ensure a reliability standard that addresses extreme weather reliability challenges in a comprehensive and cost-effective manner. While the proposed rule seeks comments on whether drought should be included along with extreme heat and cold weather events within the scope of Reliability Standard TPL-001-5.1, I believe that what we already know about meteorological projections and drought’s anticipated impacts on the electricity system compel the development of drought benchmark events in applicable regions of the country.[7] The question for me is not whether such events should be included, but how TPL-001-5.1 should cover the impact of drought induced reductions in supply on regions already experiencing unprecedented reductions in reservoir supply and increased wildfire risk. Further, NERC can facilitate cost effective implementation of these reliability standard modifications by requiring modeling of extreme weather events according to consistent planning rules, providing for consultation with states and other regulators in the development of corrective actions plans, and by considering of the interaction between this proposed Reliability Standard and related planning processes and rules, including the Commission’s recently issued notice of proposed rulemaking regarding long-term regional transmission planning.[8] I urge stakeholders to provide recommendations to NERC as to how best to account for these considerations in commenting on this proposal.
Second, it is important to note that if we are to cost-effectively ensure system reliability as the frequency and intensity of extreme weather events continues to increase, further action is necessary to complement today’s initial proposal. We have learned a good amount about the impact of extreme weather on the electricity system the hard way.[9] We have the opportunity to learn a great deal more from the substantial amount of important information and good ideas that stakeholders submitted in response to the Commission’s inquiry into Climate Change, Extreme Weather, and Electric System Reliability in Docket No. AD21-13.
Themes that emerge from this collective experience and record include, at least, the need to consider: (1) establishing a process for setting explicit minimum interregional transfer capability requirements or otherwise identifying least regrets interregional solutions, (2) improved scheduling and coordination in non-RTO regions, and (3) ensuring that planning and market mechanisms appropriately reflect resource availability during extreme weather events, accounting for the possibility of common mode failures or other correlated outages.[10] As I provide in more detail below, I urge my colleagues to prioritize these complementary issues in the months to come.
Ensuring cost-effective implementation of this NOPR
The effectiveness of this NOPR depends upon NERC implementing it in a manner that comprehensively addresses extreme weather threats, provides for consistency in modeling scenarios and methods to the greatest extent possible, facilitates consultation with state regulators, and appreciates its interrelation with the Commission’s Regional Planning NOPR. I urge NERC and stakeholders to provide feedback on the following issues, which may facilitate strengthening the effectiveness of the eventual reliability standard.
Initially, in addition to benchmark cases for extreme heat and cold, it seems prudent to include drought within the scope of Reliability Standard TPL-001-5.1. It is not surprising that, as noted in comments in the extreme weather docket, the more frequent and severe droughts occurring and expected to worsen in parts of the West and Southwest portend potentially significant grid impacts via limitations on hydroelectric generating facilities as well as thermal facilities that require water for cooling.[11] These drought conditions also, of course, serve as a main driver of what the Oregon Public Utility Commission describes as “one of the most pressing and difficult issues: the rapidly increasing risk of highly destructive wildfires.”[12] While the need to consider a drought benchmark case does not currently arise in all regions of the country, failure to contemplate the impacts of drought in relevant regions as part of equipping transmission planning to effectively address extreme weather would hamper a final Reliability Standard’s impact.
Further, I am pleased to see the proposal’s emphasis that “it is important that transmission planners and planning coordinators likely to be impacted by the same types of extreme weather events use consistent benchmark events.”[13] I urge NERC and stakeholders to contemplate the benefits of consistent modeling practices and modeling assumptions, and to provide feedback on how such consistency can best be achieved within the scope of this proposed rule.[14] Consistency in the inputs and assumptions feeding these cases and scenarios will allow for neighboring transmission planners and planning coordinators to work together towards cost-effective corrective actions, like increasing transfer capability, that could otherwise be missed for lack of apples-to-apples comparisons.
In addition, I encourage NERC to set forth a process that provides for consultation with states in the development of corrective action plans, given that many components of such plans could be state jurisdictional. As we see in other contexts, states’ jurisdiction over their resource mix and the Federal Power Act’s separation of authority between FERC and states means that consideration of some of the more cost-effective options for corrective actions, including reducing demand through energy efficiency and other demand side resource development, cannot be properly facilitated without state partnership.[15] States’ decisions regarding the siting of generation and transmission facilities may also be impacted by extreme weather.[16] Consulting with states will both ensure that opportunities for addressing reliability changes with state-jurisdictional solutions are not missed, and provide a path to regulatory approval of such solutions in a manner that ensures both FERC and state regulators are informed of the costs and benefits of different corrective actions.[17] High-level coordination would also allow for harmony between the extreme weather modeling methods of states and those of NERC, such as “referring to an agreed set of climate modeling parameters or scenarios,” where appropriate in developing their own solutions.[18]
Further, in considering how to address the aims of this proposal cost effectively, it is important for NERC and stakeholders to consider how this proposal to reform TPL-001-5.1 may interact with the Commission’s notice of proposed rulemaking on regional transmission planning and cost allocation.[19] That NOPR proposes to require transmission planners to engage in probabilistic, scenario-based planning for longer-term system needs, including at least one extreme weather scenario, but exempts shorter-term reliability planning from this scenario planning requirement. Since efficiencies are gained when considering multiple drivers for new transmission investment and it is likely that some amount of the corrective action that may emerge from the new reliability standard involves regional or interregional transmission development, it is important to derive stakeholders’ perspectives on how potential performance standards and corrective actions under a revised reliability standard interact with both shorter-term reliability and proposed longer term planning, both in terms of consistency in planning inputs and the selection of cost-effective solutions. For instance, processes may be established to prioritize finding solutions via long-term planning in the first instance wherever possible, or to incorporate multiple drivers and probabilistic benefit cost assessments into the reliability planning process, so as to leverage the benefits of multi-value planning.
Need for further actions to ensure system reliability
The Commission developed a robust record in response to the Commission’s technical conference on climate change, extreme weather, and electric system reliability, and the Commission’s technical conference to discuss resource adequacy developments in the Western Interconnection.[20] Today’s NOPR will facilitate better planning for extreme weather events, but the record in those dockets, as well as in the Commission’s inquiry into potential improvements in transmission system planning,[21] suggests action is necessary on several fronts to better facilitate cost-effective solutions. It is important to highlight three areas for which further inquiry is merited:[22] (1) increasing interregional transfer capability; (2) improving transmission scheduling and coordination in non-RTO regions; and (3) ensuring that planning and market mechanisms properly reflect resource availability during extreme weather events, accounting for the possibility of common mode failures or other correlated outages.
Increasing interregional transfer capability
Numerous commenters have highlighted that interregional transfer capability renders the grid more resilient to extreme weather events.[23] As a recent report from The Brattle Group summarizes, “[n]umerous studies have confirmed the significant benefits of expanding interregional transmission in North America, demonstrating that building new interregional transmission projects can lower overall costs, help diversify and integrate renewable resources more cost effectively, and reduce the risk of high-cost outcomes and power outages during extreme weather events.”[24]
Yet Eversource Energy observes that “[d]espite numerous studies suggesting the importance of increased interregional ties, most planning regions do not currently perform regular studies to assess whether increased interregional transmission capability could increase reliability during severe weather events.”[25] This gap in planning, along with many other barriers to constructing interregional transfer capability,[26] threatens to dissuade transmission planners and planning coordinators from pursuing enhanced interregional transfer capability as a corrective action strategy, even where it is the most effective solution for customers.
As highlighted in section A above, consistent benchmark cases, scenarios, and other modeling practices will help to facilitate transmission planners and planning coordinators’ pursuit of shared solutions, such as enhanced interregional transfer capability. Yet even with a common framework, coordination between regions is likely to prove challenging. Setting a minimum level of transfer capability could provide a unified planning goal for neighboring regions and thereby ameliorate this planning challenge.[27] American Electric Power (AEP) recommends that “a minimum interregional transfer capability should be established through a thorough risk assessment on a nationwide, and region to region basis, using sensitivity analyses on the frequency of extreme weather events, projections of climate change impacts, and project retirements, constraints, and load changes over various timelines.”[28] A capability requirement might vary, for instance, according to a region’s generation mix, load, weather, and correlation with neighboring regions across these various attributes, and would protect system reliability by “provid[ing] the ability to access additional generation in the event local (or even regional) generation is unable to serve customers or maintain reliability.”[29]
A process for setting interregional transfer capability requirements could address a gap in existing regulation. As AEP argues, “[b]ecause the current process evaluates transfer capability on a regional, or balancing authority-specific basis,” it does not capture “the efficiencies” of connections “between the regions.”[30] “[F]ailure to evaluate the grid as a whole makes the grid more susceptible to . . . the impacts of increasingly extreme weather events that impact large geographic areas,” rendering “the overall resilience and reliability the transmission grid less robust than it could be.”[31]
As this discussion suggests, both section 215 and section 206 of the Federal Power Act are implicated by the development of interregional transfer capability. I urge stakeholders and this Commission to further explore whether section 215, section 206, or a combination thereof may serve as the basis for establishing specific minimum interregional transfer capability requirements or otherwise establishing least regrets interregional planning targets.
Improving transmission scheduling and coordination in non-RTO regions
Enhanced transmission scheduling and coordination between balancing area authorities—in particular, RTO-to-non-RTO and non-RTO-to-non-RTO coordination—would improve grid reliability during extreme weather events, lower costs for customers, and level the regulatory playing field between RTO and non-RTO regions. Transmission scheduling and coordination can potentially be improved both via mandating a transition to flowgate methodology for determining transmission capacity in areas that continue to use path-based methodologies, and via facilitation of economic redispatch and narrowing the circumstances under which transmission curtailment procedures are permissible.
As leading electricity market economists have observed, “in an electricity network, power flows along parallel paths dictated by physical laws rather than the contract path, creating widespread externalities whose complexity grows with network size.”[32] Without “an appropriate mechanism to allocate transmission capacity” according to true flow, market participants “are unlikely to take into consideration the effects of power flows that diverge from the contract path.”[33] Despite the efficiencies of a flow-based method, however, the Reliability Standards continue to permit entities to choose either a path-based or a flow-based method of transmission method,[34] with most entities in the Western Interconnection continuing to use the less efficient path-based method.[35]
Arizona Public Service and Public Service Company of Colorado argue that “the path based approach results in less efficient transmission system use and could hamper the contracting and delivery of capacity resources across the Western Interconnection.”[36] By contrast, “a flow-based methodology, through its more realistic assessment of impacts to the entirety of the transmission system, in general enables greater utilization of the system as a whole.”[37] As the West faces increased frequency and duration of extreme weather events, achieving maximum reliability value from all existing infrastructure is imperative.[38] This raises the question whether the Reliability Standards should require all applicable entities to transition to a flow-based methodology.
Beyond ensuring that transmission capacity is measured and scheduled in a manner that better matches the reality of the system, the Commission should explore complementary action to improve the ability of non-RTO system operators to provide transmission service when the grid is constrained. Transmission Loading Relief (TLR) procedures and Qualified Path Unscheduled Flow Relief (USF) procedures, the default methods of managing transmission congestion between balancing areas outside of RTO/ISO markets, are blunt instruments that in some cases fail to facilitate power transfers that would aid system reliability during extreme weather, and in other cases impose higher overall costs than appropriate redispatch of generation. As MISO highlights in its post-technical conference comments in Docket No. AD21-13, TLR fails to “assure reliable service” because it “reli[es] on curtailment of interchange transactions.”[39] TLR and USF procedures curtail transactions in a pre-set priority order, without locational marginal pricing or another adequate mechanism to guide them toward redispatching generation to facilitate optimal transmission flows. By contrast, economic “[r]edispatch offers a way, in the vast majority of circumstances, to ensure that all transactions continue to be served despite transmission congestion.”[40] RTO and ISOs generally utilize TLRs to mitigate an overload only where they have “exhausted all other means available, short of load shedding.”[41]
While the existing pro-forma Open Access Transmission Tariff (OATT) currently permits a transmission provider to use redispatch to maintain reliability during transmission constraints,[42] David Patton of Potomac Economics, the independent market monitor for NYISO, MISO, ISO-NE, and ERCOT, testified at the extreme weather technical conference that he was “unaware in non-market areas of any redispatch that’s actually being provided in order to supply transmission service.”[43] The Commission should investigate how it may be able to facilitate economic redispatch in non-RTOs and reduce usage of TLRs and USFs in these areas. I am not aware of any systematic examination of the magnitude of potential benefits to improved coordination practices, but they are likely significant. During winter storm Uri, sophisticated RTO transmission scheduling practices facilitated the flow of between 10,000 and 14,000 MW from PJM to support operations in MISO and beyond.[44] Yet the use of such practices is not universal. TLRs were invoked on average over 200 times per year in the Eastern Interconnection across the past four years.[45] Public data for USFs, used across the Western Interconnection where economic redispatch is less prevalent, is not available.
I encourage non-RTO system operators to take action to improve their transmission scheduling practices, to highlight for the Commission challenges that they face in doing so, and to identify potential solutions to those challenges. Absent voluntary improvements by non-RTO system operators, I believe it would be appropriate for the Commission to consider requiring changes to the pro forma OATT to mandate transmission scheduling improvements. As MISO argues, “greater grid connectedness that has developed since Order No. 890, emerging reliability needs not met by the status quo, including the TLR process, and the inflexibility of the TLR process in responding to extreme weather . . . have potentially created conditions that may make the lack of reliability redispatch to bordering utilities potentially unjust and unreasonable.”[46]
While some commenters endorsed the general idea of improving transmission scheduling practices,[47] MISO was the only entity to provide detailed recommendations and factual support for doing so.[48] MISO provides several suggestions to the Commission, including (1) encouraging seams agreements that require non-RTOs/ISOs to compensate RTOs/ISOs for redispatch provided through market flows and for RTOs/ISOs to compensate non-RTOs/ISOs for reliability redispatch, when the market flows or the reliability redispatch are the more economical solution to a congestion problem at their seam, (2) allowing an RTO/ISO to file a presumptively just and reasonable unexecuted joint operating agreement or other agreement incorporating such redispatch provisions in cases where an RTO/ISO cannot reach agreement with a neighboring non-RTO/ISO transmission provider on joint redispatch,[49] (3) clarifying that the reliability redispatch provided under OATT section 33.2 is available sub-hourly,[50] and (4) modifying OATT section 33.2 to permit redispatch not just by network resources of the transmission provider and its network transmission customers, but also from other generators including merchants.[51] It also more broadly recommends “[m]odifying the pro forma OATT to require least cost dispatch of a transmission provider’s resources and to require network resources to manage seam congestion” such “that, in addition to requiring reliability redispatch when feasible to relieve constraints within the transmission provider’s own system, the transmission provider is also required to provide such service to each of its directly-connected public utility neighbors (or non-jurisdictional transmission providers that provide reliability redispatch) prior to implementing TLR procedures.”[52]
These recommendations warrant serious consideration. A more robust record is necessary to examine these ideas and other potential actions to improve transmission system scheduling, management, and coordination. I encourage stakeholders to bring forth proposals to the Commission on this topic, and to provide comments and information pertinent to the ideas discussed herein. I further recommend that the Commission take action to gather more information on these issues, such as by issuing a notice of inquiry, an order directing reports from NERC and the relevant Balancing Authorities, or a combination thereof, in order to gather more information on the use of path based management as well as USFs and TLRs,[53] the potential benefits of improved transmission scheduling, management, and coordination practices, and how such improvements could be achieved. Such proceedings could gather data on the extent to which additional transmission capacity could be freed up via a transition to flowgate methodologies, and the extent to which TLR and USF procedures are unnecessarily curtailing transmission that could have otherwise been facilitated by economic redispatch. They could also examine how non-RTO market operators could implement economic redispatch in the absence of organized markets setting locational marginal prices.
Properly accounting for resource availability during extreme weather
As many commenters stressed in response to the Commission’s technical conference examining extreme weather, another pressing issue is the need to ensure that planning procedures, resource adequacy mechanisms, and reserves markets appropriately reflect the availability of resources during extreme weather events, properly accounting for common mode outages or other correlated outages.[54]
Resource adequacy methodologies, in particular, are an area where accurately assessing anticipated availability of resources is critical so as to ensure that applicable planning and market design achieves the desired target level of system reliability. Commenters at the extreme weather technical conference generally agreed that existing methods are outdated and do not appropriately reflect extreme weather.[55] Failure to appropriately account for resource availability jeopardizes the reliability of grid systems in extreme weather, so doing the hard work of updating these methodologies is an urgent concern.
NYISO and PJM have made significant strides recently in establishing processes to ensure that their capacity markets better account for correlated availability of resources,[56] but more work is needed to implement these mechanisms, and to ensure that they are fairly assessing the contributions of different resource types. While NYISO’s approved proposal explicitly contemplates extending this methodology to all resource types (albeit while providing very limited detail on how it will do so),[57] PJM’s approved method is confined to wind, solar, storage, and hybrid resources.[58] ISO-NE’s external market monitor has argued that applying ELCC to thermal resources would better reflect their value.[59]
Further inquiry is necessary to investigate appropriate methodologies for accounting for correlated outages of resources during extreme weather, including common mode outages related to unavailable fuel supply such as gas-fired resources without fuel during winter events or hydro-electric resources experiencing drought conditions, and correlated de-rates that may occur in relation to extreme weather such as difficulty cooling thermal facilities. I urge stakeholders, grid operators, and my colleagues at the Commission to work expeditiously to address these questions and facilitate appropriate market reforms.
Conclusion
As the Extreme Weather NOPR highlights, climate change poses a severe reliability threat to the bulk electric system. Addressing that threat is a multi-faceted challenge posing complex issues for which there is no single answer. However, if implemented in a comprehensive and cost-effective manner, today’s NOPR promises to be an important and prudent step forward in protecting customers against the effects of extreme weather. By taking complementary actions in the future that build on this step, the Commission will continue to fulfill its responsibility of ensuring bulk electric system reliability.
For these reasons, I respectfully concur.
[1] One Time Informational Reports on Extreme Weather Vulnerability Assessments, 179 FERC ¶ 61,196 (2022).
[2] Reliability Standard TPL-001-4; see also Notice of Proposed Rulemaking, Transmission System Planning Performance Requirements for Extreme Weather (Extreme Weather NOPR), 179 FERC ¶ 61,195, at PP 20-23 (2022) (discussing the requirements set forth in TPL-001-4).
[3] See Extreme Weather NOPR at PP 18-19 (discussing Cold Weather Reliability Standards, 176 FERC ¶ 61,119, at PP 1, 3 (2021)).
[4] See NERC, 2022 ERO Enterprise Work Plan Priorities, at 3 (Nov. 4, 2021), available at nerc.com/AboutNERC/StrategicDocuments/ERO_2022_Work_Plan_
Priorities_Board_Approved_Nov_4_2021.pdf.
[5] See NERC, DRAFT Energy Management Recommendations for Long Duration Extreme Winter and Summer Conditions, available at https://www.nerc.com/
comm/RSTC/ERATF/Combined-Energy-Management-Roadmap.pdf (last accessed June 15, 2022).
[6] NERC, 2022 Summer Reliability Assessment, at 7, 9 (May 2022), available at https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_SRA_2022.pdf.
[7] See Extreme Weather NOPR at PP 90-92 (discussing the anticipated impacts of drought on the electricity system); infra P 8.
[8] Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 179 FERC ¶ 61,028 (2022) (Regional Planning NOPR).
[9] Severe weather events have caused significant outages in the past decade. See NOPR at P 26 (discussing February 2011 Southwest Cold Weather Event where low temperatures caused uncontrolled blackouts throughout ERCOT’s entire region, effecting 4.4 million electric customers), P 28 (discussing January 2014 Polar Vortex Cold Weather Event where increased demand for gas and the unavailability of gas-fired generation led to 35,000 MW of generator outages, and PP 31-32 (describing how the 2021 Cold Weather Event brought the largest controlled load shed in U.S. history, with more than 4.5 million people losing power, resulting in at least 210 people dying).
[10] While this statement highlights key priority areas for further inquiry, it is not intended to be exclusive. For instance, while I do not discuss it in detail here, I support Commissioner Phillips’ call for an examination of whether the Commission should require revisions to RTO/ISO generation and transmission outage scheduling practices. See Extreme Weather NOPR (Phillips, Comm’r, concurring) at PP 8-9.
[11] See, e.g., Comments of Environmental Defense Fund and Columbia Law School Sabin Center for Climate Change Law, Docket No. AD21-13, at 3 (filed Sept. 27, 2021) (“[C]hanges to the availability of water for cooling at thermal power plants and for hydroelectric generation will depart from historical patterns.”); Comments of the California Independent System Operator, Docket No. AD21-13 at 3 (filed April 15, 2021) (noting that drought already “has affected the availability of hydroelectric facilitates in some years”).
[12] Comments of the Oregon Public Utility Commission, Docket No. AD21-13, at 2 (filed Apr. 14, 2021).
[13] Extreme Weather NOPR at P 52.
[14] See Comments of the Institute for Policy Integrity Docket No. AD21-13, at 8 (filed Apr. 14, 2021) (emphasizing potential benefits of consistent modeling practices); see also Pre-Technical Conference Comments of Exelon Corporation Docket No. AD21-13, at 14 (filed Apr. 15, 2021) (suggesting a process by which regulators and experts could “define a reasonable range of scenarios describing potential climate-change related weather events and longer-term climate patters over the coming decades”).
[15] See Comments of PJM Interconnection, L.L.C. Docket No. AD21-13, at 9 (filed Apr. 15, 2021) (“[C]oordination with states (including state permitting agencies) on climate change and extreme weather events [is] critical.”); Comments of the R Street Institute Docket No. AD21-13, at 15 (filed Apr. 15, 2021) (“It is imperative for future reliability policy to harmonize the actions of federal and state authorities, at least to a basic degree.”); see also Motion to Intervene and Comments of the National Association of Regulatory Utility Commissioners Docket No. AD21-13, at 2 (filed Apr. 14, 2021) (urging the Commission to confer with the states “where climate change and extreme weather events may implicate both federal and state issues”).
[16] See Comments of the National Rural Electric Cooperative Association Docket No. AD21-13, at 13 (filed Apr. 15, 2021). See also id. (“Most of the necessary decision-making and policy-making” with regard to extreme weather “will be at state and local levels.”).
[17] See Comments of the Institute for Policy Integrity, Docket No. AD21-13, at 8 (filed Apr. 14, 2021) (coordination would “facilitat[e] state efforts to encourage development of flexible resources”).
[18] Id.
[19] Regional Planning NOPR, 179 FERC ¶ 61,028.
[20] See Docket Nos. AD21-13 and AD21-14.
[21] See Docket No RM21-17.
[22] While this statement highlights key priority areas for further inquiry, it is not intended to be exclusive. See supra n. 10.
[23] See Post-Conference Comments of American Electric Power, Docket No. AD21-13, at 8 (filed Sept. 27, 2021) (arguing that increased interregional transfer capability is “an important component of meeting the challenges” extreme weather poses for the system); Post-Conference Comments of Midcontinent Independent System Operator Inc., Docket No. AD21-13, at 23 (filed Sept. 27, 2021) (finding interregional transfer capacity improves the resilience of the power system); Comments of Americans for a Clean Energy Grid, Docket No. AD21-11 (filed Feb. 22, 2022), Attachment 1: Grid Strategies LLC, Fleetwide Failures: How Interregional Transmission Tends to Keep the Lights On When There is a Loss of Generation (Nov. 2021), Attachment 2: Grid Strategies LLC, Transmission Makes the Power System Resilient to Extreme Weather (July 2021), Attachment 3: Grid Strategies, LLC, The One-Year Anniversary of Winter Storm Uri, Lessons learned and the Continuing Need for Large-Scale Transmission (Feb. 13, 2022), Attachment 4: General Electric International, Inc., Potential Customer Benefits of Interregional Transmission (Nov. 29, 2021), and Attachment 5: Pfeifenberger et al., A Roadmap to Improved Interregional Transmission Planning (Nov. 30, 2021); Initial Comments of PJM Interconnection, L.L.C., Docket No. RM21-17, at 72-73 (filed Oct. 12, 2021) (“Greater interregional transfer capability has a significant reliability benefit for both adjoining regions as demonstrated . . . by the February 2021 Cold Snap and the 2014 Polar Vortex.”) (emphasis omitted).
[24] Pfeifenberger et al., A Roadmap to Improved Interregional Transmission Planning (Nov. 30, 2021) at iii, available at https://www.brattle.com/wp-content/uploads/2021/11/A-Roadmap-to-Improved-Interregional-Transmission-Planning_V4.pdf; see also id. at 2, Table 1, Summary of Select Recent Interregional Transmission Studies.
[25] Post-Conference Comments of Eversource Energy, Docket No. AD21-13, at 6-7 (filed Sept. 27, 2021).
[26] See Pfeifenberger et al. at 4-5 (summarizing barriers to interregional transmission planning and development).
[27] See, e.g., Post-Conference Comments of PJM Interconnection, L.L.C., Docket No. AD21-13, at 19-20 (filed Apr. 15, 2021) (noting that a “national standard or recommended planning driver for bi-directional transfer capability” would facilitate “interregional coordination”).
[28] Post-Conference Comments of American Electric Power, Docket No. AD21-13, at 10 (filed Sept. 27, 2021).
[29] Id. at 9-10.
[30] Id. at 9.
[31] Id.
[32] Chao et al., Flow-based Transmission Rights and Congestion Management, Electricity Journal at 39 (2000), available at https://oren.ieor.berkeley.edu/pubs/
flowbase.pdf.
[33] Id.
[34] NERC Reliability Standard MOD-29 sets forth requirements for path-based transmission management, while Reliability Standard MOD-30 sets forth the requirements for a flow-based method.
[35] See Joint Comments of Arizona Public Service Company and Public Service Company of Colorado, Docket No. AD21-14, at 5-6 (filed Jan. 31, 2022).
[36] Id. at 5.
[37] Id. at 6.
[38] See Technical Conference Tr., June 24, 2021, Docket No. AD21-14-000, at 301:14 (Chairman Glick: “I’m wondering if there are things we can do in the near term . . . that would help facilitate and improve [the] resource adequacy situation or at least improve [the] reliability situation.”); 307:2 (Amanda Ormond, in response: “I want to just talk about efficiency of the existing transmission system because we certainly need to get more out of what we have, and Alice Jackson from [X]cel mentioned the flow-based [methodology] as you did. I think that’s really important that we move to a flow[-based methodology] because [that would facilitate] know[ing] more about what’s on the system where.”).
[39] Post-Conference Comments of Midcontinent Independent System Operator, Docket No. AD21-13, at 10 (filed Sept. 27, 2021).
[40] Id.
[41] See, e.g., PJM Manual 37, Reliability Coordination § 4.1; Southwest Power Pool, Congestion Management & Communication Processes, 5, 12-13 (2013).
[42] See pro forma OATT § 33.2 (providing that network and native load resources will be redispatched without regard to ownership on a least cost basis to provide the amount of congestion relief assigned to all network and native load customers, and that the costs of such redispatch will be allocated on a load ratio share basis).
[43] See Technical Conference Tr., June 2, 2021, Docket No. AD21-13-000, at 67:21-23 (filed July 22, 2021).
[44] See Technical Conference Tr., Docket No. AD21-13, at 64:5-7 (Renuka Chatterjee) (filed July 22, 2021) (stating that PJM sent 10,000 to 14,000 MW to MISO and areas west of MISO during the February event).
[45] See NERC, TLR Logs, available at https://www.nerc.com/pa/rrm/TLR/Pages/
TLR-Logs.aspx (last accessed June 14, 2022).
[46] Post-Conference Comments of Midcontinent Independent System Operator, Docket No. AD21-13, at 11 (filed Sept. 27, 2021).
[47] See, e.g., Post-Conference Comments of Natural Resources Defense Council, Sierra Club, Sustainable FERC Project, and Union of Concerned Scientists, Docket No. AD21-13, at 13 (filed Sept. 27, 2017) (arguing that improved coordination of exports and imports between RTOs/ISOs and non-RTO/ISO regions will enhance system resilience); Post-Conference Comments of the Michigan Public Service Commission, Docket No. AD21-13, at 10 (filed Sept. 24, 2021) (strongly supporting improved coordination and management at market seams).
[48] See Post-Conference Comments of Midcontinent Independent System Operator, Docket No. AD21-13, at 10 (filed Sept. 27, 2021).
[49] Id. at 9, 14-15.
[50] Id. at 11-12.
[51] Id. at 13.
[52] Id. at 11.
[53] NERC publishes data on TLR events on its website, but does not provide easily accessible information regarding the circumstances necessitating TLR usage. See https://www.nerc.com/pa/rrm/TLR/Pages/TLR-Logs.aspx (last accessed June 13, 2022). I am not aware of public data on the use of USFs in the Western Interconnection.
[54] See, e.g., Comments of Buckeye Power, Inc., Docket No. AD21-13 at 7 (filed Apr. 15, 2021) (“[N]ew planning criteria for resource adequacy should be developed that expressly address extreme weather events and other unusual scenarios that can threaten reliability.”); Comments of Tabors Caramanis Rudkevich, Docket No. AD21-13, at 10-11, 21-24 (filed Apr. 15, 2021) (stating that seasonal resource adequacy assessments “do not . . . adequately account for either common mode events or extreme events perceived to have a low probability,” and advocating for “the adoption of advanced resource adequacy methodologies and technologies that are capable of evaluation of large numbers of stochastically generated scenarios that incorporate and quantify both common mode events and the probability of extreme events”); Comments of Dominion Energy Services, Inc., Docket No. AD21-13, at 5 (filed Apr. 15, 2021) (“Constraints arising on natural gas pipelines during extreme weather may also impact the viability of operating reserves relied upon by the Regional Transmission Organizations,” potentially leaving them “with a false sense of security that [they have] a sufficient amount of operating reserves” when that is not the case.); Comments of LS Power Development, LLC, Docket No. AD21-13, at 4 (filed Apr. 15, 2021) (“[P]lanning procedures must recognize and account for common mode failure among various resource classes with respect to particular weather events and require protections and redundancies to prevent catastrophic failures like those that occurred in Texas.”).
[55] See, e.g., June 1, 2021 Tr. at 31:15 (Lisa Barton) (“[T]he current deterministic planning methodology that we have used today [] works when supply is highly dispatchable[,] when weather is predictable[, and] when peak demand is reached only a few days a year,” and “fundamentally needs to change” to address current conditions); 112-113, 127-128 (Mark Lauby) (highlighting the outdated nature of 1-in-10 LOLE, and noting that it was developed on the assumption that generator forced outages are independent, an unrealistic assumption given the likelihood of common mode events caused by extreme weather); at 118 (Richard Tabors) (“Our resource adequacy metrics and planning methods systematically understate the probability, the depth, and economic health and safety costs of high impact events.”).
[56] See PJM Interconnection, L.L.C., 176 FERC ¶ 61,056, at P 3 (2021) (approving a proposal by PJM to implement an ELCC methodology for crediting variable and limited duration resources); New York Independent System Operator, 179 FERC ¶ 61,102, at PP 75-82 (2022) (approving NYISO’s proposal to implement a marginal capacity accreditation design via either ELCC or a similar Marginal Reliability Improvement technique).
[57] 179 FERC ¶ 61,102 at PP 79, 90.
[58] 176 FERC ¶ 61,056 at P 7.
[59] See Potomac Economics, 2020 Assessment of the ISO New England Electricity Markets, June 2021 at 92 (“EFORd alone does not accurately describe” the reliability value of “intermittent renewables, energy-limited resources, long lead time or very large conventional generators, and generators that can experience a common loss of a limited fuel supply” because “these resource types pose the risk of correlated outage or limited availability of a large amount of capacity under peak conditions”), and 84 (arguing that the availability of these resource types is overestimated in GE-MARS, ISO-NE’s resource adequacy model).