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Regulatory Updates

FERC & NERC Issue Joint Report on Freeze Reliability Failures

Dylan Achey | Jim Whitaker | Steve Persutti | December 14, 2021

Mandatory Standards Modifcations Underway

On November 16, FERC and NERC issued the results of their Joint Inquiry into the February 2021 Cold Weather Outages in Texas and the South-Central United States. The event was the largest controlled firm load shed event in U.S. history. It was the third largest in quantity of outaged load after only the 2003 Northeast Blackout and the 1996 West coast blackout.

The report outlines twenty-eight recommendations to address freeze reliability failures, including operating practices and provides recommendations for NERC standards modifications surrounding generator winterization and gas-electric coordination.

Generator Owners (GO) and Transmission Owners (TO) should take note of the detailed findings of the report. Despite multiple prior recommendations over a ten year period by FERC and NERC, as well as annual reminders via Regional Entity workshops that generating units should take action to prepare for winter weather, 49 generating units in SPP (15 percent, 1,944 MW of nameplate capacity), 26 in ERCOT (7 percent, 3,675 MW), and three units in MISO South (four percent, 854 MW) still did not have any winterization plans. The Report noted that 81 percent of the freeze-related generating unit outages occurred at temperatures above the generating unit’s stated ambient design temperature. Generating units that experienced freeze-related outages above the unit’s stated ambient design temperature represented about 63,000 MW of nameplate capacity.

Key Cold Weather Recommendations

To address these failures and ensure generation and transmission owners are prepared for freezing weather, NERC and FERC recommend the following immediate actions:

  • GOs must identify and protect cold-weather-critical components
  • GOs must retrofit existing generating units, and when building new generating units, to operate to specific ambient temperatures and weather based on extreme temperature and weather data, and account for effects of precipitation and cooling effect of wind
  • GOs/ Generator Operators (GOPs) should perform annual training on winterization plans
  • GOs that experience freeze-related outages must develop Corrective Action Plans
  • GOs/GOPs will provide the Balancing Authority (BA) with the percentage of the total generating unit capacity that the BA can rely upon during the “local forecasted cold weather”
  • GOs need to account for effects of precipitation and accelerated cooling effect of wind when providing temperature data to BAs

Timeframes for New Standards Implementation

In addition to the immediate actions noted above, NERC is beginning a Standards development Project (2021-7) and has issued a draft Standards Authorization Request to develop the following additional Cold Weather Standards within key upcoming implementation timelines.

Before Winter 2022/23

  • Generator Owners and Generator Operators are to conduct annual unit-specific cold weather preparedness plan training.
  • Generator Owners that experience outages, failures to start, or derates due to freezing are to review the generating unit’s outage, failure to start, or derate and develop and implement a corrective action plan for the identified equipment and evaluate whether the plan applies to similar equipment for its other generating units.
  • The Reliability Standards should be revised to provide greater specificity about the relative roles of the Generator Owners, Generator Operators and Balancing Authorities in determining the generating unit capacity that can be relied upon during “local forecasted cold weather,” which is language from the revised Reliability Standard TOP-003-5, R2.3.
  • Each Generator Owner/Generator Operator should be required to provide the Balancing Authority with the percentage of the total generating unit capacity that the Generator Owner/Generator Operator reasonably believes the Balancing Authority can rely upon during the “local forecasted cold weather,” including reliability risks related to natural gas fuel contracts.
  • Each Balancing Authority should be required to use the data provided by the Generator Owner/Generator Operator, combined with its evaluation, based on experience, to calculate the percentage of each individual generating unit’s total capacity that it can rely upon during the “local forecasted cold weather,” and share its calculation with the Reliability Coordinator.
  • Each Balancing Authority should be required to use that calculation of the percentage of total generating capacity that it can rely upon to “prepare its analysis functions and Realtime monitoring,” and to “manage[e] generating resources in its Balancing Authority Area to address…fuel supply and inventory concerns” as part of its Capacity and Energy Emergency Operating Plans.
  • In EOP-011-2, R7.3.2, Generator Owners are to account for the effects of precipitation and accelerated cooling effect of wind when providing temperature data.
  • Balancing Authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) are to prohibit use of critical natural gas infrastructure loads for demand response.

Before Winter 2023/2024

  • Generator Owners are to identify and protect cold-weather-critical components and systems for each generating unit. Cold-weather-critical components and systems are those which are susceptible to freezing or otherwise failing due to cold weather, and which could cause the unit to trip, derate, or fail to start.
  • Generator Owners are to design new or retrofit existing generating units to operate to a specified ambient temperature and weather conditions (e.g., wind, freezing precipitation). The specified ambient temperature and weather conditions should be based on available extreme temperature and weather data for the generating unit’s location, and account for the effects of precipitation and accelerated cooling effect of wind.
  • To protect critical natural gas infrastructure from manual and automatic load shedding in order to avoid adversely affecting bulk-power system reliability, Balancing Authorities’, and Transmission Operators’ (TOPs) provisions for operator-controlled manual load shedding are to include processes for identifying and protecting critical natural gas infrastructure loads in their respective areas from firm load shed. Critical natural gas infrastructure loads are natural gas production, processing and intrastate and interstate pipeline facility loads which, if de-energized, could adversely affect the provision of natural gas to bulk-power system natural gas-fired generation.
  • In minimizing the overlap of manual and automatic load shed, the load shed procedures of Transmission Operators, Transmission Owners (TOs) and Distribution Providers (DPs) should separate the circuits that will be used for manual load shed from circuits used for underfrequency load shed (UFLS), undervoltage load shed (UVLS) or serving critical load. UFLS/UVLS circuits should only be used for manual load shed as a last resort and for UFLS circuits, should start with the final stage (lowest frequency).

The proposed Reliability Standards build upon the requirements in EOP-011-2, IRO-010- 4, and TOP-003-5 that were approved by FERC in August 2021. Additionally, several recommendations build on existing Standards related to load shedding and the development and implementation of automatic and manual UFLS and UVLS programs (EOP-011-2, PRC-006-5 and PRC-010-2).

Next Steps

The FERC-NERC Joint Report focuses on accelerated regulatory action. Extensive changes will impact both generation and transmission owners and operators. It is important for utilities to take note of this report, the recommendations and the regulations which will emanate from the disturbance event in order to plan for and maintain both compliance and reliability.

TRC’s technical teams have the necessary expertise in all power generation and power delivery engineering subject areas. TRC can provide project management services to review your compliance program and offer an independent review of your current generation and delivery facilities’ cold weather capabilities. TRC is well positions to assess your system equipment’s ability to perform as required under the prospective regulations. The timelines are accelerated, and the amount of work is significant. TRC can help your company meet these future requirements in this area of focus by FERC, NERC, and the NERC Regions.


Your Trusted Regulatory Advisor

TRC closely follows the national and state regulatory trends in all regions of North America. Our approach to power system planning, design and operations balances solutions that incorporate appropriate industry trends, mandatory standard requirements, regulatory guidance, compliance obligations, best practices, operational goals, and budgets. With expertise in both power system planning and operations, we support public utilities and private energy providers in their effort to stay ahead of the curve to meet regulatory requirements as they evolve.

This regulatory update is a service to TRC’s utility clients, helping keep you informed of issues that impact your company’s electric system reliability risks along with related topics regarding regulatory developments to help you achieve your company’s business goals.

Dylan Achey

Dylan Achey is TRC’s Manager of Generation Engineering Services. He has been leading the effort with TRC generation clients on evaluating and providing updates/information so that clients can meet applicable NERC standards. His highly technical staff perform NERC compliance standard evaluations as well as studies for both generation and transmission clients that need assistance on technical issues concerning NERC compliance. Contact Dylan at

Jim Whitaker, PE

Jim Whitaker, PE is Supervisor of Power Systems Studies at TRC. He has over 30 years of experience in Transmission and Distribution Planning, and Substation, Transmission and Distribution Engineering. His Transmission Planning projects include coordinating joint/regional 10-year transmission plans, generator interconnections, regional system assessments, as well as NERC compliance studies. His projects have included studies for both Utilities and Project Developers across the United States in the Eastern and Western Interconnection transmission systems as well as ERCOT. Prior to joining TRC, Jim worked for Xcel Energy, Peak Power Engineering, Tucson Electric Power and Virginia Power. Contact Jim at

Steve Persutti

Steve Persutti is TRC’s Senior Vice President of Business Development. He has 25 years of comprehensive management experience within the energy industry and a consistent and successful record in strategic business planning, productivity and efficiency improvements, systems design and implementation, and employee collaboration. His areas of expertise include engineering management, project management, EPC project management, construction management, financial analysis and customer service. Steve has an M.B.A in Finance from the University of Hartford and a B.S. in Marketing from the University of Connecticut. Contact Steve at

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