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2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination | Draft 2

Description:

Start Date: 08/03/2022
End Date: 09/01/2022

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-012-1 AB 2 ST 2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-012-1 05/19/2022 06/02/2022 08/23/2022 09/01/2022
2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-012-1 | Non-binding Poll AB 2 NB 2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-012-1 | Non-binding Poll 05/19/2022 06/02/2022 08/23/2022 09/01/2022
2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination Implementation Plan AB 2 OT 2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination Implementation Plan 05/19/2022 06/02/2022 08/23/2022 09/01/2022

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Hot Answers

Yes, the addition of the definitions provides additional clarity to the requirements.  However, Enel agrees with the MRO NSRF comments that these definitions should also be added to the NERC Glossary of Terms.

Natalie Johnson, Enel Green Power, 5, 9/1/2022

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Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

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Other Answers

These definitions continue to add an administrative burden on those entities who operate, and are designed to operate in cold climates.  Specifically, many hydro projects in northern climates that operate in sub-zero weather have dealt with extreme temperature operations successfully.  How much more planning and preparation must be made when we already operate to -28 F during the winter?  We may see seasons with more river ice, but that is not unusual.  Months of preplanning will not prevent river icing, or the work that must be done to mitigate the effects.

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

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Entergy, Segment(s) 1, 5, 12/13/2017

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

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Diana Torres, Imperial Irrigation District, 6, 8/23/2022

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DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

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The proposed definitions are insufficient; another is needed for temperature.  The issue at hand cannot be addressed using only readings from thermometers (dry bulb temperature, DBT).  Generic references to, “the temperature,” as in the Extreme Cold Weather Temperature definition, therefore degrade clarity due to lack of specificity. 

The parameter of interest for conventional generation plants is the wind chill temperature (WCT), combining the effects of DBT and wind speed in causing heat transfer.  Winter Storm Uri, the Polar Vortex of 2014, and the 2011 Southwest Cold Weather Event all achieved an “extreme” classification by virtue of involving high winds, and any standard on the subject must explicitly address this point.  RCs, BAs and TOPs cannot adequately plan for winter storm-related threats to the BES if using DBT-based generation plant capability data for an inherently WCT-based phenomenon.

Some manufacturers of wind turbines offer winterization packages based on DBT, however, so it may be necessary for EOP-012-1 to say that WCT or DBT is to be used as applicable for the generation technology at hand.  An alternative, universal approach is to say that “temperature” in the present context means DBT plus a 20 mph wind, this being a typical sustained wind condition for the worst hours of the aforementioned grid emergencies.

The Guidance section of EOP-012-1 should then explain that the WCT scale is to be used for transposing capability data.  A conventional plant that is protected to -10 F DBT with a 5 mph wind (-22 F WCT), for example, is to state its EOP-012-1 capability as being 0 F DBT (-22 F WCT when combined with a 20 mph wind). 

A definition is also needed for freezing, and it should clarify how precipitation fits into the picture.  We propose, “The transition of water to ice, or congealing of fluids to the point of affecting operations (e.g. for lube oil, fuel oil and water treatment chemicals).  The effects of precipitation stand separate from freezing.”  The Guidance section of the standard should add, “A unit having a freeze prevention capability of -15 F DBT with a 20 mph wind, for example, might be forced offline by a snow or ice storm at 30 F.”

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

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Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

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Talen Marketing LLC supports Talen Generation's comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

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The proposed definitions for Extreme Cold Weather Temperature, Generator Cold Weather Critical Component, and Generator Cold Weather Reliability Event provide needed additional clarity to the requirements for EOP-012.  However, we have some concerns with the proposed definition of Generator Cold Weather Critical Component and Generator Cold Weather Reliability Event.  

WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

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Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

- 0 - 0

Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

- 0 - 0

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

- 0 - 0

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

- 0 - 0

Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

- 0 - 0

Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

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Avista agrees that the proposed definitions for Extreme Cold Weather Temperature, Generator Cold Weather Critical Component, and Generator Cold Weather Reliability Event provide needed clarity to the requirements for EOP-012-1.  However, we recommend additional revisions to the definitions of Generator Cold Weather Critical Component and Generator Cold Weather Reliability Event to provide enhanced clarity, to be addressed during the 2nd phase of this project.  (See our response to Question 2)

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

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Portland General Electric Company supports the survey response provided by EEI.

Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

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Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

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Glenn Pressler, CPS Energy, 3, 8/30/2022

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Avista agrees that the proposed definitions for Extreme Cold Weather Temperature, Generator Cold Weather Critical Component, and Generator Cold Weather Reliability Event provide needed clarity to the requirements for EOP-012-1.  However, we recommend additional revisions to the definitions of Generator Cold Weather Critical Component and Generator Cold Weather Reliability Event to provide enhanced clarity, to be addressed during the 2nd phase of this project.  (See our response to Question 2)

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

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We agree appropriately formed definitions would provide additional clarity if the comments below are addressed.

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

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Ameren agrees with the EEI and the NAGF comments.

David Jendras, Ameren - Ameren Services, 3, 8/31/2022

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Xcel Energy supports comments from EEI. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

- 0 - 0

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

- 0 - 0

PG&E agrees to the proposed definitions and the recommendations supplied by EEI on additional revisions during Phase Two of the Cold Weather project.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

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AEP would like to express its support of EEI’s response to this question.

Thomas Foltz, AEP, 5, 8/31/2022

- 0 - 0

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

LouisvilleG&E/KU support EEI's comments. 

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

- 0 - 0

Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

- 0 - 0

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

- 0 - 0

Southern Company agrees that the addition of these key terms provide additional clarity to the proposed standard.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

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Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

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Reclamation disagrees that the proposed Glossary Terms provide clarity for the proposed requirements of EOP-012. The most significant issues are what is meant by “susceptible to freezing issues” and “fuel supply component.” The phrase “susceptible to freezing” is not relevant for solar and wind. While this equipment may have frozen precipitation on them, the component itself is not frozen. The phrase “fuel supply component” is not relevant for hydro, solar, and wind. Exempting components located inside temperature controlled buildings that are not susceptible to freezing would allow entities to focus on components that actually pose a risk to the BES. This seems to be the intent of the SDT, but needs to be clearly written in the standard.

A reliability standard should be applicable to specific reliability functions (e.g., Generator Owner, Generator Operator), specific geographic locations (e.g., south of 35 degrees latitude), and/or specific equipment (e.g., gas, solar, wind). Reclamation observes that undue effort is being spent on precisely identifying the specific cold weather conditions under which the standard applies. Reclamation asserts this effort will result in a disservice to the intent of ensuring electric reliability during cold weather because the narrow applicability will allow critical electrical infrastructure to be exempt from the proposed requirements. Reclamation observes that many of the issues the SDT appears to be trying to address and that entities have commented about would be better addressed in a forum outside of electric reliability standards, e.g., marketing issues. It appears that the electric industry is being inappropriately tasked with solving a problem the root cause of which may not be within its purview.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

- 0 - 0

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

- 0 - 0

Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

- 0 - 0

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

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“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

- 0 - 0

Claudine Bates, Black Hills Corporation, 6, 8/31/2022

- 0 - 0

Josh Combs, Black Hills Corporation, 3, 8/31/2022

- 0 - 0

Micah Runner, Black Hills Corporation, 1, 8/31/2022

- 0 - 0

Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

- 0 - 0

Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

- 0 - 0

PNM agrees that the proposed definitions for Extreme Cold Weather Temperature, Generator Cold Weather Critical Component, and Generator Cold Weather Reliability Event.  PNM also supports the comments provided by EEI.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

- 0 - 0

James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

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Adding the proposed defined terms provides additional clarity to the requirements of EOP-012, and Vistra supports inclusion of definitions for those terms in the Reliability Standard. However, Vistra recommends refinements to the definitions as described below under Question 2.

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

- 0 - 0

Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #1.

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

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Exelon agrees that the proposed definitions provide additional clarity to EOP-012-1.

 

Submitted on behalf of Exelon, Segments 1 & 3

Daniel Gacek, Exelon, 1, 9/1/2022

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Southern Indiana Gas & Electric Company (SIGE) agrees the added definitions of Extreme Cold Weather Temperature, Generator Cold Weather Critical Component, and Generator Cold Weather Reliability Event provide additional clarity to the requirements of EOP-012. However, similar to EEI, SIGE also has concerns with the proposed definition of Generator Cold Weather Critical Component and Generator Cold Weather Reliability Event – as addressed in SIGE’s response to Question 2. 

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

- 0 - 0

Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

- 0 - 0

Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

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Adding the proposed defined terms provides additional clarity to the requirements of EOP-012, and Vistra supports inclusion of definitions for those terms in the Reliability Standard. However, Vistra recommends refinements to the definitions as described below under Question 2.

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

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The definitions do not meet their objective as described in question 2. 

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

- 0 - 0

Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

- 0 - 0

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

- 0 - 0

ISO-NE agrees that for the context of the new EOP-012 Standard these definitions are needed for clarification purposes, however some modifications to those definitions may be needed as described in Question 2 Comments by the SRC and ISO-NE.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

LES, Segment(s) 6, 1, 3, 5, 10/8/2018

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Yes, the addition of the definitions provides additional clarity to the requirements. The proposed definitions as stand-alone items in the NERC Glossary of Terms will also help to provide uniformity across future Standards dealing with extreme weather such as TPL-001 recently focused on by a FERC NOPR. 

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

- 0 - 0

Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

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Yes, the addition of the definitions provides additional clarity to the requirements. The MRO NSRF would like to suggest that the three proposed Terms (Generator Cold Weather Critical Component, Extreme Cold Weather Temperature & Generator Cold Weather Reliability Event) be placed in a new section, §6. Definitions Used in this proposed standard, similar to NERC Reliability Standard PRC-005-6 Protection System, Automatic Reclosing, and Sudden Pressure Relaying Maintenance, rather than the NERC Glossary of Terms.  The proposed definitions are dependent on NERC Reliability Standard EOP-012-1 – Extreme Cold Weather Preparedness and Operations, §4.2 term “generating unit” to ensure a comprehensive and complete definition.  As such, placing the three proposed terms into the NERC Glossary of Terms would prevent them from being fully defined as intended by the Standards Drafting Team and subject to unintentional misinterpretation.  The MRO NSRF suggests consideration be given to including these definitions in the NERC Glossary of Terms during future revisions.  

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

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Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

MidAmerican Energy supports the MRO NSRF as well as EEI comments for this question.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

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Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

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Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

- 0 - 0

Mark Young, Tenaska, Inc., 5, 9/1/2022

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The definition of  Generator Cold Weather Reliability Event, item 1 is not entirely clear. Is the intent to exclude derates equal to 20MW ( if they are more than 10%) or equal to 10% of total unit capacity ( when more than 20MW)? Suggest rewording to : a forced derate exceeding 10% of the total capacity of the unit but no less than 20 MW for longer than four hours in duration;" 

Imane Mrini, Austin Energy, 6, 9/1/2022

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MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC). In addition, we are submitting comments on behalf of MISO as an individual entity.

MISO thanks the Standard Drafting Team (SDT) for adopting the recommendation in MISO’s comments from Project 2019-06: Cold Weather to develop a “cold weather” definition. Having a national reference will drive consistency of application across the NERC footprint.

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

- 0 - 0

Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

- 0 - 0

Madison Gas and Electric supports the comments from the MRO NSRF.

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

- 0 - 0

Madison Gas and Electric supports the comments of the MRO NSRF

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

- 0 - 0

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

- 0 - 0

The defined terms do make the proposed requirements clearer. However, there are still areas of ambiguity that Invenergy recommends be addressed. Those recommendations can be found in our response to Question 2.

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

- 0 - 0

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/6/2022

- 0 - 0

We agree the definitions would provide additional clarity.

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 9/1/2022

- 0 - 0

Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 9/1/2022

- 0 - 0

SMUD / BANC, Segment(s) 3, 6, 1, 4, 5, 8/18/2022

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Outages on GO controlled transmission lines caused by ice storms should not be included in a Generator Cold Weather Reliability Event (GCWRE).  Also, GOs should be exempted from including forced outages as GCWREs if the forced outage was caused by a loss of offsite power caused by a BES grid event (e.g., load shed, low frequency, sub-synchronous resonance, etc.) or other transmission events unrelated to the GO Operation.  In addition, GO operators should be exempted from including forced outages due to loss of fuel supply for any reason outside of the GO’s control.  For these events, the exemption should apply to not only the time of the event, but also to any recovery time required to implement corrective actions needed as a direct result of the causal event.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

EEI agrees that the proposed definitions for Extreme Cold Weather Temperature, Generator Cold Weather Critical Component, and Generator Cold Weather Reliability Event provide additional clarity to the requirements for EOP-012-1.  However, we recommend additional revisions to the definitions of Generator Cold Weather Critical Component and Generator Cold Weather Reliability Event to provide enhanced clarity, that can be addressed during the 2nd phase of this project.  (See our response to Question 2)

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 5, 9/1/2022

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/1/2022

- 0 - 0

Alyssia Rhoads, Public Utility District No. 1 of Snohomish County, 1, 9/1/2022

- 0 - 0

John Liang, Snohomish County PUD No. 1, 6, 9/1/2022

- 0 - 0

Deanna Carlson, Cowlitz PUD, 5, 9/1/22

Deanna Carlson, Cowlitz County PUD, 5, 9/1/2022

- 0 - 0

 

The ISO/RTO Council (IRC) Standards Review Committee (SRC) supports the addition of definitions for Extreme Cold Weather Temperature, Generator Cold Weather Critical Component, and Generator Cold Weather Reliability Event. 

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 9/1/2022

- 0 - 0

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 9/1/2022

- 0 - 0

Avista agrees that the proposed definitions for Extreme Cold Weather Temperature, Generator Cold Weather Critical Component, and Generator Cold Weather Reliability Event provide needed clarity to the requirements for EOP-012-1.  However, we recommend additional revisions to the definitions of Generator Cold Weather Critical Component and Generator Cold Weather Reliability Event to provide enhanced clarity, to be addressed during the 2nd phase of this project.  (See our response to Question 2)

Mike Magruder, Avista - Avista Corporation, 1, 9/1/2022

- 0 - 0

The defined terms do make the proposed requirements clearer. However, there are still areas of ambiguity that Invenergy recommends be addressed. Those recommendations can be found in our response to Question 2.

Rhonda Jones, Invenergy LLC, 5, 9/1/2022

- 0 - 0

Hot Answers

Extreme Cold Weather Temperature:   On a positive note, Enel prefers the updated criteria.  It is a clearer criteria to assess and apply, especially with the focus on December to January months.  Enel does support the MRO NSRF comments that industry meteorological experts (i.e NOAA, NWS) should be consulted and involved in this process.

Generator Cold Weather Reliability Event:  Enel would like to recommend a few additional edits to the Generator Cold Weather Reliability Event definition.  The additional criteria is a step in the right direction but could still lead to undue administrative burden without a corresponding reliability benefit.  The 10% of the total capacity and exceeding 20MW is still far too low and could cause Corrective Action Plans for events that do not impact the Bulk Electric System resulting in substantial and unnecessary burdens.  Enel suggests again that NERC adopt the same approach used in PRC-004, where misoperations that affect an aggregate nameplate rating of less than or equal to 75MVA of BES facilities are excluded.  For this reason Enel agrees with the MRO NSRF comments on this defined term.  In addition, Enel would like to ensure that criteria is applied to “available” capacity as indicated by the forecasted power curve.  Renewables cannot generate during low wind or solar conditions and therefore criteria should not be applied to unavailable capacity or nameplate.  

Natalie Johnson, Enel Green Power, 5, 9/1/2022

- 0 - 0

We agree with the new proposed definitions, but still believe the definition of Generator Cold Weather Reliability Event should either remove the phrase “apparent cause(s)” or reword it to be “for which the apparent cause(s), as determined by the entity during RCA or internal investigation, is due to…”.  Without definition, the term “apparent” is subjecetive and open to different interpretations.  It should be removed, or clarified that it is as defined by the entity.

Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

- 0 - 0

Other Answers

This standard should be clearly targeted to those entities not designed to run in below freezing conditions, that operate in those areas where it is possible to have freezing events.  Those entities operating in environments where freezing is a yearly expectation, and where they are designed to operate in freezing weather should be exempt.  We feel that, due to poor performance of certain generators in specific areas, the whole fleet of generators is being targeted for this poor performance.  This comes at a significant cost and effort by smaller organizations who do not have these risks.

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

- 0 - 0

Entergy, Segment(s) 1, 5, 12/13/2017

- 0 - 0

Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

- 0 - 0

IID disagrees that the 0.2 percentile is not overly conservative, IID recommends to use 0.5 or 1.0.

Diana Torres, Imperial Irrigation District, 6, 8/23/2022

- 0 - 0

DTE Electric supports NAGF comments provided for this project

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

- 0 - 0

Talen Energy supports in large part the inputs of the NAGF on this topic, and goes further by recommending that the, “Extreme Cold Weather Temperature,” should be the historical worst-case temperature (WCT, or DBT-plus-20 mph, as described above).  Setting a statistical cutoff for winterization (proposed in Rev. 2 of EOP-012-1 to be the 0.2 percentile of the winter season) is fundamentally unsuitable. 

EOP-012-1 in its present form implies that the blackouts, deaths and damage caused by Winter Storm Uri are acceptable, so long as they are experienced only during the coldest 43 hours per decade (or much longer, due to the time needed to troubleshoot, thaw and restart units with freeze-up forced outages).  This is precisely when BES reliability is most important, however, becoming a life-or-death matter.

Where will the power come from during those 43 (or more) hours?  The answer presently is that it will be supplied by older generation plants, designed to operate through all winter storms and not just some of them.  As the years pass and these facilities are replaced by 0.2 percentile units, however, occasional devastating blackouts will become the norm, not as a ghastly error but according to plan.

The argument that some EPC firms use the 0.2 percentile cutoff has no validity.  This is the cause of the problem, not the cure.  One must not depend on old-reliable units to save the day and allow cutting corners in the quest to become the low bidder.  It is NERC’s job to put a halt to such practices, not enshrine them as the law of the land. 

It is impossible moreover to slice matters so finely as a fraction of a percentile, since freeze protection is subject to great uncertainty due to frequent design and installation errors by contractors.  Protection that is thought to address all weather except the coldest 43 hours per decade might in fact allow freeze-up for a much longer duration.  Nor is there need for extreme exactitude, since the cost difference between designing for the 0.2 percentile temperature and historical worst-case conditions is negligible in comparison to the harm being prevented.

The DBT-plus-20 mph approach proposed above provides a simple alternative for GOs having difficulty identifying the worst-historical WCT.  This would not be an excessively conservative criterion, since winter storms that cause grid emergencies tend to be by those combining low DBT values with high wind speed.  Also, in our experience heat tracing/insulation systems rarely provide the specified protection, much less containing enough safety margin to cover 0.19 percentile-and-lower events.  In summary:

{C}-         The mission of Project 2021-07 is to ensure BES reliability during ALL credible winter storm conditions.

{C}-         Historical worse-case conditions are credible; they happened before, so they can happen again.

{C}-         Therefore the design criterion must be the historical worst-case weather conditions, which to be meaningful must be wind and temperature-based (WCT) and relying soly on temperature (DBT). 

The definition of Generator Cold Weather Critical Components and the way in which this term is used in R1 and R3 indicate an obligation to list freeze-susceptible equipment at the component level and identify their individual temperature capabilities.  Doing so for every outdoors pipe and tube containing water or steam (even large-bore systems can freeze if left static for too long during downtime periods), plus their associated instruments and equipment, would be extremely and unnecessarily burdensome.  It should be sufficient to address elements at the system level, where freeze protections was implemented on this basis.  That is, only a single entry would be needed for all outdoors water and steam piping if it was heat-traced and insulated under a single contact, using conditions of X degrees F DBT and Y mph wind speed. 

The Generator Cold Weather Reliability Event definition should be revised and Guidance material should be added, as shown below.  There are presently many forced outages under part 3 of this currently proposed definition (and EOP-012-1 in its present form will not prevent them), because the vulnerability being discussed is related to WCT for conventional plants, not DBT.

Generator Cold Weather Reliability Event

(1) a forced derate of more than 10% of the total capacity of the plant and exceeding 20 MW for the plant, for longer than four hours in duration, due to freezing of equipment within the Generator Owner’s control. 

or

(2) a start-up failure in which the unit fails to synchronize within the extreme cold weather start-up time declared for R3.5 [add this to R3.5, there is presently no target in this respect], due to freezing of equipment within the Generator Owner’s control. 

Guidance:  “Precautionary derates, e.g. ramping-down CTGs to minimum load during blizzards to help avoid clogging the inlet air filters, are not counted as forced derates so long as this limitation has been documented in accordance with R3.5 of EOP-012-1.”

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

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Tri-State mostly agrees however, the concept of mobile vs. fixed fuel should be incorporated into the Generator Cold Weather Critical Component definition.

Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

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Talen Energy Marketing LLC supports Talen Generation's comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

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We agree with the definitions and our program will inform the correct action to maintain reliability at Extreme Cold Weather Temperature, prepare for a Cold Weather Event and identify Cold Weather Critical Components.  We can communicate our concerns for generator availability using the communication requirements.

WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

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Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

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The SDT intended for the “Extreme Cold Weather Temperature” to be recorded at or near the plant site, but the location is not included in the definition.  We suggest the SDT consider enhancing the definition (incorporating a location) such as the following:

Extreme Cold Weather Temperature – The temperature equal to the lowest 0.2 percentile of the hourly temperatures neasured in December, January, and February from 1/1/2000 through the date the temperature is calculated at one of the following locations:

a.  At the generating plant site (preferred location).

b.  At the closest official meterological location.

c.  At an official weather recording site within the generating plant surrounding area.

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

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The current definitions as written leave ample room for interpretation. While this is often desired, we believe that in this instance they do not provide enough clarity to the requirements of EOP-012. The specific concerns with the current verbiage are as follows:


Generator Cold Weather Critical Component: While the open-endedness of “any generating unit component” is desired as it allows the Generator Owner to identify critical components on a per-unit basis, it does not appear to include any “common” equipment shared between units. Examples would include service water, instrument air, ammonia, ash handling, common bus isolation breakers/switches, etc. The proposed modification to the definition is: “Any generating unit component or associated fixed fuel supply component, to include any critical equipment shared between multiple units (i.e. Balance of Plant (BOP) and/or Common equipment), that is under the Generator Owner’s control and is susceptible to freezing issues, the occurrence of which would likely lead to a Generator Cold Weather Reliability Event.”


Extreme Cold Weather Temperature:  If the current method to calculate is implemented, NERC should consider coordinating with the National Oceanic and Atmospheric Administration to ensure dry bulb temperature data is available from 1/1/2000 through an indefinite future date. As currently written the requirement to use “the hourly temperatures measured” seems a bit excessive. Given the inherent difficulty of compiling a dataset containing > 49,000 data points and then calculating the lowest 0.2 percentile, we recommend modifying the definition to include daily minimum temperatures from the same time period. This modification would reduce the size of the dataset significantly (down to ~2076 total days) and should not change the resulting Extreme Cold Weather Temperature by any significant statistical margin given that the daily minimum will contain the hourly minimums.


Lastly, the requirement to use a fixed data start date of 01/01/2000 means the dataset will grow by approximately 2,160 data points if using the hourly metric while only 90 data points if using the daily minimum metric. Therefore, it is our recommendation to use a 20-year rolling time period if staying with the hourly metric.


If the hourly metric is to remain, a proposed modification to the definition would be: “The temperature equal to the lowest 0.2 percentile of the actual hourly temperatures measured in December, January, and February from the previous 20 years immediately prior to the date the
temperature is calculated.“


The preferred modification would be to abandon the hourly metric in favor of the daily minimum metric. This proposed modification to the definition is: “The temperature equal to the lowest 0.2 percentile of the actual daily minimum temperatures measured in December, January, and February from 1/1/2000 through the date the temperature is calculated.”


Generator Cold Weather Reliability Event: Pertaining to event type 2 that may constitute a Generator Cold Weather Reliability Event:
2. “A start-up failure where the unit fails to synchronize within a specified start-up time”: Who specifies the start-up time? Per the draft Technical Rationale and Justification for EOP-012-1, start-up failures are defined using a modified version of the GADS definition in order to ensure consistency across all jurisdictions for this standard. Our concern stems from the language in R2 that references the GADS definition of “specified start-up time” without providing the additional clarification found in the 2022 GADS Data Reporting Instructions. Our recommendation is to modify this subsection as follows: “A start-up failure where the unit fails to synchronize within a specified start-up time. The specified start-up time period for each unit is determined by the GO/GOP based on the condition of the unit at the time of start-up.”

In addition this defined term is not clear in relation to what constitutes “apparent cause(s) is due to freezing of equipment” in the draft definition. AECI urges the standard drafting team to consider removing the word “apparent” from the definition as the apparent cause may not be the actual cause after further investigation. 

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Consider modifying the following term definitions:

-Extreme Cold Weather Temperature:

Change “Extreme Cold Weather Temperature” to “Extreme Cold Weather Target Temperature” to discern between the lowest extreme cold weather temperature and the extreme cold weather temperature adjusted for the lowest 0.2 percentile of the hourly temperatures.

-Generator Cold Weather Critical Component:

Change “Any generating unit component or associated fixed fuel supply component…” to “Any component or associated fixed fuel supply component…” to recognize non-traditional units (e.g., solar) that do not have traditional electrical generators and to capture unit auxiliary components.

-Generator Cold Weather Reliability Event:

Suggestion #1: (2) a start-up failure where the unit fails to synchronize within a specified start-up time:

o   Define specified start-up time duration that constitutes a start-up failure.

o   Define the entity that would determine the start-up time duration and failure.

Suggestion #2: (3) a Forced Outage”,”:

o   Change comma to a semi-colon.

o   Note: As written, the paragraph that follows “(3) a Forced Outage” appears to be uniquely linked to Event (3) rather than representing language specified for Events (1), (2) and (3).

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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To clarify the definition of “Generator Cold Weather Reliability Event”, we recommend the language “for which the apparent cause(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above the Extreme Cold Weather Temperature” be moved to the beginning of the definition to clarify that it applies to derates, start-up failures, AND forced outages.

Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

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It is unclear why the word “apparent” is used in the definition for Generator Cold Weather Reliability Event. Based on the time-lines provided for the development of a CAP (up to 150 days) there is sufficient time to make a determination of the cause of a Generator Cold Weather Reliability Event. Additionally, without determining the actual cause of an event it would be imposible to develop an effective CAP. The use of a subjective term like “apparent” opens up all events to interpretation during compliance review and should be removed from the definition.

Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

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ECWT source data not clearly defined. This could be anything from an employee logging a thermometer value to downloading incomplete data from NOAA. Plus, data may be available and adequate for some generating stations, but for other remote generating station the search for historical data has produced incomplete and/or missing data. Maintaining a rolling minimum value of the lowest winter temperatures (3 months) from 1/1/2000 to current is excessive, especially for 20+ year old plants. Ten years of data from the commercial operation date or ten years ending on the date of adoption of EOP-012-1 would seem sufficient.

Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

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Avista supports all three definitions for this first phase, but we also propose additional revisions to the Generator Cold Weather Critical Supply Component and the Cold Weather Reliability Event because additional clarity is needed and that can be addressed during the next phase of this project. (See below) 

 

Generator Cold Weather Critical Supply Component: Use of the undefined term “fixed fuel supply component” within the proposed definition of Generator Cold Weather Critical Component creates confusion.  While we support the explanation provided by the SDT in the Technical Rationale, the Technical Rationale has no standing as a compliance document.  For this reason, we ask the SDT to consider defining this term within the framework of the next phase of this project.  We suggest the following for SDT consideration:

 

Fixed Fuel Supply Component: Are non-mobile equipment that support the reliable delivery of fuel to the generating unit and under the control the Generator Owner at a plant site. Gaseous, liquid, or solid fuel handling components that are installed on site as fixed parts of the fuel delivery system that are under the Generator Owner’s control would be included. Components that would not be included would be mobile equipment such as trains, bulldozers, or other equipment that are not fixed in one location.

Generator Cold Weather Reliability Event: EEI is concerned with the use of the term “specified”, as it relates to the start-up time of a generator during cold weather events, because it is unclear clear who would be responsible for specifying the start-up time.  Results Based Standards should “define a particular reliability objective or outcome to be achieved.  In its simplest form, a results-based requirement has four components: who, under what conditions (if any), shall perform what action, to achieve what particular result or outcome.” (NERC Results Based Standards – Performance Based; 

 

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

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Portland General Electric Company supports the survey response provided by EEI.

Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

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Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

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Glenn Pressler, CPS Energy, 3, 8/30/2022

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Avista supports all three definitions for this first phase, but we also propose additional revisions to the Generator Cold Weather Critical Supply Component and the Cold Weather Reliability Event because additional clarity is needed and that can be addressed during the next phase of this project. (See below)  

Generator Cold Weather Critical Supply Component: Use of the undefined term “fixed fuel supply component” within the proposed definition of Generator Cold Weather Critical Component creates confusion.  While we support the explanation provided by the SDT in the Technical Rationale, the Technical Rationale has no standing as a compliance document.  For this reason, we ask the SDT to consider defining this term within the framework of the next phase of this project.  We suggest the following for SDT consideration:

Fixed Fuel Supply Component: Are non-mobile equipment that support the reliable delivery of fuel to the generating unit and under the control the Generator Owner at a plant site. Gaseous, liquid, or solid fuel handling components that are installed on site as fixed parts of the fuel delivery system that are under the Generator Owner’s control would be included. Components that would not be included would be mobile equipment such as trains, bulldozers, or other equipment that are not fixed in one location.

Generator Cold Weather Reliability Event: EEI is concerned with the use of the term “specified”, as it relates to the start-up time of a generator during cold weather events, because it is unclear clear who would be responsible for specifying the start-up time.  Results Based Standards should “define a particular reliability objective or outcome to be achieved.  In its simplest form, a results-based requirement has four components: who, under what conditions (if any), shall perform what action, to achieve what particular result or outcome.” (NERC Results Based Standards – Performance Based; https://www.nerc.com/pa/Stand/Pages/ResultsBasedStandards.aspx#:~:text=Results%20based%20standards%20are%20standards,the%20NERC%20Standard%20Processes%20Manual.)

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

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Extreme Cold Weather Temperature (“ECWT”): We do not agree that this definition adds clarity.  Temperature, wind velocity, precipitation, and duration are inseparable when evaluating freeze protection measures.  The SDT attempts to create a synthetic condition that has not occurred in nature.  As we describe below, we think a more logical approach would be to select the duration and frequency of occurrence.  This procedure links all variables as the naturally exist to establish models that set reliability standards.  Setting the temperature first provides little predictive power in a generator’s ability to perform under extreme cold weather events.  As an example, if the ECWT were 15 degrees at a particular location and had to meet the duration standard for new generators, 12 hours, our analysis shows that the observed temperatures dip below the ECWT for some or all of the duration in almost all scenarios.  In many cases, the dip is significant.  Therefore, if a generator plans to perform for 12 hours at the ECWT it may fail.  Additionally, we asked whether the SDT performed analysis to confirm whether an assumed 20 mph wind coincident with the duration was reasonable.  The SDT replied that it was a reasonable assumption based on the group’s experience. We analyzed the weather data for 27 locations from California to Massachusetts and North Dakota to Florida.   In only one location (Boston) did wind and temperatures at or below the ECWT appear correlated.   

Rather than specifying a temperature and a duration independently, the better approach would be to allow the Balancing Authorities (BA) to specify the weather scenarios that they use in their planning scenarios.  Alternatively, if NERC were to set the standard, a better approach for establishing a continent-wide standard would be to start with a loss-of-load-expectation (LOLE) and work backwards to the combination of temperature, duration, wind, and (perhaps) precipitation that yield the criteria LOLE.  As an example, select a reasonable duration – e.g., 12 hours, etc., then calculate the temperature that yields the selected LOLE memorialized in the reliability standard (“Historical Event(s)”).  Fiftieth percentile wind speed coincident with these Historical Event(s) are then a derivative of this calculation.  Because the effects of precipitation are much more subjective and difficult to quantify, the standard should require generator owners to examine historical precipitation coincident with the Historical Event(s) and document that they have considered the effects of the precipitation and modified their cold weather preparedness plans accordingly. We offer a proposed alternate definition:

 

Extreme Cold Weather Event Standard –  An(a) observed event(s) with a duration of no less than 12 hours, such that the combination of observed hourly dry bulb temperatures and 50th percentile wind speeds yield a once in XX year probability of occurring at the generator’s location based on a review of the historical weather from the period January 1, 2000 through the date the temperature is calculated.”  

 

Generator Cold Weather Critical Component (“Component”):  The benefit of defining specific components within a generator that may be susceptible to freezing are evident, but the benefit of applying a MW threshold at the component level is not.  This definition does not expressly define a MW threshold but engages a threshold through the definition’s reference to a “Generator Cold Weather Reliability Event.”  In our experience if a component is so fundamental to the operation of the facility that its loss could cause a derate, then it is critical.  Additionally, setting a MW threshold may be counter-productive.  As an illustrative example, say a coal plant has six coal mills and only needs five to obtain full output – i.e., the loss of any one mill would not “likely” lead to a derate, so a generator owner could logically conclude that all coal mills could be excluded from the Component definition.   Redundant instrumentation, conveyors, etc. may also be excused using similar logic.  We propose the following definition:

 

Generator Cold Weather Critical Component – Any generating unit component or associated fixed fuel supply component that are under the Generator Owner’s control and are susceptible to freezing, the occurrence of which would likely lead to a forced outage, derate, failed start or the reliance on redundant or back-up components to maintain output.”

 

Generator Cold Weather Reliability Event (“Event”):  We do not have any comments to this definition at this time.

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

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Ameren agrees with the EEI and the NAGF comments.

David Jendras, Ameren - Ameren Services, 3, 8/31/2022

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Xcel Energy supports comments from EEI. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

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Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

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PG&E supports the proposed definitions for Phase One (this version) of the Cold Weather project and agrees with the input by EEI and the NAGF that additional clarity is needed which should be completed during Phase Two of the project. 

 

Our input of NO for the comment is related to the additional work needed in Phase Two.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

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In regards to the definition of the term “Generator Cold Weather Reliability Event”, the text “for which the apparent cause(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above the Extreme Cold Weather Temperature” is provided *after* the text for (3), which gives the impression (likely unintentional) that it only applies to (3) rather that to (1), (2), and (3) collectively. AEP recommends moving the text so that it instead proceeds (1), (2), and (3), and adding text to make it clear that it indeed applies to all of them collectively.

The definition of Generator Cold Weather Critical Component is somewhat circular, as it specifically references the word “component” multiple times, yet it does not clearly state what a “component” itself actually is. The definition could benefit from this added clarity, perhaps similar to that provided in the definition of “Protection System” in the NERC Glossary of Terms. This might be considered either now or in future phases of this project.

Thomas Foltz, AEP, 5, 8/31/2022

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Dominion Energy supports comments submitted by EEI proposing revisions to the proposed definitions.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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LouisvilleG&E/KU support EEI's comments. 

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

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For Generator Cold Weather Critical Component definition, please see modification (italicized - text in brackets describes recommended change) as follows: 

Any generating unit component or associated fixed fuel supply component, that is under the Generator Owner’s control [recommend replacing "control" with "ownership"] ownership and that is susceptible to freezing issues, the occurrence of which would likely lead to a generating unit(s): (1) forced derate of more than 10% of the total capacity of the unit and exceeding 20 MWs for longer than four hours in duration, (2) a start-up failure where the unit fails to synchronize within a specified start-up time, or (3) a Forced Outage.

Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

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While CHPD recognizes the merits of allowing the percentile method, we would recommend adding language to recognize and allow use of minimum temperature data from daily, monthly, or yearly weather record summaries, rather than prescriptively requiring a certain percentile of hourly data. Additionally it should also be noted that some weather station data will not go back to the required 2000 date and therefore language should be added to allow for flexibility in those instances. Furthermore, some generating plants do not have weather data directly available at the plant, but this data is available at a nearby location. The proximity of the weather site location to the generating plant should be addressed so this aspect is clear to the Generator Owner.

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

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Southern Company aligns with EEI’s comments an offers some suggestions for additional clarity.  For Generator Cold Weather Critical Component, we suggest clarification would be beneficial to specifically state in the definition that it includes equipment for which the GO has responsibility to provide freeze protection.  

Southern also proposes modifying the definition of Generator Cold Weather Reliability Event to be when the dry-bulb temperature was above the generator’s stated minimum operating temperature in R3 and not at or above the Extreme Cold Weather Temperature.  Requiring a CAP for freezing issues below an already stated capability would only create additional administrative burden with no reliability benefit.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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Constellation specifically notes support for the use of percentiles in the definition of Extreme Cold Weather Temperature, and support for the use of the term "apparent" in the definition Generator Cold Weather Reliability Event.

 

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

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Constellation specifically notes support for the use of percentiles in the definition of Extreme Cold Weather Temperature, and support for the use of the term "apparent" in the definition Generator Cold Weather Reliability Event.

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

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“Generator Cold Weather Critical Component” introduces more confusion than it alleviates. For example, what is the definition of “associated fixed fuel supply components”?

“Extreme Cold Weather Temperature” introduces unnecessary complexity and undue administrative burdens that do not lead to improved reliability. Reclamation recommends the initial proposal of using the coldest temperature back to 1/1/1975 was less confusing and less of an administrative burden than requiring entities to calculate the lowest .2 percentile of hourly temperatures. For example, climatological data from NOAA can only be processed 10 years at a time. For this timeframe, the file is over 55MB in size. Reclamation observed that following the NERC instructions and using a 10-year period of data took over an hour to filter and get the required data. Additionally, the data for several facilities only goes back to 2005, which will limit how much data some facilities can obtain and will automatically result in non-compliance with the proposed required analysis. Other searches yielded a longer period of available data, but from NOAA stations that were not near the facility in question (e.g., 100 miles away) or included major elevation changes (e.g., over 3000 feet and different weather patterns). These discrepancies will result in inaccurate data affecting the relevance of the calculations and again call into question the complicated structure of the proposed calculation method. Reclamation recommends the SDT account for these impacts to reliability as well as the ability to comply with the proposed requirements.

“Generator Cold Weather Reliability Event” introduces unnecessary complexity and provides loopholes for entities to circumvent solutions to the root causes of the cold weather problem FERC is attempting to solve. Reclamation recommends the specification of “10% of total capacity” is unnecessary. The focus should be on whether the derate aggregates to a total exceeding the MW threshold.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

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Generator Cold Weather Critical Component

The definition of Generator Cold Weather Critical Component does not line up with the team’s responses to comments.  The proposed definition in the standard is open to interpretation and inconsistent application because it can be read to include equipment that is not listed in the response to comments.  NRG proposes the SDT include the list of equipment in the standard definition.

 Extreme Cold Weather Temperature

NRG is grateful the SDT simplified the ability for generators to meet these requirements with the latest definition of Extreme Cold Weather Temperature.

However, NRG understands that to meet and validate the Extreme Cold Weather Temperature (ECWT), some units will be required to perform a full reverse-engineering of identified critical systems.  This would essentially require removing existing cold weather protection then installing new enhanced protection on these systems to meet the new requirements. The incremental cost differential by doing this instead of simply adding protection onto existing equipment could be cost prohibitive at some sites.

The definition does not include clarification on accepted data sources for determining extreme temperature. NRG suggests this should be extracted from the newly developed guidance document and inserted into the standard.

 NRG believes that this minimum temperature level should be based upon historical operational performance or design criteria.

 NRG would accept the proposed ECWT definition provided technical, commercial, and operational constraints are accepted under R7.

 Generator Cold Weather Reliability Event

The definition of Generator Cold Weather Reliability Event is not clear regarding what constitutes an apparent cause.  Is this due only to freezing equipment at the generator site?  There are many other actual causes for generator derates or start-up failures where freezing equipment may not be the actual cause or simply play a limited role.  This should be clarified.

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

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Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

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Generator Cold Weather Critical Component

The definition of Generator Cold Weather Critical Component does not line up with the team’s responses to comments.  The proposed definition in the standard is open to interpretation and inconsistent application because it can be read to include equipment that is not listed in the response to comments.  NRG proposes the SDT include the list of equipment in the standard definition.

 

Extreme Cold Weather Temperature

NRG is grateful the SDT simplified the ability for generators to meet these requirements with the latest definition of Extreme Cold Weather Temperature.

 

However, NRG understands that to meet and validate the Extreme Cold Weather Temperature (ECWT), some units will be required to perform a full reverse-engineering of identified critical systems.  This would essentially require removing existing cold weather protection then installing new enhanced protection on these systems to meet the new requirements. The incremental cost differential by doing this instead of simply adding protection onto existing equipment could be cost prohibitive at some sites.

 

The definition does not include clarification on accepted data sources for determining extreme temperature. NRG suggests this should be extracted from the newly developed guidance document and inserted into the standard.

 

NRG believes that this minimum temperature level should be based upon historical operational performance or design criteria.

 

NRG would accept the proposed ECWT definition provided technical, commercial, and operational constraints are accepted under R7.

 

Generator Cold Weather Reliability Event

The definition of Generator Cold Weather Reliability Event is not clear regarding what constitutes an apparent cause.  Is this due only to freezing equipment at the generator site?  There are many other actual causes for generator derates or start-up failures where freezing equipment may not be the actual cause or simply play a limited role.  This should be clarified.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

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“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

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BHC agrees with comments submitted by EEI & NAGF.

Claudine Bates, Black Hills Corporation, 6, 8/31/2022

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BHC agrees with comments submitted by EEI & NAGF.

Josh Combs, Black Hills Corporation, 3, 8/31/2022

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BHC agrees with comments submitted by EEI & NAGF. 

Micah Runner, Black Hills Corporation, 1, 8/31/2022

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BHC agrees with comments submitted by EEI & NAGF

Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

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LADWP proposes the following recommendations for the definitions of “Generator Cold Weather Critical Component” and “Generator Cold Weather Reliability Event”.

  • For the definition of “Generator Cold Weather Critical Component” LDWP proposes to update the definition as seen below. This revision provides a concise and objective definition.

 “Any generating unit component or associated fixed fuel supply component, that is under the Generator Owner’s control and is susceptible to freezing issues. the occurrence of which would likely lead to a Generator Cold Weather Reliability Event. 

 

  • Provide clarification for the definition of “Generator Cold Weather Reliability Event” specifically for event 3. As currently written the definition implies the time of the event would be at the temperature of Extreme Cold Temperature or warmer. If event 3 is referring to freezing temperatures meaning colder than the Extreme Cold Weather Temperature, event 3 under this definition should be revised as follows:

 

“(3) a Forced Outage, for which the apparent cause(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above below the Extreme Cold Weather Temperature.”

 

 

Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

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For Generator Cold Weather Reliability Event, PNM recommends adding to (1) the cause of derate is within the “freezing of equipment within the Generator Owner’s control”.  This would be similar to the statement in (3).

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

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We are concerned that the definition of Extreme Cold Weather Temperature will not capture the lower temperatures experienced in February 2021 (the Event).  Even if the temperatures experienced during the Event are considered outliers,  we do not believe that they should be removed from the dataset.  The frequency or intensity of these extreme temperatures occurring in the future may be probabilistically low, but cannot be discounted.  If NERC wants the new Standard to address temperatures like those experienced in February 2021, the ECWT definition must yield a result lower than the current definition.

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

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LCRA provides the following comments:

The Extreme Cold Weather Temperature definition differs from the language/method in the Public Utility Commission of Texas Project No. 53401 to define the minimum temperature at which a resource is reasonably expected to ensure sustained operation.

LCRA offers the following revisions to events 1 and 2 of the Generator Cold Weather Reliability Event definition:

(1) a forced derate of more than 10 of the seasonally adjusted High Sustainable Limit (HSL) of the unit and exceeding 20 MWs for longer than four hours in duration;

(2) a start-up failure where the unit fails to synchronize within the Balancing Authority’s specified start-up time; or”

James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

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The definition of "Extreme Cold Weather Temperature"--though an improvement over the cold weather standard in the previous version of EOP-012, which required continuous operations at the documented lowest hourly temperature experienced at the particular location since Jan. 1, 1975--remains problematic and could exacerbate resource adequacy challenges facing the nation (particularly in the Texas Reliability Entity, Inc. (TRE) region), without actually improving reliability outcomes—i.e., if the costs to achieve these standards prove substantial, the adoption of the standards could contribute to early retirements or cancellations or delays of planned resources, which could harm long-term resource adequacy and thus reliability. The new proposal is still extremely conservative, effectively equating to a 99.8th percentile coldest hourly temperature experienced at the applicable weather station for a resource since 2000, during the months of December, January, and February—in other words, a temperature that is colder than the temperature experienced in 99.8 percent of the total hours studied. In the draft Technical Requirements document (NERC’s Calculating Extreme Cold Weather Temperatures), the 0.2 percentile lowest temperature for the example weather station was 2 degrees Fahrenheit, which apparently had occurred in only 11 hours in the study period (dating back to January 1, 2000), and those 11 hours seemingly were not contiguous.

 

A requirement for new resources to operate for 12 consecutive hours, and existing resources to operate for 1 continuous hour, at a temperature experienced so few times in the past 22 years could require the Generator Owner to make significant capital expenditures (e.g., depending on the design specifications of the resource and depending on whether the SDT clarifies the meaning of “freeze protection measures” as recommended by Vistra under Question 5) to prepare for an extremely unlikely future occurrence, without any way for the Generator Owner to recoup the costs. The proposed definition and the accompanying standard based on that definition for new resources (R1) seems especially unworkable and unreasonable, as it would require new resources to operate for 12 consecutive hours at a temperature that would have occurred for one hour on only a handful of (apparently separate) occasions over the past two decades—in other words, new resources would be required to prove they could operate in conditions that have apparently never occurred, at least during the lookback period (i.e., while the temperature would have reached the Extreme Cold Weather Temperature for 1-hour periods at least a few times since 2000, it is unlikely that the Extreme Cold Weather Temperature would have occurred for 12 consecutive hours since 2000).  In lieu of making those unrecoverable expenditures in an attempt to prepare their resource to operate in speculative future extended extreme cold temperatures, investors may forego or cancel resource additions. Similarly, an existing Generator Owner that cannot operate for one hour at its Extreme Cold Weather Temperature may decide to retire early in lieu of making significant expenditures to attempt to operate at that temperature for one hour in the future.

 

Notably, the new proposal is far more conservative than the proposed extreme weather standard under consideration for the TRE region, by the Public Utility Commission of Texas (PUCT). In a pending rulemaking, the PUCT has proposed an extreme cold weather standard based on sustaining operations at either the 95th percentile minimum average 72-hour temperature as published in a recurring study by the balancing authority (which will be filed every 5 years and will examine weather outcomes dating back over 100 years) or the lowest ambient temperature at which the particular resource has experienced sustained operations. While Vistra has urged the PUCT to not adopt the alternative "lowest ambient temperature" standard for a variety of reasons (notably that it may effectively override the 72-hour average standard and impose different weather standards for different resources), and while the PUCT has yet to adopt its final rule establishing its standards, Vistra believes the intent of the “lowest temperature” standard proposed by the PUCT is actually to require resources to maintain weatherization measures that go above and beyond the standard, rather than to supplant the 72-hour average standard. In any event, the PUCT’s proposed “lowest temperature” standard would still be preferable to the 0.2 percentile standard proposed by the SDT, since the PUCT standard would take into account the resource’s demonstrated capabilities, not require it to sustain operations at a temperature at which it has never sustained operations, and not require new resources to sustain operations at that temperature for durations and in compounding weather conditions that are extremely unlikely to have any historical precedent.

 

Vistra urges the SDT to reconsider the proposed 0.2 percentile lowest hourly temperature since Jan. 1, 2000 in favor of something closer to the PUCT standard, i.e., either an average lowest ambient temperature (at the 95th or even 99th percentile) over a specified number of hours (e.g., 12 hours, 24 hours, 72 hours, etc.) since a specified date (e.g., Jan. 1, 2000) or a standard based on actual operations (for existing resources) or design specifications (for new or existing resources). If the SDT were to redefine “Extreme Cold Weather Temperature” to incorporate an average lowest ambient temperature, then the NERC guide for Calculating Extreme Cold Weather Temperature would also need to be modified to develop a methodology for calculating that temperature, or alternatively, the balancing authority for each region (e.g., ERCOT for the TRE region) could be responsible for publishing the applicable average temperatures on some periodicity (e.g., every five years). It may be preferable to have the balancing authority publish that data periodically, since that provides a common reference point for all resources operating in the region.  

 

The definition of “Generator Cold Weather Reliability Event” also should be clarified in a couple of ways. First, the phrase that begins “for which the apparent cause(s)” should be moved up to clarify that it modifies all three paragraphs of the definition (i.e., relating to (1) derates, (2) start-up failures, and (3) forced outages), rather than appearing directly at the end of paragraph (3) without any paragraph break, which could provide the impression that it only modifies that last paragraph. In addition, the definition for paragraph (2) (relating to start-up failures) should be modified to clarify that the term “start-up failure” will have the same meaning that it does for purposes of Generating Availability Data System (GADS) reporting. For instance, the definition could be modified to state that “Generator Cold Weather Reliability Event” means:

 

“One of the following events, if the apparent cause(s) of that event(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above the Extreme Cold Weather Temperature:

(1) a forced derate of more than 10% of the total capacity of the unit and exceeding 20 MWs for longer than four hours in duration;

(2) a start-up failure where the unit fails to synchronize within a specified start-up time, as defined in the instructions for mandatory reporting of startup failures in the Generating Availability Data System; or

(3) a Forced Outage.

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #2.

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

- 0 - 0

Exelon agrees with the proposed definitions. Exelon supports EEI's comments regarding the benefit of making clarifying enhancements to the definitions during the next phase of this project.  

 

Submitted on behalf of Exelon, Segments 1 & 3

Daniel Gacek, Exelon, 1, 9/1/2022

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SIGE is requesting the Standard Drafting Team consider the following recommendations:

For Generator Cold Weather Reliability Event:

  • As written, bullets 1 and 2 could apply at any time during the year. SIGE is proposing the addition of a qualify to define the applicability of bullets 1 and 2. Additionally, SIGE is proposing increasing 10% to 15% to allow larger units capacity for everyday variances:

Generator Cold Weather Reliability Event: One of the following events occurring when the ambient temperature is at or below 32 degrees

(1) a forced derate of more than 15% of the total capacity of the unit and or exceeding 20 MWs, whichever is greater,  for longer than four hours in duration;

(2) a start-up failure where the unit fails to synchronize within a specified start-up time; or

(3) a Forced Outage, for which the apparent cause(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above the Extreme Cold Weather Temperature

  • In alignment with EEI’s comment, SIGE is also voicing concern that use of the term “specified” in bullet 2 is unclear as to whom is responsible or what is determining the ‘specifying’ of the start-up time.

For Generator Cold Weather Critical Component, SIGE believes that the inclusion of the phrase “fixed fuel supply component” in the proposed definition is not clear and supports EEI’s proposed definition of “fixed fuel supply component”.

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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The Extreme Cold Weather Temperature definition differs from the language/method in the Public Utility Commission of Texas Project No. 53401 to define the minimum temperature at which a resource is reasonably expected to ensure sustained operation. 

LCRA offers the following revisions to events 1 and 2 of the Generator Cold Weather Reliability Event definition:

(1)   a forced derate of more than 10 of the seasonally adjusted High Sustainable Limit (HSL) of the unit and exceeding 20 MWs for longer than four hours in duration;

(2)   a start-up failure where the unit fails to synchronize within the Balancing Authority’s specified start-up time; or”

Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

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Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

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Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

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The definition of "Extreme Cold Weather Temperature"--though an improvement over the cold weather standard in the previous version of EOP-012, which required continuous operations at the documented lowest hourly temperature experienced at the particular location since Jan. 1, 1975--remains problematic and could exacerbate resource adequacy challenges facing the nation (particularly in the Texas Reliability Entity, Inc. (TRE) region), without actually improving reliability outcomes—i.e., if the costs to achieve these standards prove substantial, the adoption of the standards could contribute to early retirements or cancellations or delays of planned resources, which could harm long-term resource adequacy and thus reliability. The new proposal is still extremely conservative, effectively equating to a 99.8th percentile coldest hourly temperature experienced at the applicable weather station for a resource since 2000, during the months of December, January, and February—in other words, a temperature that is colder than the temperature experienced in 99.8 percent of the total hours studied. In the draft Technical Requirements document (NERC’s Calculating Extreme Cold Weather Temperatures), the 0.2 percentile lowest temperature for the example weather station was 2 degrees Fahrenheit, which apparently had occurred in only 11 hours in the study period (dating back to January 1, 2000), and those 11 hours seemingly were not contiguous.

A requirement for new resources to operate for 12 consecutive hours, and existing resources to operate for 1 continuous hour, at a temperature experienced so few times in the past 22 years could require the Generator Owner to make significant capital expenditures (e.g., depending on the design specifications of the resource and depending on whether the SDT clarifies the meaning of “freeze protection measures” as recommended by Vistra under Question 5) to prepare for an extremely unlikely future occurrence, without any way for the Generator Owner to recoup the costs. The proposed definition and the accompanying standard based on that definition for new resources (R1) seems especially unworkable and unreasonable, as it would require new resources to operate for 12 consecutive hours at a temperature that would have occurred for one hour on only a handful of (apparently separate) occasions over the past two decades—in other words, new resources would be required to prove they could operate in conditions that have apparently never occurred, at least during the lookback period (i.e., while the temperature would have reached the Extreme Cold Weather Temperature for 1-hour periods at least a few times since 2000, it is unlikely that the Extreme Cold Weather Temperature would have occurred for 12 consecutive hours since 2000).  In lieu of making those unrecoverable expenditures in an attempt to prepare their resource to operate in speculative future extended extreme cold temperatures, investors may forego or cancel resource additions. Similarly, an existing Generator Owner that cannot operate for one hour at its Extreme Cold Weather Temperature may decide to retire early in lieu of making significant expenditures to attempt to operate at that temperature for one hour in the future.

Notably, the new proposal is far more conservative than the proposed extreme weather standard under consideration for the TRE region, by the Public Utility Commission of Texas (PUCT). In a pending rulemaking, the PUCT has proposed an extreme cold weather standard based on sustaining operations at either the 95th percentile minimum average 72-hour temperature as published in a recurring study by the balancing authority (which will be filed every 5 years and will examine weather outcomes dating back over 100 years) or the lowest ambient temperature at which the particular resource has experienced sustained operations. While Vistra has urged the PUCT to not adopt the alternative "lowest ambient temperature" standard for a variety of reasons (notably that it may effectively override the 72-hour average standard and impose different weather standards for different resources), and while the PUCT has yet to adopt its final rule establishing its standards, Vistra believes the intent of the “lowest temperature” standard proposed by the PUCT is actually to require resources to maintain weatherization measures that go above and beyond the standard, rather than to supplant the 72-hour average standard. In any event, the PUCT’s proposed “lowest temperature” standard would still be preferable to the 0.2 percentile standard proposed by the SDT, since the PUCT standard would take into account the resource’s demonstrated capabilities, not require it to sustain operations at a temperature at which it has never sustained operations, and not require new resources to sustain operations at that temperature for durations and in compounding weather conditions that are extremely unlikely to have any historical precedent.

 

Vistra urges the SDT to reconsider the proposed 0.2 percentile lowest hourly temperature since Jan. 1, 2000 in favor of something closer to the PUCT standard, i.e., either an average lowest ambient temperature (at the 95th or even 99th percentile) over a specified number of hours (e.g., 12 hours, 24 hours, 72 hours, etc.) since a specified date (e.g., Jan. 1, 2000) or a standard based on actual operations (for existing resources) or design specifications (for new or existing resources). If the SDT were to redefine “Extreme Cold Weather Temperature” to incorporate an average lowest ambient temperature, then the NERC guide for Calculating Extreme Cold Weather Temperature would also need to be modified to develop a methodology for calculating that temperature, or alternatively, the balancing authority for each region (e.g., ERCOT for the TRE region) could be responsible for publishing the applicable average temperatures on some periodicity (e.g., every five years). It may be preferable to have the balancing authority publish that data periodically, since that provides a common reference point for all resources operating in the region.  

The definition of “Generator Cold Weather Reliability Event” also should be clarified in a couple of ways. First, the phrase that begins “for which the apparent cause(s)” should be moved up to clarify that it modifies all three paragraphs of the definition (i.e., relating to (1) derates, (2) start-up failures, and (3) forced outages), rather than appearing directly at the end of paragraph (3) without any paragraph break, which could provide the impression that it only modifies that last paragraph. In addition, the definition for paragraph (2) (relating to start-up failures) should be modified to clarify that the term “start-up failure” will have the same meaning that it does for purposes of Generating Availability Data System (GADS) reporting. For instance, the definition could be modified to state that “Generator Cold Weather Reliability Event” means:

“One of the following events, if the apparent cause(s) of that event(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above the Extreme Cold Weather Temperature:

(1) a forced derate of more than 10% of the total capacity of the unit and exceeding 20 MWs for longer than four hours in duration;

(2) a start-up failure where the unit fails to synchronize within a specified start-up time, as defined in the instructions for mandatory reporting of startup failures in the Generating Availability Data System; or

(3) a Forced Outage

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

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The defined Extreme Cold Weather Temperature does not result in a temperature that would cause a Generator Cold Weather Reliability Event (as defined by this standard). It should be no higher than the lowest historically recorded temperature for the region.

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

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AES Clean Energy supports comments submitted by NAGF. 

Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

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The NAGF agrees with creation of the definitions. The NAGF has concerns with the proposed definitions as written.

  • The definition of Generator Cold Weather Reliability Event is not clear. Use of the word “apparent” in the definition has the potential to cause disagreements during an audit due to the multiple meanings of the word. It would be better to use a word that has a consistent definition rather than a word with multiple different meanings. Synonyms for apparent include assumed, evident, ostensible, ostensive, presumed, prima facie, putative, reputed, seeming, supposed. Based on this list of words, if an auditor assumes that an outage was caused by freezing based on the timing of the outage the auditor would be correct to expect a CAP for that event. (As written, an auditor can take the position any outage that is assumed to be caused by freezing requires a CAP to be created. Then the CAP must either be implemented, or a declaration made that the CAP will not be implemented.) While we do not believe this is the intent of the SDT, the NAGF asks the SDT to address this potential conflict by replacing the word apparent with a word that provides clearer intent.
  • The Generator Cold Weather Reliability Event uses the term “freezing of equipment” and Generator Cold Weather Critical Component uses “susceptible to freezing issue” without clearly defining what is meant. While the SDT has spent a significant amount of time discussing what they mean by freezing, that discussion does not appear to be captured well in this documentation. The NAGF recommends that this issue be clearly explained to ensure that all entities understand what issues are to be addressed.
  • The SDT has used the Extreme Cold Weather Temperature in the definition of Generator Cold Weather Reliability Event which will cause a Generator Owner to do a CAP under R6. This definition should instead use the term “generator minimum operating temperature as identified in the cold weather plan” to better address reliability. The NAGF agrees with the Technical Rationale document that using the Extreme Cold Weather Temperature treats everyone equally. However, in this case, treating everyone equally does not address the reliability concerns raised in the Joint Inquiry Report. The NAGF explain this position in more detail under question 8.

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

- 0 - 0

ECWT: The EOP-012 standard as written would not have mitgated much of the events that happened during Feb 2021 in the Southern US.  It looks like the Standard is written to ensure that Generators are able to operate to the “normal” experienced low temperatures experienced during the winter months.  The ECWT definition does not address the “Extreme” cold weather. It specifies something that sounds good, but in reality leaves the “equipment freezes” door wide open: the criterion is that fixed portions of cold-weather sensitive equipment should not freeze when exposed to 0.2% of the coldest winter hours in the past 20 years.  To give an example: Dallas, TX got down to -2degF for quite a while during storm Uri – the standard requires protection down to 14degF.  This means that for the Dallas area, this standard would have minimal influence during a similar extreme event.

ISO-NE supports the recommendation from the SRC Comments that the Standard should consider a period of sustained cold temperatures (e.g., the average of the lowest recorded six hours at a given location) as the ECWT.

 

GCWRE: Additionally, the term Generating unit is vague and is open to interpretation.  Does this mean each generating unit or is it an entire facility.  Depending on the interpretation of unit by a GO, they could declare each unit separate in the large plant with many units which could preclude them from the applicability section of this standard as well as exempt form the CAP requirements outlined in Requirement 6.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

The definition for Extreme Cold Weather Temperature seems overly complicated and will require a lot of data crunching to reach a number that could be attained by looking at lowest recorded temperature in each year, without having to retrieve hourly data and perform statistical analysis.

LES, Segment(s) 6, 1, 3, 5, 10/8/2018

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NPPD agrees with the definition of  as proposed, with the following exceptions:

Cold Weather Reliability Event definition: we request the definition be modified to the following: “(1) a forced derate of more than 10% of the Facility Rating of the unit and exceeding 20 MWs for longer than four hours in duration;”. We believe the basis should be the Facility Rating of the generator rather than the capacity. We believe this modification would provide additional clarity and provide for a more accurate calculation.

Extreme Cold Weather Temperature definition: historical hourly temperature data for many project locations is nonexistent. Several entities have considered National Weather Service data from small airports, but these stations can be many miles away from the facility locations. We request modification to the language in the definition to the effect of, “the closest NWS site data is adequate for calculating this temperature (ECWT)”. Also, NPPD requests the SDT consider changing the beginning date of records for the Extreme Cold Weather Temperature from 1/1/2000 to 1/1/2005. While there is certainly temperature data on the NOAA NCEI website for most airports located near large population centers that goes back to the 1/1/2000 date, there is abundantly more data available for some more remote areas starting in 2005. This would help entities obtain a more accurate temperature for the local area that generators may be in, which for some facilities may be quite remote and several hundred miles away from any major population area.

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

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  • Generator Cold Weather Reliability Event

The MRO NSRF disagrees with the definition of Generator Cold Weather Reliability Event as written.  We believe that 10% of the total capacity and exceeding 20MW is far too low for many generating units. The MRO NSRF appreciates the Standard Drafting Teams (SDT) adding the “and exceeding 20MW” prose for a Generator Cold Weather Reliability Event.  However, we would suggest tying the magnitude back to a reliability concept such as the BES Definition: 75MVA/20MVA.  The simple reasoning is that for a 100MVA facility identified under Inclusion I4 of the BES Definition, a  derate of 10% (10MVA) and 20MW would not constitute a reliability concern as it does not even meet the thresholds to be BES for generation facilities identified under inclusion I4. Given that, the MRO NSRF believes the threshold for a Generator Cold Weather Reliability Event as currently proposed is adding an undue administrative burden without a clear increase in reliability.

The MRO NSRF suggests the following language modification to this Definition:

Generator Cold Weather Reliability Event - One of the following events, for which the apparent cause(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above the Extreme Cold Weather Temperature:

(1) a forced derate of:

  • 10% or greater than or equal to 20MVA of the Facility Rating, whichever is greater, for generating units identified under Inclusion I2 of the BES definition

or

  •      10% or greater than or equal to 75MVA of the Facility Rating, whichever is greater, for generating units identified under Inclusion I4 of the BES definition

for longer than four hours in duration;

(2) a start-up failure where the generating unit fails to synchronize within a specified start-up time;

or

(3) a Forced Outage.

If the current ballot gains approval without changes to the proposed language of the Standard, the MRO NSRF would like to suggest addressing the afforemention comments in a future phase of this project. 

  • Extreme Cold Weather Temperature

Regarding Extreme Cold Weather Temperature, the MRO NSRF would like to thank the SDT for the changes incorporated from Draft 1 to Draft 2. While we appreciate the effort to reduce the burden on Generator Owner and Generator Operators to evaluate the Extreme Cold Weather Temperature, we disagree with the proposed definition for several reasons. First, the MRO NSRF would suggest the SDT to work with the National Oceanic and Atmospheric Administration (NOAA), National Weather Service (NWS), team members of the FERC, NERC and Regional Entity Staff Report to develop the appropriate percentile this definition will require Generator Owners and Generator Operators to meet in Requirements R1 and R2. Within the technical rationale, the SDT states “select the 0.2 percentile of winter month temperatures since 1/1/2000 to identify a temperature which has been rarely surpassed, but which allows some margin for a Generator Owner to have previously demonstrated successful operation”.  While we agree with a statistical approach, we cannot support the level of 0.2 percentile without a scientific and statistical analysis to determine if 0.2 is appropriate.

As it relates to the portion of the of the definition that states “from 1/1/2000 through the date the temperature is calculated”, the MRO NSRF suggests two items. First, confer with the members from NOAA, NWS and ECCC to confirm that keeping 1/1/2000 as the baseline date is appropriate (for example, not dropping the oldest 5 year period for each new calculation) or if it should be on a latest 15, 20, 30 winter season basis. Secondly, the way the current language is proposed, in conjunction with requirement R4, we are concerned of an overlap between the effective date of the standard and implementation date of the requirement could cause inadvertent confusion as to when to calculate the winter season temperature. For example, if the effective date of the standard is 1/1/2023, does an entity calculate the Extreme Cold Weather Temperature to 12/31/2022? Therefore, the MRO NSRF proposes to clarify “through the date the temperature is calculated” to “through the end of the previous winter season of the date the temperature is calculated”.  

The MRO NSRF requests clarification on data souce location. Historical hourly temperature data for many project locations is nonexistent. Several of our members have considered National Weather Service data from small airports, but these stations can be many miles away from the project locations. The NSRF requests modification to the language in the definition to the effect of, “the closest NWS site data is adequate for calculating this temperature (ECWT)”.

Additionally, the MRO NSRF request the SDT consider changing the beginning date of records for the Extreme Cold Weather Temperature from 1/1/2000 to 1/1/2005. While there is certainly temperature data on the NOAA NCEI website for most airports located near large population centers that goes back to the 1/1/2000 date, there is abundantly more data available for some more remote areas starting in 2005. This would help entities obtain a more accurate temperature for the local area that generators may be in, which for some generation facilities such as wind or solar farms may be quite remote and several hundred miles away from any major population area.

In consideration of this data calculation, perhaps NERC can work with NOAA’s National Climatic Data Center (NCDC) on setting up this data for download for industry members. In the June 2013 issue of the Bulletin of the American Meteorological Society, “Alternative Climate Normals: Impacts to the Energy Industry”, the article states that NCDC has been expanding its “proactive engagement” with various sectors and has analyzed what data the energy sector requires for climate normals. To ensure Generator Owners and Generator Operators are using the same data, the NSRF would like to propose that NERC and NCDC develop a data set so industry members do not have to manipulate large sets of data. The winter season data set will be over 2,000 data points and currently as proposed over a 20 year span. Forward looking, this data manipulation will require an abundance of resources to complete for new and existing generation resources.

Alternative Climate Normals: Impacts to the Energy Industry in: Bulletin of the American Meteorological Society Volume 94 Issue 6 (2013) (ametsoc.org)

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

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How is the BA held responsible for determining what is considered the “winter season”? EOP-012-1 section 4.2 lacks clarity and there are no requirements concerning this responsibility, nor is it mentioned in the TR.

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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MidAmerican Energy supports the EEI and NSRF comments for this question. We would also expound on NSRF’s comments that one location’s weather data would mean over 175,000 points of data. 

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

- 0 - 0

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

- 0 - 0

The term Generator is not clearly defined. Please refer to our comments in question #4 and #5. EDF supports the comments of NAGF and EEI.

Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

- 0 - 0

Generator Cold Weather Reliability Event - In (1), (2), and (3), change “unit” to “unit or combined cycle block”.

The event descriptions do not specifically indicate events relating to freezing.

Suggested change:

              (1) a forced derate due to freezing equipment, which results in more than 10% of the total capacity of the unit and exceeding 20 MWs for longer than four hours in duration

(2) a start-up failure where the unit fails to synchronize within a specified start-up time due to freezing equipment.

 

On a temperature related note, unless there has been some analysis of historical data to substantiate it, imposing the 20mph wind assumption on top of the temperature requirement will likely cause plants to design for a theoretical weather condition that has never existed.  Given the costs and challenges involved with this effort, we should not be basing design on arbitrary assumptions.

 

Also relating to temperature, “Design temperature”, “historical operating temperature”, or “current cold weather performance temperature” do not have a practical meaning for wind turbines with respect to cold weather reliability.    Wind turbines are often rated to perform at extremely low temperatures.   The reliability issue is icing “conditions” which usually happen at temperatures much higher than the lowest rated temperature.   Icing conditions are related to a combination of temperature and moisture vs a specific low temperature.  Additionally, there is no known technology that reliably mitigates all icing concerns.

Mark Young, Tenaska, Inc., 5, 9/1/2022

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The definition of  Generator Cold Weather Reliability Event, item 1 is not entirely clear. Is the intent to exclude derates equal to 20MW ( if they are more than 10%) or equal to 10% of total unit capacity ( when more than 20MW)? Suggest rewording to : a forced derate exceeding 10% of the total capacity of the unit but no less than 20 MW for longer than four hours in duration;" 

Imane Mrini, Austin Energy, 6, 9/1/2022

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MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC). In addition, we are submitting comments on behalf of MISO as an individual entity.

In analyzing the proposed Extreme Cold Weather Temperature, MISO discovered that it doesn’t go far enough to capture many of the hours in recent major cold weather events, including Winter Storm Uri (February 2021), South Central Cold Weather Event (January 2018) and the Polar Vortex (January 2014). Without an adequate temperature definition, the standard will not achieve its intended outcome or provide a measurable reliability benefit as the balance of winterization requirements hinge upon the adequacy of this definition.

The current Extreme Cold Weather Temperature (ECWT) definition sets “the temperature equal to the lowest 0.2 percentile of the hourly temperatures measured in December, January, and February from 1/1/2000 through the date the temperature is calculated.”

In analyzing the proposed definition, we found that the lowest 0.2 percentile is insufficient to capture many of the hours in past extreme events (see detailed analysis below). Therefore, we recommend the SDT modify the percentile. One option is to model this threshold after an established industry percentile; e.g. the Loss of Load Expectation (LOLE) which is equivalent to one day in ten years. This equates to:

LOLE = 1 day/(10 years x 365 days/year) = 0.000274 or 0.0274 percentile almost 10 times less than the current benchmark.

In contrast, the current 0.2 percentile in the ECWT definition equates to:

ECWT = 1 day/(0.002 x 365 days/year) = 1 day every 1.37 years which indicates a need to plan for a loss of load expectation (LOLE) on an almost annual or yearly basis.

Planning to shed load in support of a major event on an annual basis fails to adequately address the findings from past major events and will not provide measurable reliability benefits. Therefore, MISO recommends the SDT adopt a more stringent percentile such as that for LOLE (of 0.0274) in determining the Extreme Cold Weather Temperature definition.

Using a smaller percentile also has the added benefit of addressing Generator Owner concerns that the definition not be based on the single coldest hour experienced; but rather a temperature for which has been realized on multiple occasions over a period of time.

MISO Temperature Analysis

To evaluate the adequacy of the Extreme Cold Weather Temperature definition, MISO examined two cities in its footprint - Lake Charles, Louisiana (LCH) and Little Rock, Arkansas (LIT) – both of which were adversely affected during the Winter Storm Uri (February 2021) event.

For LCH, the proposed ECWT would be 24.98° F. When reviewing the hourly data from December 1991 to February 2022, 206 hours meet or fall below that ECWT over thirty-eight days and twenty-five events. LCH also had sixteen hours (16) during Winter Storm Uri the proposed ECWT would exclude.

The proposed ECWT for LIT is 12.92° F. In the hourly data from December 1991 to February 2022, 183 hours meet or fall below that ECWT over thirty-two days and twenty-one events. LIT also had fifty-seven (57) hours during Winter Storm Uri the proposed ECWT would exclude.

In light of the foregoing, the SRC recommends using a fifty year look back period (replacing the year 2000 with the year 1972). The SRC also recommends striking the 0.2 percentile entirely or, at least, changing it to the 0.02 percentile so the resulting ECWT more accurately reflects extreme cold temperatures.

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

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Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

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Madison Gas and Electric supports the comments from the MRO NSRF.

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

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Madison Gas and Electric supports the comments of the MRO NSRF

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

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The current definitions as written leave ample room for interpretation. While this is often desired, we believe that in this instance they do not provide enough clarity to the requirements of EOP-012. The specific concerns with the current verbiage are as follows:

Generator Cold Weather Critical Component: While the open-endedness of “any generating unit component” is desired in that it allows the GO to identify critical components on a per-unit basis, it does not appear to include any “common” equipment shared between units. Examples would include service water, instrument air, ammonia, ash handling, common bus isolation breakers/switches, etc.

The proposed modification to the definition is: “Any generating unit component or associated fixed fuel supply component, to include any critical equipment shared between multiple units (i.e. Balance of Plant (BOP) and/or Common equipment), that is under the Generator Owner’s control and is susceptible to freezing issues, the occurrence of which would likely lead to a Generator Cold Weather Reliability Event.”

Extreme Cold Weather Temperature: The flexibility and intent behind using the “lowest 0.2 percentile” is greatly appreciated; however, the requirement to use “the hourly temperatures measured” seems a bit excessive. Given the inherent difficulty of compiling a dataset containing greater than 49,000 data points and then calculating the lowest 0.2 percentile, we recommend modifying the definition to include daily minimum temperatures from the same time period. This modification would reduce the size of the dataset significantly (down to ~2076 total days) and should not change the resulting Extreme Cold Weather Temperature by any significant statistical margin given that the daily minimum will contain the hourly minimums.

Lastly, the requirement to use a fixed data start date of 01/01/2000 means the dataset will grow by approximately 2,160 data points if using the hourly metric while only 90 data points if using the daily minimum metric. Therefore, it is our recommendation to use a 20-year rolling time period if staying with the hourly metric.

 

If the hourly metric is to remain, a proposed modification to the definition would be:  “The temperature equal to the lowest 0.2 percentile of the actual hourly temperatures measured in December, January, and February from the previous 20 years immediately prior to the date the temperature is calculated. “

The preferred modification would be to abandon the hourly metric in favor of the daily minimum metric. Thus the preferred proposed modification to the definition is: “The temperature equal to the lowest 0.2 percentile of the actual daily minimum temperatures measured in December, January, and February from 1/1/2000 through the date the temperature is calculated.”

Generator Cold Weather Reliability Event: Pertaining to event type 2 that may constitute a Generator Cold Weather Reliability Event (GCWE):

2.  “A start-up failure where the unit fails to synchronize within a specified start-up time”: Who specifies the start-up time? Per the draft Technical Rationale and Justification for EOP-012-1, start-up failures are defined using a modified version of the GADS definition in order to ensure consistency across all jurisdictions for this standard. Our concern stems from the language in R2 that references the GADS definition of “specified start-up time” without providing the additional clarification found in the 2022 GADS Data Reporting Instructions. Our recommendation is to modify this subsection as follows: “A start-up failure where the unit fails to synchronize within a specified start-up time. The specified start-up time period for each unit is determined by the GO/GOP based on the condition of the unit at the time of start-up.”

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

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Invenergy does not agree with the definitions as currently drafted and offers the following recommendations.

Generator Cold Weather Reliability Event:  

As noted below in response to Question 6, Invenergy recommends setting the forced derate threshold in a manner consistent with NERC’s BES criteria, using a minimum of 20 MVA for individual generating units and a minimum of 75 MVA for dispersed power producing resources.

Invenergy proposes the following change to condition (1) of the definition:

(1)   A forced derate of:

  • More than 10% of the total capacity of the unit and exceeding 20 MVA for generating units identified under Inclusion I2 of the BES definition; or
  • More than 10% of the total capacity of the generating facility and exceeding 75 MVA for generating units identified under Inclusion I4 of the BES definition.

Additionally, Invenergy recommends removing the word “apparent” from the definition.

Extreme Cold Weather Temperature: 

The proposed definition improves on the previous draft by using a percentile instead of the single minimum hourly temperature and data starting on 1/1/2000 rather than 1/1/1975.

As Invenergy did in response to the first ballot, we propose that the methodology use a multi-day average temperature rather than hourly temperatures, and a reliability analysis-based percentile rather than the 0.2 proposed in the latest draft. Without endorsing the exact values proposed, we note the proposal by Commission Staff at the Public Utility Commission of Texas (see Project No. 53401, Electric Weather Preparedness Standards-Phase II, Memorandum and Proposal for Publication dated May 19, 2022) would be expected to yield a more reasonable requirement: “…the lesser of the minimum ambient temperature at which the resource has experienced sustained operations or the 95th percentile minimum average 72-hour temperature reported in ERCOT’s historical weather study…for the weather zone in which the resource is located.” (Emphasis added.)

To demonstrate the need for this alternative approach, consider solar generators. Under the SDT’s proposal, the calculation of the Extreme Cold Weather Temperature will be heavily influenced by colder nighttime temperatures, when there is no solar generation. Using a multi-day period would more reasonably set the minimum temperature standard for these facilities.

Finally, Generator Owners need additional detail on the mechanics of calculating the Extreme Cold Weather Temperature as it is presently defined. For example, if hourly temperature data back to 1/1/2000 at a Generator Owner’s nearest weather station(s) are unavailable, should the Generator Owner use only the data available at that station, or use an alternative station regardless of the distance from the facility? What fraction of the data from the nearest station must be missing before an alternative station is used?

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

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For the second item, the “specified time” is ambiguouse. If it is completely up to the generator operator, then is is not a standard. Perhaps the specified time could be required to be included in the Operating Plan or Data requirements of R3.

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/6/2022

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Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 9/1/2022

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Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 9/1/2022

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The proposed definition for Cold Weather Reliability Event uses the language “total capacity of the unit” which is vague and not defined in the NERC Glossary of Terms.  SMUD recommends that the language “Facility Rating of the unit” be used which is more specific and includes a NERC defined term that is referenced in other reliability standards.

SMUD / BANC, Segment(s) 3, 6, 1, 4, 5, 8/18/2022

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See comment for Question 1.  For Start Failure, the line should read, “a start-up failure where the unit fails to synchronize within a specified and scheduled start-up time.”  The addition of “and scheduled” makes it clear that a failed start resulting from a GO starting a unit on its own accord or during testing would not be reported as a failed start under the winterization program.

The definition of GCWRE should be clarified to state (changes are bold):

Generator Cold Weather Reliability Event: A failure of a Generator Cold Weather Critical Component that causes one of the following events:

(1) a forced derate of more than 10% of the total capacity of the unit and exceeding 20 MWs for longer than four hours in duration;

(2) a start-up failure where the unit fails to synchronize within a specified and scheduled  start-up time; or

(3) a Forced Outage, for which the apparent cause(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above the Extreme Cold Weather Temperature.

Furthermore, a component failure that occurs during a cold weather event but was not caused by the cold weather event should not fall under this Standard.  NERC should revise the Standard to make this clear.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

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EEI supports all three definitions for this first phase, but we also propose additional revisions to the Generator Cold Weather Critical Component and the Cold Weather Reliability Event because additional clarity is needed that can be addressed during the next phase of this project. (See below.) 

 

Generator Cold Weather Critical Component: Use of the undefined term “fixed fuel supply component” within the proposed definition of Generator Cold Weather Critical Component creates confusion.  While we support the explanation provided by the SDT in the Technical Rationale, the Technical Rationale has no standing as a compliance document.  For this reason, we recommend defining this term within the framework of the next phase of this project.  We suggest the following:

 

Fixed Fuel Supply Component: Are non-mobile equipment that support the reliable delivery of fuel to the generating unit and under the control the Generator Owner at a plant site. Gaseous, liquid, or solid fuel handling components that are installed on site as fixed parts of the fuel delivery system that are under the Generator Owner’s control would be included. Components that would not be included would be mobile equipment such as trains, bulldozers, or other equipment that are not fixed in one location.

 

Generator Cold Weather Reliability Event: EEI is concerned with the use of the term “specified”, as it relates to the start-up time of a generator during cold weather events, because it is unclear who would be responsible for specifying the start-up time.  Results Based Standards should “define a particular reliability objective or outcome to be achieved.  In its simplest form, a results-based requirement has four components: who, under what conditions (if any), shall perform what action, to achieve what particular result or outcome.” (NERC Results Based Standards – Performance Based; https://www.nerc.com/pa/Stand/Pages/ResultsBasedStandards.aspx#:~:text=Results%20based%20standards%20are%20standards,the%20NERC%20Standard%20Processes%20Manual.)

 

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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APS supports all three definitions for this phase. However, we support EEI’s proposed revisions to Generator Cold Weather Critical Component and Cold Weather Reliability Event during the next phase of the project.

Specifically, APS supports EEI’s proposal to add a definition for Fixed Fuel Supply Component to eliminate confusion within the Generator Cold Weather Critical Component definition. Additionally, APS agrees that within the Generator Cold Weather Reliability definition, the use of term “specified” as it relates to the start-up time of a generator during cold weather events is ambiguous, as it unclear who would be responsible for specifying the start-up time.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 9/1/2022

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While Cowlitz appreciates the effort so far, further improvements are needed. We agree with comments provided by the North American Generator Forum.

Russell Noble, Cowlitz County PUD, 3, 9/1/2022

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Alyssia Rhoads, Public Utility District No. 1 of Snohomish County, 1, 9/1/2022

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John Liang, Snohomish County PUD No. 1, 6, 9/1/2022

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Agree with comments provided by Russell Noble.

Deanna Carlson, Cowlitz County PUD, 5, 9/1/2022

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The SRC believes two definitions require revising, specifically:

1.  Extreme Cold Weather Temperature (ECWT): The SRC evaluated this temperature and found it is not low enough to capture the critical hours during cold weather periods, such as Winter Storm Uri, The South Central United States Cold Weather Event of January 17, 2018, The 2014 Polar Vortex, the February 2011 Southwest Cold Weather Event and the Cold Wave in January 1994.  The following information supports the request to lower the ECWT and cover events such as Winter Storm Uri.

The SDT apparently chose a “look back” date of the year 2000 based on statements on the NOAA website indicating it made some improvements in weather infrastructure around that time. That reason does not justify limiting the look back to 1/1/2000 and misinterprets the NOAA website language. The NOAA website notes it completed its “Modernization and Associated Restructuring” (MAR) effort in 2000. That effort, as the website describes, “modernized” its surface observational infrastructure by incorporating more automation. However, nothing in that effort changed the availability or quality of previous temperature data of NOAA (and its predecessor the National Weather Bureau).

During the NERC presentation on 8/16/22, the Standard Drafting Team (SDT) presented the ECWT for the Dallas, Texas area (12°F). The actual temperature in the Dallas area during Winter Storm Uri was -2°F.

Next, the PJM region experienced extremely cold conditions with a direct impact on reliability (through freezing of coal piles, canal locks and natural gas infrastructure) in 1994. The conditions at that time were the type of conditions the standard should address as they parallel those experienced during Winter Storm Uri. However, limiting the look back to the year 2000 would ignore even this relatively recent (1994) experience for determining ECWT in the PJM region.

The attached chart compares the impact of the proposed ECWT in the PJM region and illustrates how much the 0.2 percentile factor moves the requirement for winterization away from the actual temperature experienced. The results call into question the value of the 0.2 percentile factor. 

Some examples included in the chart (please reference additional data and details via the attached file) - all temperatures in degrees Farenheit:

Weather Station = Allentown Lehigh Valley International Airport; Minimum Temp = -9.75; 0.2 Percentile = -0.75; 0.02 Percentile = -6.00; and average lowest temperature over a six hour period = -7.50

Weather Station = Atlantic City International Airport; Minimum Temp = -12.50; 0.2 Percentile = 0.00; 0.02 Percentile = -7.50; and average lowest temperature over a six hour period = -8.33

Weather Station = Chicago O'Hare International Airport; Minumum Temp = -26.00; 0.2 Percentile = -14.00; 0.02 Percentile = -23.00; and average lowest temperature over a six hour period = -24.33

Further, MISO examined two cities in its footprint - Lake Charles, Louisiana (LCH) and Little Rock, Arkansas (LIT) - adversely affected during the February, 2021 event. For LCH, the proposed ECWT would be 24.98° F. When reviewing the hourly data from December 1991 to February 2022, 206 hours meet or fall below that ECWT over thirty-eight days and twenty-five events. LCH also had sixteen hours during Winter Storm Uri the proposed ECWT would exclude.

The proposed ECWT for LIT is 12.92° F. In the hourly data from December 1991 to February 2022, 183 hours meet or fall below that ECWT over thirty-two days and twenty-one events. LIT also had fifty-seven hours during Winter Storm Uri the proposed ECWT would exclude.

In light of the foregoing, the SRC recommends using a fifty year look back period (replacing the year 2000 with the year 1972). The SRC also recommends striking the 0.2 percentile entirely or, at least, changing it to the 0.02 percentile so the resulting ECWT more accurately reflects actual cold temperatures.

As an alternative to the addition of a percentile adjustment while avoiding requiring winterization to one extremely cold anomalous hour, the SRC recommends the SDT consider, as a viable alternative, defining the ECWT as a period of sustained cold temperatures (e.g., the average of the lowest recorded six hours at a given location). In short, the day would be divided into six hour blocks (e.g. midnight to 6AM, 6AM to noon, noon to 6PM and 6PM to midnight) with the average coldest temperature during those six hour blocks determine the ECWT. The table attached demonstrates the results for all these options. The SDT may need to do additional work in this area, however, the SRC has seen insufficient justification for using the proposed 0.2 percentile factor.

Please note: The Public Utility Commission of Texas is currently working on a proposed rule establishing a cold weather temperature standard. Accordingly, ERCOT does not support or oppose the SRC’s comments on the Extreme Cold Weather Temperature definition.

2.  Generator Cold Weather Reliability Event (GCWRE): The SRC believes the terms “generating unit” or “unit” does not make it clear the Standard applies to an entire facility/plant. The NERC Glossary does not define generation “unit," but many industry people consider an individual turbine/generator a unit (e.g., a plant may have four quick start Combustion Turbine units and one combined cycle unit). The SDT should review and revise the “Applicability” section of EOP-012-2 to clearly identify how the standard applies to dispersed generation resources. This is not a new concept and is supported by the work previously completed under Project 2014-01: Standards Applicability for Dispersed Generation Resources.

The NERC Glossary defines a Facility as “a set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.)” and an Element as, “any electrical device with terminals that may be connected to other electrical devices....” Those definitions do not, however, clearly indicate whether “generator” includes all the associated equipment/components the Standard seeks to cover. By way of example, other NERC Glossary definitions use “generating unit” and/or “generating facility” but not always in the same way, for example:

-     Blackstart Resource (“A generating unit(s) and its associated set of equipment….”)

-     Cranking Path (“A portion of the electric system that can be isolated and then energized to deliver electric power from a generation source to enable the startup of one or more other generating units”)

-     Economic Dispatch (“The allocation of demand to individual generating units on line to effect the most economical production of electricity”)

-     Forced Outage (“1. The removal from service availability of a generating unit…for emergency reasons….”)

-     Frequency Measurable Event (“…a cumulative change in generating unit/ generating facility, DC tie and/or firm load pre-perturbation megawatt value to post-perturbation megawatt value absolute deviation greater than 550 MW….”)

Thus, referring to the NERC Glossary does not provide an easy solution for this issue. The SRC believes the SDT should include a standard-only definition of generating unit or generating facility, particularly to ensure it captures dispersed resources adequately. A Standard-only definition could include, for example, “the technology used to convert a primary fuel into electricity including generators, inverters, associated control systems, valves, actuators, other mechanical and electrical components, etc.”  Such an approach would capture PV, wind, natural gas, nuclear, hydro, fuel oil, biomass, etc. and ensure the rule covers individual parts of facilities.

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 9/1/2022

IRC SRC supporting tabled temperatures.pdf

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The phrase from #3 from the Generator Cold Weather Reliability Event defintion – “ for which the apparent cause(s) is due to freezing of equipment within the Generator Owner’s control and the dry bulb temperature at the time of the event was at or above the Extreme Cold Weather Temperature” seems to apply to points #1 and #2 and therefore should be included in these or moved to the opening statement ‘One of the following events for which the apparent cause…’ 

Also, within the same highlighted phrase, ‘freezing of equipment’ is specified, but not freezing of onsite fuel supplies or process fluids? Is fuel exempt? Lube oil? Ammonia? If these are included, this should be stated and further clarification/extension of the term ‘freezing’ may also be warranted to state something to the effect of ‘changing fuel or process fluid properties such that critical processes are limited’.

FE also supports EEI’s comments on the proposed definitions. 

EEI supports all three definitions for this first phase, but we also propose additional revisions to the Generator Cold Weather Critical Component and the Cold Weather Reliability Event because additional clarity is needed and that  can be addressed during the next phase of this project. (See below.)  

Generator Cold Weather Critical Component: Use of the undefined term “fixed fuel supply component” within the proposed definition of Generator Cold Weather Critical Component creates confusion.  While we support the explanation provided by the SDT in the Technical Rationale, the Technical Rationale has no standing as a compliance document.  For this reason, we recommend defining this term within the framework of the next phase of this project.  We suggest the following:

Fixed Fuel Supply Component: Are non-mobile equipment that support the reliable delivery of fuel to the generating unit and under the control the Generator Owner at a plant site. Gaseous, liquid, or solid fuel handling components that are installed on site as fixed parts of the fuel delivery system that are under the Generator Owner’s control would be included. Components that would not be included would be mobile equipment such as trains, bulldozers, or other equipment that are not fixed in one location.

Generator Cold Weather Reliability Event: EEI is concerned with the use of the term “specified”, as it relates to the start-up time of a generator during cold weather events, because it is unclear clear who would be responsible for specifying the start-up time.  Results Based Standards should “define a particular reliability objective or outcome to be achieved.  In its simplest form, a results-based requirement has four components: who, under what conditions (if any), shall perform what action, to achieve what particular result or outcome.”

 

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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AEPC has signed on to ACES comments, please see their responses.

 

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 9/1/2022

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Avista supports all three definitions for this first phase, but we also propose additional revisions to the Generator Cold Weather Critical Supply Component and the Cold Weather Reliability Event because additional clarity is needed and that can be addressed during the next phase of this project. (See below)

Generator Cold Weather Critical Supply Component: Use of the undefined term “fixed fuel supply component” within the proposed definition of Generator Cold Weather Critical Component creates confusion.  While we support the explanation provided by the SDT in the Technical Rationale, the Technical Rationale has no standing as a compliance document.  For this reason, we ask the SDT to consider defining this term within the framework of the next phase of this project.  We suggest the following for SDT consideration:

Fixed Fuel Supply Component: Are non-mobile equipment that support the reliable delivery of fuel to the generating unit and under the control the Generator Owner at a plant site. Gaseous, liquid, or solid fuel handling components that are installed on site as fixed parts of the fuel delivery system that are under the Generator Owner’s control would be included. Components that would not be included would be mobile equipment such as trains, bulldozers, or other equipment that are not fixed in one location.

Generator Cold Weather Reliability Event: EEI is concerned with the use of the term “specified”, as it relates to the start-up time of a generator during cold weather events, because it is unclear clear who would be responsible for specifying the start-up time.  Results Based Standards should “define a particular reliability objective or outcome to be achieved.  In its simplest form, a results-based requirement has four components: who, under what conditions (if any), shall perform what action, to achieve what particular result or outcome.” (NERC Results Based Standards – Performance Based; https://www.nerc.com/pa/Stand/Pages/ResultsBasedStandards.aspx#:~:text=Results%20based%20standards%20are%20standards,the%20NERC%20Standard%20Processes%20Manual.)

Mike Magruder, Avista - Avista Corporation, 1, 9/1/2022

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Invenergy does not agree with the definitions as currently drafted and offers the following recommendations.

Generator Cold Weather Reliability Event:  

As noted below in response to Question 6, Invenergy recommends setting the forced derate threshold in a manner consistent with NERC’s BES criteria, using a minimum of 20 MVA for individual generating units and a minimum of 75 MVA for dispersed power producing resources.

Invenergy proposes the following change to condition (1) of the definition:

(1) A forced derate of:

  • More than 10% of the total capacity of the unit and exceeding 20 MVA for generating units identified under Inclusion I2 of the BES definition; or
  • More than 10% of the total capacity of the generating facility and exceeding 75 MVA for generating units identified under Inclusion I4 of the BES definition.

Additionally, Invenergy recommends removing the word “apparent” from the definition. 

Extreme Cold Weather Temperature:  

The proposed definition improves on the previous draft by using a percentile instead of the single minimum hourly temperature and data starting on 1/1/2000 rather than 1/1/1975.  

As Invenergy did in response to the first ballot, we propose that the methodology use a multi-day average temperature rather than hourly temperatures, and a reliability analysis-based percentile rather than the 0.2 proposed in the latest draft. Without endorsing the exact values proposed, we note the proposal by Commission Staff at the Public Utility Commission of Texas (see Project No. 53401, Electric Weather Preparedness Standards-Phase II, Memorandum and Proposal for Publication dated May 19, 2022) would be expected to yield a more reasonable requirement: “…the lesser of the minimum ambient temperature at which the resource has experienced sustained operations or the 95th percentile minimum average 72-hour temperature reported in ERCOT’s historical weather study…for the weather zone in which the resource is located.” (Emphasis added.) 

To demonstrate the need for this alternative approach, consider solar generators. Under the SDT’s proposal, the calculation of the Extreme Cold Weather Temperature will be heavily influenced by colder nighttime temperatures, when there is no solar generation. Using a multi-day period would more reasonably set the minimum temperature standard for these facilities.

Finally, Generator Owners need additional detail on the mechanics of calculating the Extreme Cold Weather Temperature as it is presently defined. For example, if hourly temperature data back to 1/1/2000 at a Generator Owner’s nearest weather station(s) are unavailable, should the Generator Owner use only the data available at that station, or use an alternative station regardless of the distance from the facility? What fraction of the data from the nearest station must be missing before an alternative station is used?

Rhonda Jones, Invenergy LLC, 5, 9/1/2022

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Hot Answers

The term “generating unit” causes confusion in how the standard applies to renewable resources.  Although an attempt to clarify is provided, the term “generating unit” is often interpreted to refer to individual turbines or invertors and not the aggregate facility.  Enel therefore supports the MRO NSRF proposed language to further clarify section 4.2.  In particular, Enel supports the MRO NSRF suggestion to clarify that the term “generating unit” refers to Inclusion I4, the aggregated dispersed power producing resources with a total capacity of 75 MVA or greater.  In addition, Enel also recommends that this clarification be consistent with how this issue was addressed in other standards such as PRC-024.    

Natalie Johnson, Enel Green Power, 5, 9/1/2022

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The applicability will not be consistently applied due to references to contracts for serving load that are not related to NERC standards (i.e. 4.2.1.1 “That commits or is obligated to serve a Balancing Authority load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement.”).  In addition, the use of the phrase “not typically available at or below thirty-two (32) degrees” in 4.2.1.1.1 is highly subjective and open to interpretation. 

Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

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Other Answers

The applicabilty should exempt those generation facilities that are designed and operated in below freezing weather, or that employ technology that is not affected by extreme cold weather.

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

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Entergy, Segment(s) 1, 5, 12/13/2017

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

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Diana Torres, Imperial Irrigation District, 6, 8/23/2022

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DTE Electric supports NAGF comments provided for this project

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

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The Applicability section is clear, but insufficient.  There cannot be meaningful progress on enhancing BES wintertime reliability without proper Planning Assessments and real-time resource adequacy evaluations, and these goals cannot be achieved if RCs, BAs and TOPs continue to use a DBT yardstick for WCT-related phenomena. 

The DBT-based databases presently being used create a false sense of resource adequacy, as was demonstrated during Winter Storm Uri.  It may not be possible for EOP-012-1 to set requirements for RCs, BAs and TOPs, since they were omitted from the SAR, but NERC should launch a parallel project so that they use accurate, WCT-based temperature capability data (or DBT-plus-20 mph), and EOP-012-1 should set the stage by manfdating collection of this information.

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

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a. 4.2.1.1 That commits or is obligated to serve a Balancing Authority load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement; This should not be included in the Applicability section as per FAC-001-3, R4.3, all BES generators must be within a BA metered boundary.

b. The inclusion of blackstart resources is redundant with the inclusion I3 of the BES definition and therefore should be removed.

c. The cold weather exclusion should be removed from the applicability section and instead a requirement should be added to require the GO to prove operability in cold weather through analysis/studies.

Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

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Talen Energy Marketing LLC supports Talen Generation's comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

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WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

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Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

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In regards to the proposed Section 4.2 Facilities definition: In order to ensure a reliable response from generators that may be called upon by the Balancing Authorities during Capacity and Energy Emergencies, we recommend eliminating the exception for generators that do not operate during the winter season except when called upon by the Balancing Authority to be available during Capacity Emergencies or Energy Emergencies.


Our recommended change to the language would be “The term excludes those generators that are not normally expected to operate during the winter season under normal and/or emergency conditions.”

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

- 0 - 0

We recommend the SDT consider establishing a defined winter season under 4.2.1.1.1 or placing responsibility for defining a winter season on the Balancing Authority rather than relying on the “typically not available at or below thirty-two degrees” language.

Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

- 0 - 0

The Applicability is unnecessarily complicated.

section 4.2.1.2: Is it the intent to not automatically include generators that meet the BES definition Inclusions I2 and I4? Blackstart Resources (I5) are already included as BES Generators per the definition of the BES and it is redundant and/or confusing to call them out specifically.

Section 4.2.1.1.1 uses the term "typically" which is subjective and unclear. If this is going to be used as an exclusion to the standard it should be definitive. Alternatively, the limited generators that this will be applicable to can utilize this type of exclusionary languge in their Cold Weather Prep Plan and as justification for not implementing a CAP to address issues as necessary.

Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

- 1 - 0

Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

- 0 - 0

While Avista supports the Applicability Section, it is overly complicated and offer the following non-substantive changes for consideration:

 

4.2    Facilities: The term “generating unit” subject to these requirements means:

 

4.2.1  Bulk Electric System (BES) generating unit(s) that commit or are obligated to serve a Balancing Authority load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement, excluding BES generating unit(s) that are that are not committed or obligated to operate at or below thirty-two (32) degrees Fahrenheit (zero degrees Celsius) for any continuous run of more than four hours. The exclusion applies even when such BES generating unit(s) have been called to assist in the mitigation of BES Emergencies, Capacity Emergencies, or Energy Emergencies during periods at or below thirty-two (32) degrees Fahrenheit (zero degrees Celsius).

4.2.2  Blackstart Resource(s) that are identified in the Transmission Operator’s system restoration plan.

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

- 0 - 0

Portland General Electric Company supports the survey response provided by EEI.

Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

- 0 - 0

Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

- 0 - 0

Glenn Pressler, CPS Energy, 3, 8/30/2022

- 0 - 0

While Avista supports the Applicability Section, it is overly complicated and offer the following non-substantive changes for consideration:

4.2    Facilities: The term “generating unit” subject to these requirements means:

4.2.1  Bulk Electric System (BES) generating unit(s) that commit or are obligated to serve a Balancing Authority load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement, excluding BES generating unit(s) that are that are not committed or obligated to operate at or below thirty-two (32) degrees Fahrenheit (zero degrees Celsius) for any continuous run of more than four hours. The exclusion applies even when such BES generating unit(s) have been called to assist in the mitigation of BES Emergencies, Capacity Emergencies, or Energy Emergencies during periods at or below thirty-two (32) degrees Fahrenheit (zero degrees Celsius).

4.2.2  Blackstart Resource(s) that are identified in the Transmission Operator’s system restoration plan.

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

- 0 - 0

The proposed definition of a BES generating unit is one “[t]hat commits or is obligated to serve a Balancing Authority load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangements.”  This definition assumes that an obligation “to serve” exists.  The majority of generating assets in the United States are located in regions overseen by Independent System Operators or Regional Transmission Operators and do not have obligations “to serve,” unless pursuant to a state contract or stretching the definition – a Reliability Must Run contract.   They may have an obligation to supply energy under specified rules on a seasonal or annual basis if they clear a capacity auction.  If the intent of this rule is to apply only to generation owned by a vertically integrated utility subject to federal and/or state laws that obligate the utility to provide service, to a publicly owned generator subject to municipal rules regarding an obligation to serve, or to a generating unit that has contractually committed to supply energy for a long term period to a Balancing Authority or through state and or/federal contract, the definition may not be infirm.  However, we encourage the SDT to clarify the purpose and intent of this section.

With regard to R4.1.1.1, we note that, as drafted, a generator that is typically unavailable above 32 degree Fahrenheit – e.g., a mothballed unit in south Florida – would be required to comply with the standard.  The first criteria should be whether a location experiences sufficient freezing conditions to warrant applicability.  If it does not, then there is no compliance obligation – e.g., San Diego.  If it does, then the availability criteria should apply.  We also recommend replacing “typical” with the ECWT to create bright line criteria.  In addition, we do not understand the need to specify the duration of a dispatch schedule.  In our experience, failures of peaking resources are more likely to occur during start-up than during operations.  BAs typically dispatch peaking plants after the nadir of the local temperature in the overnight hours – i.e., morning ramp, thus we recommend SDT change the definition to:

“The term excludes a Bulk Electric System generating unit that is: (i) in a location where the Extreme Cold Weather Temperature is calculated to be greater than 32 degree Fahrenheit (0 degree Celsius) or (ii) in a location where the Extreme Cold Weather Temperature is calculated to be lower than or equal to 32 degree Fahrenheit (0 degree Celsius) and the unit is typically not available in these freezing conditions.”

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

- 0 - 0

Ameren agrees with the EEI and the NAGF comments.

David Jendras, Ameren - Ameren Services, 3, 8/31/2022

- 0 - 0

Xcel Energy supports comments from EEI. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

- 0 - 0

Texas RE understands the intent of the SDT to include generation units that operate in different types of market structures, including the ERCOT region.  Texas RE recommends, however, clarifying Section 4.2.1.1, as it could benefit additional detail and clarity. The use of the term “to serve BA load” could lead to confusion for how the standard applies to generation-only BAs in the Eastern or Western interconnection as well as to ancillary services.

 

Texas RE recommends the type of market structure be removed from the Facilities section and the applicability focus on the reliability need.

 

Texas RE suggests the following proposed language, which focuses on the reliability needs that the generation units provide:

4.2.1 A Bulk Electric System generating unit:

4.2.1.1 That commits, or is committed by the BA, to provide energy to serve BA load, or;

4.2.1.2 That commits, or is committed by the BA or Reserve Sharing Group, to provide ancillary services to the BA or RSG for frequency control, frequency response, voltage control, or Operating Reserves, or;

4.2.1.3 That commits, or is committed by the BA or Reserve Sharing Group, to maintain BES elements within System Operating Limits, or;

4.2.1.4 Is identified as a Blackstart Resource.

4.2.2 The term excludes ….. (may want to include an example, such as a unit that is in a seasonal mothball status and only runs during summer months)

 

If the SDT feels that it is critical to maintain the market structure within the applicability section, Texas RE proposes the following language:

4.2.1 A Bulk Electric System generating unit:

4.2.1.1 That commits, or is committed by the BA, to provide energy under market processes, or;

4.2.1.2 That commits, or is committed by the BA or Reserve Sharing Group, to provide ancillary services to the BA or RSG for frequency control, voltage control, or Operating Reserves, or;

4.2.1.3 Is obligated to serve a Balancing Authority load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement, or;

4.2.1.4 Is identified as a Blackstart Resource.

4.2.2 The term excludes …..

 

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

- 0 - 0

PG&E supports the comments provided by EEI and the NAGF, and has the following additional concern and recommendations related to NAGF’s second input;

 

The currently proposed wording in Section 4.2.1.1.1 is not clear what is required if a Generator Owner's calculated Extreme Cold Weather Temperature is above 32 degrees Fahrenheit. To address this concern, PG&E recommends the addition of “or a generator that has determined its Extreme Cold Weather Temperature be above 32 degrees” in the first sentence of 4.2.1.1.1 to help correct this issue.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

- 0 - 0

AEP would like to express its support of EEI’s response to this question and adds supportive comments below.

AEP believes the Applicability section could be improved by making it clear that a Blackstart Resource, for purposes of this standard, are *only* those resources identified as such by the RTO (serving as the BA).

4.2.1.1.1 states that “The term excludes a Bulk Electric System generating unit that is typically not available…”, however we believe the phrase “typically not available” is ambiguous. Rather, we believe a threshold should be established in this section, similar to that provided in MOD-026 and MOD-027.

We believe clarity is also needed within 4.2.1 to make it clear if the bullets are to be collectively considered as an “and” or as an “or” clause.

Thomas Foltz, AEP, 5, 8/31/2022

- 0 - 0

Dominion Energy supports the EEI comments and recommend modifications to the proposed Applicability section. 

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

LouisvilleG&E/KU support EEI's comments. 

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

- 0 - 0

Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

- 0 - 0

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

- 0 - 0

Southern Company agrees that the Applicability Section language is clear.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

- 0 - 0

Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

- 0 - 0

Reclamation disagrees with 4.2.1.1 and disagrees with the exclusion in 4.2.1.1.1. Reclamation disagrees with narrowing the scope of applicability based on entity choice of units that operate. Generating units that have no potential to freeze, e.g., hydroelectric plants that are housed indoors in climate-controlled buildings, should be excluded. Generating units that may be called on to assist in the mitigation of any Emergency should not be excluded because the failure of these units to operate properly in an Emergency exacerbates the Emergency. Reclamation asserts that exempting these units is a clear loophole in the intent of ensuring reliability during cold weather. Both exclusions will decrease BES reliability.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

- 0 - 0

A clear statement also needs to be made that this standard is not applicable to a generator with the Extreme Cold Weather temperature above 32 degrees.

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

- 0 - 0

Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

- 0 - 0

A clear statement also needs to be made that this standard is not applicable to a generator with the Extreme Cold Weather temperature above 32 degrees

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

- 0 - 0

“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

- 0 - 0

BHC still needs clarity on what the SDT is attempting to say by the 4.2.1.1 BA portion. 

Claudine Bates, Black Hills Corporation, 6, 8/31/2022

- 0 - 0

BHC still needs clarity on what the SDT is attempting to say by the 4.2.1.1 BA portion.

Josh Combs, Black Hills Corporation, 3, 8/31/2022

- 0 - 0

BHC still needs clarity on what the SDT is attempting to say by the 4.2.1.1 BA portion.

Micah Runner, Black Hills Corporation, 1, 8/31/2022

- 0 - 0

BHC still needs clarity on what the SDT is attempting to say by the 4.2.1.1 BA portion.

Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

- 0 - 0

LDWP recommends this requirement to be region specific applicable only to areas that are susceptible to Extreme Cold Weather.  In addition, require Generator Owners that plan to operate generating units in areas susceptible to Extreme Cold Weather to specify the need for continuous operation at or below the Extreme Cold Weather Temperature.

Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

- 0 - 0

PNM supports EEI’s comments.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

- 0 - 0

In order to capture the comparable OATT in non-US jurisdictions, we suggest revising 4.2.1.1 as follows:  

That commits or may be committed or is obligated to serve a Balancing Authority load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement or rules; 

The IESO strongly believes that the standard should apply to all the generating units whose capacity is being counted on, including those providing sufficient reserve to withstand a cold weather event.

The IESO suggests considering the concept of requiring the GO to declare to the BA/RC a unit will not run during the winter, unless the BA/RC requests it to run during an emergency.

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

- 0 - 0

In Section 4.2.1.1.1 the language ‘typically not available’ is subjective and unclear. If an exclusion is allowed, the Balancing Authority should determine which resources are excluded from the EOP-012 standard and requirements.

Further, excluding resources from NERC reliability standards but allowing those same resources to be dispatched in the conditions (below 32 degrees) which this standard addresses, is contrary to the purpose of this exact NERC standard.

James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

- 0 - 0

Vistra has no comments on the Applicability Section language.

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

- 0 - 0

Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #3.

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

- 0 - 0

Exelon agrees the Applicability Section language is clear, we do also support the enhancements proposed by the EEI.  

 

Submitted on behalf of Exelon, Segments 1 & 3

Daniel Gacek, Exelon, 1, 9/1/2022

- 0 - 0

SIGE agrees with the changes to the revised Applicability Section.

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

- 0 - 0

In Section 4.2.1.1.1 the language ‘typically not available’ is subjective and unclear.  If an exclusion is allowed, the Balancing Authority should determine which resources are excluded from the EOP-012 standard and requirements. 

Further, excluding resources from NERC reliability standards but allowing those same resources to be dispatched in the conditions (below 32 degrees) which this standard addresses, is contrary to the purpose of this exact NERC standard.

Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

- 0 - 0

Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

- 0 - 0

Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

- 0 - 0

Vistra has no comments on the Applicability Section language.

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

- 0 - 0

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

- 0 - 0

AES Clean Energy supports comments submitted by NAGF.

Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

- 0 - 0

The NAGF has two concerns with the applicability section.

The first concern is that the language used in section 4.2.1.1 is unclear as to the meaning. Every generator has an interconnection agreement with their Transmission Owner (and possibly other third parties) which is under the OATT. The NAGF is concerned that the lack of clarity in this statement will lead to assumptions that differ across the registered entities and the regulators. Clarity would be provided by clearly stating that this standard is applicable to generators that are accepted in a capacity market rather than the vague wording used in the current draft.

The second concern is that it is not clear what is required of a Generator Owner if the calculated Extreme Cold Weather Temperature is above 32 degrees Fahrenheit. To address this concern, a clear statement that this standard is not applicable to a generator with the Extreme Cold Weather Temperature above 32 degrees is needed. The addition of “or a generator that has determined its Extreme Cold Weather Temperature to be above 32 degrees” in the first sentence of 4.2.1.1.1 will correct this issue.

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

- 0 - 0

ISO-NE believes that if the GOs are left to their own declaration of being “typically” available and/or if they are required to upgrade a unit or facility with freeze protection, this could create an unfair market advantage to those entities that choose not to freeze protect their units and facilities for “commercial” reasons.  During extreme weather events markets may account for these situations reflected in the real-time prices.  Thus, ISO-NE suggests the SDT consider the concept of requiring the GO to declare to the BA/RC a unit will not run during the winter so the GO cannot take advantage of high prices unless the BA/RC requests it to run during an emergency.

 

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

LES, Segment(s) 6, 1, 3, 5, 10/8/2018

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

- 0 - 0

Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

- 0 - 0

The Applicability Section in the revised standard seems to indicate applicability to individual generating units. During the Q&A session of the WebEx presentation held on 8/16/22, a question was asked that led to discussion around this term, and it was indicated that the requirements, when considering I4 generating facilities, should be applied to entire wind farm (time mark 1:48:14 in the August 16, 2022 webinar recording). Considering this discrepancy, the MRO NSRF requests the Standard Drafting Team provide clarifying language in the Applicability Section of the Standard.

Proposed language: 

4.2 Facilities: : For purposes of this standard, the term “generating unit” subject to 
these requirements means:
4.2.1 For generating facilities included in the BES under:
4.2.1.1 Inclusion I2, an individual generating unit
4.2.1.2 Inclusion I3, any Blackstart Resources identified in the Transmission Operator’s restoration plan.
4.2.1.3 Inclusion I4, the aggregated dispersed power producing resources with a total capacity of 75 MVA or greater. 
and
4.2.2 That commits or is obligated to serve a Balancing Authority load
pursuant to an Open Access Transmission Tariff (OATT) or other 
contractual arrangement;
4.2.3 The term excludes a Bulk Electric System generating unit that
is typically not available at or below thirty-two (32) degrees 
Fahrenheit (zero degrees Celsius) for any continuous run of 
more than four hours. The exclusion applies even when such 
BES generator has been called to assist in the mitigation of
BES Emergencies, Capacity Emergencies, or Energy 
Emergencies during periods at or below 32 degrees 
Fahrenheit.

 

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 0 - 0

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

MidAmerican Energy supports the MRO NSRF comments for this question. 

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

- 0 - 0

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

- 0 - 0

EDF supports the comments submitted by NAGF.

Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

- 0 - 0

Mark Young, Tenaska, Inc., 5, 9/1/2022

- 0 - 0

As this is written, it says that a "generation unit" is a BES unit that is committed/obligated AND is identified as a blackstart resource.  Because 4.2.1 doesn't indicate that the unit be "one of the following" and because there's no OR between 4.2.1.1 and 4.2.1.2, there is an implied AND.  This suggests that, for the purpose of this standard, only blackstart units need to winterize.  We suspect that this is not the intent of the document, so we would recommend changing 4.2.1 to say "A Bulk Electric System generating unit that conforms to either 4.2.1.1 or 4.2.1.2 below:".  I would also move 4.2.1.1.1 to become 4.2.2. so that it doesn't impede or obscure the either/or choice of 4.2.1.1/4.2.1.2.

Imane Mrini, Austin Energy, 6, 9/1/2022

- 0 - 0

MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC) except where noted.

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

- 0 - 0

Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

- 0 - 0

Madison Gas and Electric supports the comments from the MRO NSRF.

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

- 0 - 0

Madison Gas and Electric supports the comments of the MRO NSRF

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

- 0 - 0

In regards to the proposed Section 4.2 Facilities definition: In order to ensure a reliable response from generators that may be called upon by the Balancing Authorities during Capacity and Energy Emergencies, we recommend eliminating the exception for generators that do not operate during the winter season except when called upon by the Balancing Authority to be available during Capacity Emergencies or Energy Emergencies.

Our recommended change to the language would be “The term excludes those generators that are not normally expected to operate during the winter season under normal and/or emergency conditions.”

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

- 0 - 0

The revised Applicability Section is less clear than the version presented for the first ballot. Specifically, it is not clear what BES generating units the SDT intends to include with respect to the load-serving requirement and listed contractual qualifiers in Section 4.2.1.1. Invenergy recommends that the Applicability be returned to the language used for the first ballot.

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

- 0 - 0

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/6/2022

- 0 - 0

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 9/1/2022

- 0 - 0

Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 9/1/2022

- 0 - 0

SMUD / BANC, Segment(s) 3, 6, 1, 4, 5, 8/18/2022

- 0 - 0

WGRs may not meet the requirements of 4.2.1.1.1 if ambient dry bulb air temperature is below 32 degrees Fahrenheit and wet precipitation (i.e., rain) is being deposited on the turbine blades.  Additionally, it is not clear why certain types of units would be exempt from the Standard.  NERC should clearly specify the types of units that it intends exempt from this Standard and explain why exempting these units is not unduly discriminatory.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

EEI recommends the references to the OATT and “other contractual arrangement” language be removed because such language adds little to the requirement from results-based Reliability Standard standpoint.  Additionally, while EEI supports the Applicability Section, it is overly complicated and offer the following non-substantive changes for consideration:

Applicability:

4.1   Functional Entities:

4.1.1.        Generator Owner

4.1.2.        Generator Operator

4.2.      Facilities: The term “generating unit” subject to these requirements means:

4.2.1.       A Bulk Electric System (BES) generating unit that commits or is obligated to serve a Balancing Authority load excluding a BES generating unit that is not committed or obligated to operate at or below thirty-two (32) degrees Fahrenheit (zero degrees Celsius) for any continuous run of more than four hours. The exclusion continues to apply should such BES generating unit be called upon to operate for more than four hours in order to assist in the mitigation of BES Emergencies, Capacity Emergencies, or Energy Emergencies during periods at or below 32 degrees Fahrenheit.

4.2.2.       That is identified as a Blackstart Resource.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

APS agrees with EEI’s recommendation to remove references to the OATT and “other contractual agreement” language as it introduces complexity with little value. We agree with EEI’s proposed revisions to the Applicability section.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 9/1/2022

- 0 - 0

Cowlitz agrees with comments proviced by North American Generator Forum and Utility Services.

Russell Noble, Cowlitz County PUD, 3, 9/1/2022

- 0 - 0

Alyssia Rhoads, Public Utility District No. 1 of Snohomish County, 1, 9/1/2022

- 0 - 0

John Liang, Snohomish County PUD No. 1, 6, 9/1/2022

- 0 - 0

Agree with comments provided by Russell Noble.

Deanna Carlson, Cowlitz County PUD, 5, 9/1/2022

- 0 - 0

The SRC supports the addition of Part 4.2.1.1, as the language provides a clear and measurable criteria. However, the SRC believes it could be improved. Specifically, Section 4.2.1.1 refers to a unit obligated to serve a BA load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement.  Specifically, an OATT does not define capacity obligations of units in RTO regions. Those obligations appear in: (i) other agreements approved by FERC; (ii) state law in states with vertically integrated utilities (such as the requirement for the state PUC to find units receiving rate base treatment “used and useful”); or (iii) market rules. As written, the Standard’s language would override (or, at best, conflict with) those other requirements. As a result, to avoid that problem the SRC recommends revising the language as follows (to cover RTOs, ERCOT and Canadian entities):

That commits or may be committed or is obligated to serve Balancing Authority load pursuant to a tariffed obligation, state requirement as defined by relevant electric regulatory authority, other contractual arrangement, rules or regulations;

Section 4.2.1.1.1 goes on to inadvertently undo the sweep of Section 4.2.1.1 by stating the Standard, “...excludes a [BES] generating unit... typically not available at or below thirty-two (32) degrees...for any continuous run of more than four hours [and] applies even when such BES generator has been called to assist in the mitigation of BES Emergencies, Capacity Emergencies, or Energy Emergencies during periods at or below 32 degrees Fahrenheit.” To correct this drafting issue, the SRC recommends adding the following language at the beginning of Section 4.2.1.1.1:

“For any generating unit not covered by Section 4.2.1.1,…”

Within Section 4.2.1.1.1, using the phrase "typically not available at or below thirty-two degrees…" allows a GO to self-proclaim a unit not "typically" available in the winter. The SRC believes the SDT should revisit this language and provide more measurable parameters. Otherwise, a GO could make itself available one day and not the next. It also provides no parameters for what constitutes “typical;” i.e., more than 50% of the time, 25%, etc.? As written, a Regional Entity could not audit a unit exemption.

[GOs should not be able to choose to not weatherize a unit and then choose to offer that unit to take advantage of high prices during the winter season. Thus, the SRC suggests the SDT consider the concept of requiring the GO to declare to the BA/RC a unit will not run during the winter so the GO cannot take advantage of high prices unless the BA/RC requests it to run during an emergency.] *

* Please note:  MISO is not a party to this paragraph in response to this Question.  PJM also has concerns with this response.

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 9/1/2022

- 0 - 0

FE supports EEI comments on the proposed changes to Functional Entities and fully support removing the phrase “pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement”.  The proposed edits read:

 Applicability: 

4.1 Functional Entities:

4.1.1. Generator Owner 

4.1.2. Generator Operator 

4.2. Facilities: The term “generating unit” subject to these requirements means: 

4.2.1. A Bulk Electric System generating unit that commits or is obligated to serve a Balancing Authority load excluding a Bulk Electric System generating unit that is not committed or obligated to operate at or below thirty-two (32) degrees Fahrenheit (zero degrees Celsius) for any continuous run of more than four hours. The exclusion continues to apply should when such BES generator be called upon to operate for more than four hours in order to assist in the mitigation of BES Emergencies, Capacity Emergencies, or Energy Emergencies during periods at or below 32 degrees Fahrenheit. 

4.2.2. That is identified as a Blackstart Resource.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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AEPC has signed on to ACES comments, please see their responses.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 9/1/2022

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While Avista supports the Applicability Section, it is overly complicated and offer the following non-substantive changes for consideration: 

4.2    Facilities: The term “generating unit” subject to these requirements means:

4.2.1  Bulk Electric System (BES) generating unit(s) that commit or are obligated to serve a Balancing Authority load pursuant to an Open Access Transmission Tariff (OATT) or other contractual arrangement, excluding BES generating unit(s) that are that are not committed or obligated to operate at or below thirty-two (32) degrees Fahrenheit (zero degrees Celsius) for any continuous run of more than four hours. The exclusion applies even when such BES generating unit(s) have been called to assist in the mitigation of BES Emergencies, Capacity Emergencies, or Energy Emergencies during periods at or below thirty-two (32) degrees Fahrenheit (zero degrees Celsius).

4.2.2  Blackstart Resource(s) that are identified in the Transmission Operator’s system restoration plan.

Mike Magruder, Avista - Avista Corporation, 1, 9/1/2022

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The revised Applicability Section is less clear than the version presented for the first ballot. Specifically, it is not clear what BES generating units the SDT intends to include with respect to the load-serving requirement and listed contractual qualifiers in Section 4.2.1.1. Invenergy recommends that the Applicability be returned to the language used for the first ballot.

Rhonda Jones, Invenergy LLC, 5, 9/1/2022

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Hot Answers

Natalie Johnson, Enel Green Power, 5, 9/1/2022

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Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

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Other Answers

This is an arbitrary timeframe with an arbitrary assumption.  I don't see a good technical basis established regarding this requirement.

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

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Entergy agrees with the statement “at the Extreme Cold Weather Temperature” but does not agree with “or below”.

Entergy, Segment(s) 1, 5, 12/13/2017

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

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Diana Torres, Imperial Irrigation District, 6, 8/23/2022

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DTE Electric supports NAGF comments provided for this project

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

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The equations in IEEE-515, IEEE Standard for the Testing, Design, Installation, and Maintenance of Electrical Resistance Trace Heating for Industrial Applications, have a steady-state basis. Granting an exception for inadequately protected equipment so long as it takes a long time to freeze would put the BES at risk and is not in accordance with industry practice.

There is also no apparent basis for a figure of 12 hours as representing the maximum duration of a weather emergency.  The historical worst-case winter storm in our area produced freeze protection-challenging cold weather (-15 F WCT or lower) for approx. 30 consecutive hours. 

Additionally, freeze protection margins cannot be reliably sliced so thin – there is great uncertainty in protecting a plant, due to frequent design and installation errors by heat tracing and insulation contractors.  There is also no big-picture incentive to do so.  The cost difference between a steady-state design and one with a survival limit of 12 hours is negligible in comparison to the cost to society of inadequate protection and the cost to GOs if finding that their forecasts are off and R6 retrofits are needed.

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

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Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

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Talen Energy Marketing supports Talen Generation's comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

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WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

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Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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We do not have a concern where viable technical solutions exist but do have a concern where installing such measures would void manufacturer warranties and increase the risk of equipment failure. Additionally, renewable generation (Solar or Wind) is only capable of performing if the resource is available. 

Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

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It is our recommendation that wind should not be included in the design criteria for new Generation units unless added to Extreme Cold Weather Temperature definition. The rationale is due to the inconsistencies between R1 and R3. The language in R1 states that the GO shall include a concurrent 20 MPH wind speed in the design criteria for new generating units. Whereas the language in R3 states that the cold weather preparedness plan may include measures used to reduce the cooling effects of wind. Is the GO required to include wind in their calculations for all stations and all scenarios? If not, then what is the benefit for including this in the design criteria for new generating units?


Furthermore, the 20 MPH value seems to be somewhat arbitrary. Please provide additional clarification as to how this value was derived and the rationale behind this derivation.


Lastly, the standard drating team should consider how commercial constraints are referenced in R1. As written a declaration for a commercial constraint as defined by the Generator Owner could preclude the ability to implement appropriate freeze protection measures to provide capability of operating for twelve (12) hours at the documented Extreme Cold Weather Temperature. A commercial constraint could be defined by the Generator Owner to include the lack of budget allocated for winterization projects. This approach seems to not align with the purpose of this standard, "To address the effects of operating in extreme cold weather by ensuring each Generator Owner has developed and implemented plan(s) to mitigate the reliability impacts of extreme cold weather on its generating units."

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

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Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

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Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

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Avista supports the language proposed in Requirement R1, which if approved, would require new generation to have the capability to operate for a period of not less than 12 hours at the Extreme Cold Weather Temperature for the unit, but we do not agree that the unit needs to 

be capable of operating below the Extreme Cold Weather Temperature for 12 hours, as indicated in this question.

 

There should be an allowance for act of god situations which a plant can not reasonably account for.

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

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Portland General Electric Company supports the survey response provided by EEI.

Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

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Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

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Glenn Pressler, CPS Energy, 3, 8/30/2022

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Avista supports the language proposed in Requirement R1, which if approved, would require new generation to have the capability to operate for a period of not less than 12 hours at the Extreme Cold Weather Temperature for the unit, but we do not agree that the unit needs to be capable of operating below the Extreme Cold Weather Temperature for 12 hours, as indicated in this question.

There should be an allowance for act of god situations which a plant can not reasonably account for.

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

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We note that the proposed standard requires performance at the ECWT, yet the question asks whether we support an open-ended requirement below the ECWT.  We do not.  

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

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Ameren agrees with the EEI and the NAGF comments.

David Jendras, Ameren - Ameren Services, 3, 8/31/2022

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Xcel Energy supports comments from EEI. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

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Please see Texas RE’s answer to #5.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

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PG&E supports the requirement for a new generator to operate for a period not less than 12 hours as noted in the Requirement. 

 

PG&E also supports the comments supplied by EEI that is not a 12-hour timeframe as indicated in this question and the concerns indicated in the NAGF comments regarding the Standard being unenforceable by the ERO and NAGF’s input on addressing the optional requirement language.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

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AEP supports the proposed 12-hour timeframe in the current draft, however we disagree with Q4’s inference that the unit needs to be capable of performing *below* the Extreme Cold Weather Temperature for 12 hours.

AEP interprets the text proposed in the final bullet of R1 as allowing a declaration to be used as an exception based on operational restrictions outside of the Generator Owner’s control such as environmental permit limits for a new installation.

Thomas Foltz, AEP, 5, 8/31/2022

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Dominion, Segment(s) 3, 5, 1, 9/19/2019

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LouisvilleG&E/KU support EEI's comments. 

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

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Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

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PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

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Southern Company agrees with the 12-hour continuous hours as proposed in R1.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

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Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

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Reclamation does not agree with the fine-toothed level of specificity that is proposed. A standard that is too specific only sets up entities for compliance failure and does not improve reliability. Creating overly-specific requirements and allowing exemptions creates loopholes in the solution, which ultimately sabotages reliability. Reclamation recommends the applicability be targeted to specific geographic region(s) or specific types of generating units that are the root causes of the cold weather problems FERC is attempting to solve. Mandatory compliance for these units should not be diminished in any way.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

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The 12-hour timeframe imposes a larger performance burden on new fossil generation since many renewable technologies are unlikely to meet this benchmark in the winter period as the nature of their operation is less than 12 continuous hours. In addition, renewable technology such as wind turbines cannot operate in certain winter conditions (freezing precipitation, high winds) allowing for technical exemptions. Since these IRRs could potentially be exempted under a technical exception, this creates a disadvantage for new thermal generators further slanting the market playing field by giving one type of technology a competitive advantage over another type of technology.

 NRG also has concerns with the language around the exclusion for technical, operational, and commercial reasons.  Clarity is needed as to what are acceptable criteria for these exclusions as this will be subject to interpretation.

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

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Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

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The 12-hour timeframe imposes a larger performance burden on new fossil generation since many renewable technologies are unlikely to meet this benchmark in the winter period as the nature of their operation is less than 12 continuous hours. In addition, renewable technology such as wind turbines cannot operate in certain winter conditions (freezing precipitation, high winds) allowing for technical exemptions. Since these IRRs could potentially be exempted under a technical exception, this creates a disadvantage for new thermal generators further slants the market playing field by giving one type of technology a competitive advantage over another type of technology.

 

NRG also has concerns with the language around the exclusion for technical, operational, and commercial reasons.  Clarity is needed as to what are acceptable criteria for these exclusions as this will be subject to interpretation.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

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“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

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BHC does not feel 12 hours is an adequate amount of time once a new unit has gone commercial, dependent upon when that commercial date was achieved. Hypothetically, if the unit achieved commercial operation during spring/summer, therefore, the unit may not have had a chance for capability testing during winter/extreme temperatures.

Claudine Bates, Black Hills Corporation, 6, 8/31/2022

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BHC does not feel 12 hours is an adequate amount of time once a new unit has gone commercial, dependent upon when that commercial date was achieved. Hypothetically, if the unit achieved commercial operation during spring/summer, therefore, the unit may not have had a chance for capability testing during winter/extreme temperatures.

Josh Combs, Black Hills Corporation, 3, 8/31/2022

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BHC does not feel 12 hours is an adequate amount of time once a new unit has gone commercial, dependent upon when that commercial date was achieved. Hypothetically, if the unit achieved commercial operation during spring/summer, therefore, the unit may not have had a chance for capability testing during winter/extreme temperatures.

Micah Runner, Black Hills Corporation, 1, 8/31/2022

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BHC does not feel 12 hours is an adequate amount of time once a new unit has gone commercial, dependent upon when that commercial date was achieved. Hypotehtically, if the unit achieved commercial operation during spring/summer, therefore, the unit may not have had a chance for capability testing during winter/extreme temperatures.

Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

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LDWP recommends this requirement to be region specific applicable only to areas that are susceptible to Extreme Cold Weather.  In addition, require Generator Owners that plan to operate generating units in areas susceptible to Extreme Cold Weather to specify the need for continuous operation at or below the Extreme Cold Weather Temperature.

Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

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PNM supports EEI’s comments.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

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Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

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James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

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As a general principle, Vistra believes that the requirements for existing and new resources should be substantively similar, such that neither has a material cost burden or advantage over the other.  With that said, the 12-hour standard is not inherently unreasonable, in itself, if the term “Extreme Cold Weather Temperature” is defined in a less conservative manner, such as the 99th percentile minimum average ambient temperature over some timeframe (e.g., 12 to 72 hours) since a specified date (e.g., Jan. 1, 2000) at the nearest weather station. However, based on the current, very conservative proposed definition of Extreme Cold Weather Temperature, which effectively equates to a 99.8th percentile lowest hourly temperature recorded at the nearest weather station since Jan. 1, 2000, it may not be economically feasible for a new Generation unit to achieve 12-hours of sustained operations at that temperature, based on current design specifications for the particular type of resource. The costs of achieving 12-hours of sustained operations at a 1-hour 99.8th percentile standard could be cost-prohibitive and cause investors to cancel planned investments, which, in turn, would be detrimental to resource adequacy, as described in response to Question 2. If a 12-hour operations standard will be required, then the definition of Extreme Cold Weather Temperature should also be tied to historical temperatures over at least a continuous 12-hour timeframe. The Extreme Cold Weather Temperature definition, as currently framed, looks only at a single hourly temperature in the lowest 0.2 percentile since Jan. 1, 2000 and then requires a new resource to prove that it can operate at that temperature for at least 12 hours and at 20 mph winds. As noted under Question 2, in the draft Technical Requirements  document, the example 0.2 percentile temperature had only ever occurred in 11 separate hours since 2000. Thus, there is no basis under the historical data underlying that definition of Extreme Cold Weather Temperature to require a new resource to prove it can operate for 12 consecutive hours at a temperature that apparently has not occurred in the past 22 years for 12 consecutive hours. Thus, as described under Question 2, Vistra would recommend using an average temperature over a period of hours that at least matches (if not exceeds) the required hours for which the resource must sustain operations at that temperature (and would recommend setting the percentile at something less conservative than the lowest 0.2 percentile/99.8th percentile). If the Extreme Cold Weather Temperature definition is not changed as proposed, then new resources should not be required to prove sustained operations at that temperature for more than one hour.

 

In addition, Requirement R1 allows a new resource to submit a declaration if it cannot satisfy the 12-hour operation requirement, but it is not clear what happens in that instance. The standard should clarify what standard will be imposed if a new resource declares that it cannot meet the standard in the requirement (e.g., 12 hours). Will the resource be held to a lower standard consistent with its design specifications? Will that lower standard relate to the applicable cold weather temperature at which the resource must sustain operations or the number of hours for which the resource must sustain operations or both? Will the Technical Feasibility Exception process be used?

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #4.

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

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Exelon concurs with EEI's comment to Question 4.  

 

Submitted on behalf of Exelon, Segments 1 & 3

Daniel Gacek, Exelon, 1, 9/1/2022

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SIGE supports EEI’s comment for Question 4 and agrees with the language of R1 for new generations units to implement freeze protection measures that provide capability to operate for a period of not less than twelve (12) continuous hours at the Extreme Cold Weather Temperature if the constraint exemption (bullet 2) remains in the requirement.

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

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Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

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Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

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As a general principle, Vistra believes that the requirements for existing and new resources should be substantively similar, such that neither has a material cost burden or advantage over the other.  With that said, the 12-hour standard is not inherently unreasonable, in itself, if the term “Extreme Cold Weather Temperature” is defined in a less conservative manner, such as the 99th percentile minimum average ambient temperature over some timeframe (e.g., 12 to 72 hours) since a specified date (e.g., Jan. 1, 2000) at the nearest weather station. However, based on the current, very conservative proposed definition of Extreme Cold Weather Temperature, which effectively equates to a 99.8th percentile lowest hourly temperature recorded at the nearest weather station since Jan. 1, 2000, it may not be economically feasible for a new Generation unit to achieve 12-hours of sustained operations at that temperature, based on current design specifications for the particular type of resource. The costs of achieving 12-hours of sustained operations at a 1-hour 99.8th percentile standard could be cost-prohibitive and cause investors to cancel planned investments, which, in turn, would be detrimental to resource adequacy, as described in response to Question 2. If a 12-hour operations standard will be required, then the definition of Extreme Cold Weather Temperature should also be tied to historical temperatures over at least a continuous 12-hour timeframe. The Extreme Cold Weather Temperature definition, as currently framed, looks only at a single hourly temperature in the lowest 0.2 percentile since Jan. 1, 2000 and then requires a new resource to prove that it can operate at that temperature for at least 12 hours and at 20 mph winds. As noted under Question 2, in the draft Technical Requirements  document, the example 0.2 percentile temperature had only ever occurred in 11 separate hours since 2000. Thus, there is no basis under the historical data underlying that definition of Extreme Cold Weather Temperature to require a new resource to prove it can operate for 12 consecutive hours at a temperature that apparently has not occurred in the past 22 years for 12 consecutive hours. Thus, as described under Question 2, Vistra would recommend using an average temperature over a period of hours that at least matches (if not exceeds) the required hours for which the resource must sustain operations at that temperature (and would recommend setting the percentile at something less conservative than the lowest 0.2 percentile/99.8th percentile). If the Extreme Cold Weather Temperature definition is not changed as proposed, then new resources should not be required to prove sustained operations at that temperature for more than one hour.

In addition, Requirement R1 allows a new resource to submit a declaration if it cannot satisfy the 12-hour operation requirement, but it is not clear what happens in that instance. The standard should clarify what standard will be imposed if a new resource declares that it cannot meet the standard in the requirement (e.g., 12 hours). Will the resource be held to a lower standard consistent with its design specifications? Will that lower standard relate to the applicable cold weather temperature at which the resource must sustain operations or the number of hours for which the resource must sustain operations or both? Will the Technical Feasibility Exception process be used?

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

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Cold weather performance needs to be sustained for the duration of a weather event. Historically, extreme weather events have lasted more than 12 hours. Hence, equipment should be expected to operate continuously at a stated level, albeit at a level below nameplate. Operating for 12 hours only delays onset of problems without ensuring mitigation of reliability impacts.

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

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Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

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While the NAGF agrees with the proposal as being reasonable, there are still concerns related to this proposal. Those concerns include the expectation that this proposal will not protect against another event like Uri, and that the Extreme Cold Weather Temperature is not addressing wind and moisture. With this said, the proposal is considered by most to be clear and enforceable and provides clear guidance and expectations to design future generators to meet a design criterion.

The NAGF does have concern with the language around the exclusion for technical operational and commercial reasons. This language essentially makes this requirement optional to anyone that does not want to meet the design requirement. While we recognize the reasoning for the exemption language, we feel it makes the standard unenforceable by NERC.

Instead of creating the optional requirement, a more immediate impact would be seen by ensuring that Balancing Authorities and others are using information detailing generator capabilities when performing their planning processes to reduce the expectation of unplanned outages due to the lack of appropriate planning. This would allow the appropriate entities, including regulatory officials, to identify where issues might arise and how to best address the issue rather than creating optional requirements.

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

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ISO-NE believes that new generation units be capable of performing “Continuously” at the ECWT.  The requirement should also include the 20 mph wind speed on exposed critical equipment.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

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LES, Segment(s) 6, 1, 3, 5, 10/8/2018

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

- 0 - 0

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

- 0 - 0

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 0 - 0

For some Canadian entites, units already operate in cold weather annually from November to March. These requirements represent and added administrative burden.

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

MidAmerican Energy supports the MRO NSRF comments for this question.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

- 0 - 0

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

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EDF believes that it is extremely difficult to apply a “one-size-fits-all” strategy to the timeframe. As an example, the R1 definition refers to twelve (12) continuous hours which is unrealistic during winter period (in cold climates) for inverter based resources (Photovoltaic – PV and Battery Energy Storage System – BESS), i.e., 12 hours of sunlight are not available for PV generation, and many BESS units are only rated for 4 hours. PV and BESS would be producing less than 12 hours during these months on a normal basis. Wind resource, unlike PV and BESS, is unpredictable and we cannot guarantee 12 hours, since the production time will depend of wind availability. We recommend defining a timeframe based on conventional and another for renewables (wind may need to be separate from solar and battery storage)

Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

- 0 - 0

Mark Young, Tenaska, Inc., 5, 9/1/2022

- 0 - 0

The last sentence of M1 is incomplete and therefore confusing.  Is it supposed to be part of the sentence prior?

Imane Mrini, Austin Energy, 6, 9/1/2022

- 0 - 0

MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC).

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

- 0 - 0

Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

- 0 - 0

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

- 0 - 0

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

- 0 - 0

It is our recommendation that wind should not be included in the design criteria for new Generation units unless added to ECWT definition. The reasoning behind this recommendation is due to the inconsistencies between R1 and R3. The language in R1 states that the GO shall include a concurrent 20 MPH wind speed in the design criteria for new generating units. Whereas the language in R3 states that the cold weather preparedness plan may include measures used to reduce the cooling effects of wind. Is the GO required to include wind in their calculations for all stations and all scenarios? If not, then what is the benefit for including this in the design criteria for new generating units?

Furthermore, the 20 MPH value seems to be somewhat arbitrary. Please provide additional clarification as to how this value was derived and the rationale behind this derivation. 

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

- 0 - 0

Invenergy recommends striking “continuous” from the requirement to reflect the fact that certain generation technologies, including wind and solar generators, have variable, not continuous output.

Even with the recommended edit above, the capability requirement does not account for all relevant circumstances. Two examples illustrate the issue: (1) Solar generators are not capable of operating in a 12-hour period that extends beyond daylight hours. (2) The capability of storage generators is constrained by their duration.

Further, the performance expectations of all generators should be the same, and the separate performance criteria proposed for new and existing generating units in R1 and R2 respectively set precedents for the unequitable treatment of Generator Owners based on a fluid effective date of the Requirement.

If the SDT decides to regulate new and existing generators differently, then the SDT should establish a definition for new and existing units not based on the effective date of the Requirement(s), but rather the age of the generating unit.

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

- 0 - 0

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/6/2022

- 0 - 0

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 9/1/2022

- 0 - 0

Acciona Energy has no comments.  

George Brown, Acciona Energy North America, 5, 9/1/2022

- 0 - 0

SMUD / BANC, Segment(s) 3, 6, 1, 4, 5, 8/18/2022

- 0 - 0

R1 requires the GO to operate for no less than 12 continuous hours at the ECW Temperature with wind speeds up to 20 mph.  First, wind speed should be specified as “sustained wind speed”.  Second, this question infers GOs will be required to operate reliably below the ECW Temperature.  That is not the R1 requirement.  R1 does not require operating at below the ECW.  Furthermore, consistent with the comment in Response 3, NERC should clearly specify the types of units that it intends to exempt from this Standard and explain why exempting these units is not unduly discriminatory.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

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EEI supports the language proposed in Requirement R1, which if approved, would require new generation to have the capability to operate for a period of not less than 12 hours at the Extreme Cold Weather Temperature for the unit, but we do not agree that the unit needs to be capable of operating below the Extreme Cold Weather Temperature for 12 hours, as indicated in this question.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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Michelle Amarantos, APS - Arizona Public Service Co., 5, 9/1/2022

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Cowlitz is concerned how this will be demonstrated by compliance documentation short of actual performance, although the intent is reasonable. The requirement should recognize good faith effort in design, but clearly define the action the responsible entity should take if the design proves inadequate in during operations.

Russell Noble, Cowlitz County PUD, 3, 9/1/2022

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Alyssia Rhoads, Public Utility District No. 1 of Snohomish County, 1, 9/1/2022

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John Liang, Snohomish County PUD No. 1, 6, 9/1/2022

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Agree with comments provided by Russell Noble.

Deanna Carlson, Cowlitz County PUD, 5, 9/1/2022

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The proposed Standard requires generating units to perform at or below the ECWT for twelve hours. The SRC does not think this language, as written, suffices because it limits a unit’s obligation to winterize to run for only a twelve-hour period. For example, in PJM, units with capacity obligations are required to perform whenever called upon by PJM during a declared system emergency and are subject to very high penalties if they do not perform during the hours when they can be called upon. Yet, as written, the standard would potentially erode if not create an ambiguity with that requirement by requiring a lesser only 12 hour run requirement.

The SRC recognizes this issue needs further discussion and is willing to coordinate with the SDT to address the issue.

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 9/1/2022

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FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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AEPC has signed on to ACES comments, please see their responses.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 9/1/2022

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Avista supports the language proposed in Requirement R1, which if approved, would require new generation to have the capability to operate for a period of not less than 12 hours at the Extreme Cold Weather Temperature for the unit, but we do not agree that the unit needs to be capable of operating below the Extreme Cold Weather Temperature for 12 hours, as indicated in this question.

There should be an allowance for act of god situations which a plant can not reasonably account for.

Mike Magruder, Avista - Avista Corporation, 1, 9/1/2022

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Invenergy recommends striking “continuous” from the requirement to reflect the fact that certain generation technologies, including wind and solar generators, have variable, not continuous output.

Even with the recommended edit above, the capability requirement does not account for all relevant circumstances.  Two examples illustrate the issue: (1) Solar generators are not capable of operating in a 12-hour period that extends beyond daylight hours. (2) The capability of storage generators is constrained by their duration.

Further, the performance expectations of all generators should be the same, and the separate performance criteria proposed for new and existing generating units in R1 and R2 respectively set precedents for the unequitable treatment of Generator Owners based on a fluid effective date of the Standard.

If the SDT decides to regulate new and existing generators differently, then the SDT should establish a definition for new and existing units not based on the effective date of the Requirement, but rather the age of the generating unit.

Rhonda Jones, Invenergy LLC, 5, 9/1/2022

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Hot Answers

Natalie Johnson, Enel Green Power, 5, 9/1/2022

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Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

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Other Answers

This continues to put an unnecessary burden on those generators that operate in freezing environments.  This one hour timeline is arbitrary and doesn't seem to have any technical justification for the timeline.

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

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Entergy agrees with the statement “at the Extreme Cold Weather Temperature” but does not agree with “or below”.

Entergy, Segment(s) 1, 5, 12/13/2017

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

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Agree, but this could become problematic because there is no time period mentioned.  How long is a historical run able to be used as meeting the requirement? 

Diana Torres, Imperial Irrigation District, 6, 8/23/2022

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DTE Electric supports NAGF comments provided for this project

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

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Talen Energy supports the comments of the NAGF on this topac, and adds that a one-hour period is appropriate since the variability of weather conditions often makes a longer demonstration impossible.  This is not the end of the matter, however; this achievement should be based for conventional plants on WCT (or DBT-plus-20 mph), not DBT alone. 

The lack of credibility of DBT-based achievements can be seen in reviewing the events of January 2014 for our area.  No problems were encountered on 1/4/2014 at -4 F DBT and a 4.6 mph wind (-14.6 F WCT).  EOP-012-1 in its present form says that all plants online at that time had a proven DBT capability of at least -4 F.  Many of these facilities were knocked offline three days later, however, when the Polar Vortex of 2014 bottomed-out at 0 F with a 21.9 mph wind (-22.8 WCT).

More importantly, R2 should allow declaring R3.5.2 WCT capability values as an alternative to retrofits, and EOP-012-1 should also permit R6 CAPS that consist of revising these inputs instead of modifying equipment.  Existing facilities were built in accordance with all regulatory and market rules in place at the time, and it would be wrong to order them in ex post facto fashion to become something significantly different.  The lack of winterization rules to-date is not a failing of GO/GOPs, so they should not be subjected to punitive measures.

RC/BA/TOP planning based on GO/GOP temperature capability inputs hasn’t worked in the past, but only due to these entities insisting on an incorrect basis (DBT only) plus failing to differentiate between temperature-caused and precipitation-caused outages.  Planning Assessments and real-time reserve margin forecasts should be highly accurate once EOP-012-1 puts an end to this confusion.

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

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Tri-State feels that a 1-hour is too short of a time frame for reliability, instead we recommend the time frame of 4-hours.

Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

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Talen Energy Marketing LLC supports Talen Generation's comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

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WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

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Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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Need the ability to explain in a declaration, technical, commercial or operational constraints for existing units (as is proposed for new units under Requirement R1).  We do not have a concern where viable technical solutions exist but do have a concern where installing such measures would void manufacturer warranties and increase the risk of equipment failure.  Requiring a Corrective Action Plan (CAP) under Requirement R2 may not be feasible for certain generation, as the needed technological advancement may be delayed beyond the proposed implementation period or may never be achieved.   Additionally, renewable generation (Solar or Wind) is only capable of performing if the resource is available. 

Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

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AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

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Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

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How will it be proven that you’ve provided enough protection to sustain the minimum 1-hour capability during ECWT? It is still not clear why there is a different requirement for generating units existing prior to the effective date of the requirement. Shouldn’t all generators have the same requirement of 12 hours while also allowing existing generatios to submit a corrective action plan?

Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

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Avista supports the proposed R2 language that requires GOs of existing Generating units ensure new or modify existing freeze protection measures provide the capability to operate for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature.

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

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Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

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Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

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Glenn Pressler, CPS Energy, 3, 8/30/2022

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Avista supports the proposed R2 language that requires GOs of existing Generating units ensure new or modify existing freeze protection measures provide the capability to operate for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature.

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

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We note that the proposed standard requires performance at the ECWT, yet the question asks whether we support an open-ended requirement below the ECWT.  We do not.   Additionally, we do not support disparate treatment of resource types that are otherwise similarly situated, and new versus existing creates disparate treatment.  If the SDT selected 12 hours because they thought is was the duration necessary to enhance reliability, then it should apply to all generators.  During the deliberation process, certain SDT team members were concerned a rigorous standard may cause “premature retirements.”  We understand that the sole reason that the existing generator standard differs from new is to mitigate the “premature retirements.”  Section 1341 of the Energy Policy Act of 2005, which was affirmed by the Commission in its Order 672, supports cost recovery for all costs prudently incurred to comply with the Reliability Standards, and it does not limit this consideration to specific types of units or circumstances, e.g., whether because of their “newness,” or retirement considerations.

 

Additionally, the SDT assumes that good historical performance assures good future performance.  A permissive prescriptive standard may not result in this outcome.  We agree with the SDT that many generators have performed well in the past and may have operated at or below their ECWT for extended durations.  However, the proposed standard will only allow cost recovery for meeting the exact requirements of the standard and no more.  If a generator owner elects to replace robust freeze protections that have demonstrated superlative performance with in-kind components at the end of their service life or after a major outage, the generator owner may not be able to recover the full cost of such replacement.  In fact, ratemaking proceedings may expressly disallow costs incremental to meeting the one-hour standard.   For these reasons, we do not support different standards between new and existing.

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

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David Jendras, Ameren - Ameren Services, 3, 8/31/2022

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Xcel Energy can support the 1-hour time frame for existing units, predicated on the ability that R2 is tied to R6 and, subsequently, R7. The ability to declare qualifying units as unable to implement corrective actions is a required element for Xcel Energy to support R2 of the Standard. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

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Texas RE does not agree the proposed 1-hour timeframe in Requirement R2 is sufficient to allow existing Generation units to demonstrate their performance at or below the Extreme Cold Weather Temperature.  Historical events in 2011, 2014, 2018, and 2021, have instances in which it has taken at least 6-12 hours for freezing issues to appear, depending on the unit status. During the South Central United States cold weather BES event in January 2018, for example, cold weather was sustained for two days.  Between January 15 and January 17, 2018, generation resources experienced various outages, derates, or failures to start.  Similarly, for over two days in February 2021, ERCOT averaged 34,000 MW of generation outages.  The SDT should consider a longer duration to demonstrate performance at or below the Extreme Cold Weather Temperature based on historic events.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

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PG&E agrees with the input provided by the NAGF that the 1-hour timeframe will not make an improvement in performance during an extreme event and supports the NAGF recommendation on how to decide on the adequacy of the proposed timeframe.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

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AEP supports the proposed 1-hour timeframe in the current draft, however we disagree with Q5’s inference that the unit needs to be capable of operating *below* the Extreme Cold Weather Temperature for 1 hour.

Thomas Foltz, AEP, 5, 8/31/2022

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Dominion Energy strongly advocates for and supports appropriately addressing the reliability issues identified in the joint FERC/NERC report related to winter storm Uri in a non-arbitrary and cost-effective manner under the Federal Power Act. Accordingly, Dominion Energy recommends rather than a universal requirement to retrofit exiting generation to operate to an arbitrary temperature requirement that may be beyond its current design capabilities, a requirement to communicate the generating units’ extreme cold weather operating capabilities to the RC and BA and a corresponding requirement to develop a corrective action plan to continue to operate to those capabilities if the unit fails to do so due to freezing. Dominion Energy is of the opinion that this modification will accomplish the reliability goal identified in the FERC/NERC report.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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LG&E/KU supports the SDT proposed 1-hour timeframe.

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

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Difficult to answer yes or no... the 1-hour timeframe for demonstrating (which we interpret to mean testing) a Generation unit's performance sounds reasonable, however, if operating at or below the Extreme Cold Weather Temperature, you would not be in a testing state, you would be in an actual Extreme Cold Weather Temperature state. 

Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

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PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

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Southern Company agrees with the 1-hour timeframe to allow existing Generation units to demonstrate their performance as proposed in R2.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

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Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

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Reclamation does not agree with the fine-toothed level of specificity that is proposed. The proposed calculations required to comply or determine whether compliance is required are unnecessary administrative and resource-intensive burdens that will not improve reliability and will detract from entities’ ability to comply with the standard.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

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Currently this draft requires Generator Owners to retrofit their units to meet the newly defined Extreme Weather temperature levels. NRG understands that to invoke any technical, operational, or commercial exclusions clauses (such as units designed above 32 F) that each facility would require development of a CAP which may not be able to be executed under R7. It would be more prudent to include a provision in R2 to allow generators to provide these exclusions and associated justifications upfront.  

 NRG believes that R2 should not require existing Generators to retrofit but rather report their extreme cold weather operating parameters to the appropriate parties and only require a CAP if they fail to meet their operating parameters as communicated to the appropriate entities. This will allow the appropriate entities to identify where issues might arise and how to best address the issue rather than placing an unreasonable reliability requirement on all Generator Owners. The weatherization requirements, as currently drafted without cost recovery mechanisms in place, may exacerbate current difficulties for independent generators to cover costs and earn a return overall. The potential cost implications may result in generators either retiring or opting out of the winter season through seasonal mothballing.

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

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Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

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Currently this draft requires Generator Owners to retrofit their units to meet the newly defined Extreme Weather temperature levels. NRG understands that to invoke any technical, operational, or commercial exclusions clauses (such as units designed above 32 F) that each facility would require development of a CAP which may not be able to be executed under R7. It would be more prudent to include a provision in R2 to allow generators to provide these exclusions and associated justifications upfront.  

 

NRG believes that R2 should not require existing Generators to retrofit but rather report their extreme cold weather operating parameters to the appropriate parties and only require a CAP if they fail to meet their operating parameters as communicated to the appropriate entities. This will allow the appropriate entities to identify where issues might arise and how to best address the issue rather than placing an unreasonable reliability requirement on all Generator Owners. The weatherization requirements, as currently drafted  without cost recovery mechanisms in place,  may exacerbate current difficulties for independent generators to cover costs and earn a return overall. The potential cost implications may result in generators either retiring or opting out of the winter season through seasonal mothballing.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

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“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

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BHC agrees with comments submitted by EEI. 

Claudine Bates, Black Hills Corporation, 6, 8/31/2022

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BHC agrees with comments submitted by EEI. 

Josh Combs, Black Hills Corporation, 3, 8/31/2022

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BHC agrees with comments submitted by EEI. 

Micah Runner, Black Hills Corporation, 1, 8/31/2022

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BHC agrees with comments submitted by EEI

Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

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The requirement should be for continuous operation. The capability of the unit operating for 1 hour under Extreme Cold Weather, does not mean the generating unit will be reliable in Extreme Cold Weather..

Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

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PNM has concern regarding how the acceptable evidence outline in M2 [Identification of generating units minimum temperature per Part 3.5.2 which is equal to or less than the unit’s Extreme Cold Weather Temperature, documentation of freeze protection measures, Facility cold weather preparedness plan, and CAP(s)] demonstrates the capability to operate a generating unit for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

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Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

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It is more appropriate to have a temperature profile for unit operation.

James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

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The 1-hour timeframe, in itself, can be a reasonable standard. However, as discussed at length under Question 2, the term “Extreme Cold Weather Temperature” also must be defined in a similarly reasonable manner. As discussed under Question 2, Vistra proposes modifications to the definition of “Extreme Cold Weather Temperature” to make it more in line with the standards under consideration by the PUCT and to make it more economically feasible to meet.

 

In addition, Requirement R2 should expressly clarify that an existing resource will be deemed to have satisfied the requirements of R2 at its respective Extreme Cold Weather Temperature and that no new or modified freeze protection measures will be required if the Generator Owner: (i) has actual operating data demonstrating continuous operations for at least one hour at that plant’s Extreme Cold Weather Temperature (as cacluated under NERC’s Calculating Extreme Cold Weather Temperature guide), or (ii) in the absence of such data, can show that the plant is capable of sustained operations for one hour at that temperature based on design temperature or engineering analysis. Only if the plant cannot demonstrate (i) or (ii) above should the Generator Owner be required to implement a CAP to develop new or modified freeze protections to meet R2.

 

In addition, the language of R2 should make clear that the requirement is a weather preparedness standard, rather than a performance standard, and thus should avoid use of the word “ensure.”

 

The language of R2 could be modified as follows:

 

R2. For each generating unit(s) in commercial operation prior to [Effective Date of this requirement], the Generator Owner shall prepare its generating unit(s) by adding new or modifying existing freeze protection measures as needed to provide the capability to operate for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature. If a Generator Owner provides evidence that it has operated for at least one hour at or below its Extreme Cold Weather Temperature, or if the Generator Owner provides design specification information or other data (e.g., an engineering report) as detailed in M2 showing that it can operate for at least one hour at or below its Extreme Cold Weather Temperature, then the Generator Owner will be deemed to have met this Requirement R2, and need not implement new or additional freeze protection measures. Generating unit(s) that are not capable of operating for one (1) hour at its Extreme Cold Weather Temperature shall develop a Corrective Action Plan (CAP) for the identified issues, including identification of any needed modifications to the cold weather preparedness plan required under Requirement R3. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning]

                                                              

M2. Each Generator Owner will have dated evidence that demonstrates it has freeze protection measures for its unit(s) in accordance with R2, or it has developed a CAP for the identified issues. Acceptable evidence may include the following (electronic or hardcopy format): Identification of generating units minimum temperature per Part 3.5.2 which is equal to or less than the unit’s Extreme Cold Weather Temperature, documentation of freeze protection measures, cold weather preparedness plan, engineering study, historical data demonstrating one hour of sustained operations by the unit(s) at the applicable Extreme Cold Weather Temperature, and CAP(s).

 

Further, the SDT should consider adding a definition of “freeze protection measures” (applicable to all of EOP-012 and not just to R2) to clarify what those measures could entail and, importantly, to make clear that those measures do not have to include capital expenditures for redesign or retrofitting. For example, it should be clarified that “freeze protection measures” include temporary equipment like wind barriers. A new definition could be added as follows:

 

Freeze protection measures include permanent or temporary equipment, procedures, or other measures reasonably targeted to contribute to sustained operation by an existing unit(s) for the timeframe in R1 or R2, as applicable, at the Extreme Cold Weather Temperature.

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

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While Evergy supports EEI’s comments in our responses, in an effort to answer the specific question from the SDT, Evergy holds no concerns with the 1-hour timeframe.  Evergy agrees with the concerns about retrofits to existing resources with future transition plans but maintains that the SDT does not hold the authority to address the retrofit concern. 

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

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Daniel Gacek, Exelon, 1, 9/1/2022

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SIGE supports the proposed 1-hour timeframe in R2; however, for clarity and consistency, SIGE recommends modifying R2 to mirror R1:

For each generating unit(s) in commercial operation prior to [Effective Date of this requirement], the Generator Owner shall:

  • Ensure its generating unit(s) add new or modify existing freeze protection measures as needed to provide the capability to operate for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature. Generator Owner shall develop a Corrective Action Plan (CAP) for the identified issues, including identification of any needed modifications to the cold weather preparedness plan required under Requirement R3; or
  • Explain in a declaration, any technical, commercial, or operational constraints as defined by the Generator Owner that preclude the ability to implement appropriate freeze protection measures to provide capability of operating for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature.

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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It is more appropriate to have a temperature profile for unit operation.

Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

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Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

- 0 - 0

Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

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The 1-hour timeframe, in itself, can be a reasonable standard. However, as discussed at length under Question 2, the term “Extreme Cold Weather Temperature” also must be defined in a similarly reasonable manner. As discussed under Question 2, Vistra proposes modifications to the definition of “Extreme Cold Weather Temperature” to make it more in line with the standards under consideration by the PUCT and to make it more economically feasible to meet.

In addition, Requirement R2 should expressly clarify that an existing resource will be deemed to have satisfied the requirements of R2 at its respective Extreme Cold Weather Temperature and that no new or modified freeze protection measures will be required if the Generator Owner: (i) has actual operating data demonstrating continuous operations for at least one hour at that plant’s Extreme Cold Weather Temperature (as cacluated under NERC’s Calculating Extreme Cold Weather Temperature guide), or (ii) in the absence of such data, can show that the plant is capable of sustained operations for one hour at that temperature based on design temperature or engineering analysis. Only if the plant cannot demonstrate (i) or (ii) above should the Generator Owner be required to implement a CAP to develop new or modified freeze protections to meet R2.

In addition, the language of R2 should make clear that the requirement is a weather preparedness standard, rather than a performance standard, and thus should avoid use of the word “ensure.”

The language of R2 could be modified as follows:

R2. For each generating unit(s) in commercial operation prior to [Effective Date of this requirement], the Generator Owner shall prepare its generating unit(s) by adding new or modifying existing freeze protection measures as needed to provide the capability to operate for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature. If a Generator Owner provides evidence that it has operated for at least one hour at or below its Extreme Cold Weather Temperature, or if the Generator Owner provides design specification information or other data (e.g., an engineering report) as detailed in M2 showing that it can operate for at least one hour at or below its Extreme Cold Weather Temperature, then the Generator Owner will be deemed to have met this Requirement R2, and need not implement new or additional freeze protection measures. Generating unit(s) that are not capable of operating for one (1) hour at its Extreme Cold Weather Temperature shall develop a Corrective Action Plan (CAP) for the identified issues, including identification of any needed modifications to the cold weather preparedness plan required under Requirement R3. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning]

M2. Each Generator Owner will have dated evidence that demonstrates it has freeze protection measures for its unit(s) in accordance with R2, or it has developed a CAP for the identified issues. Acceptable evidence may include the following (electronic or hardcopy format): Identification of generating units minimum temperature per Part 3.5.2 which is equal to or less than the unit’s Extreme Cold Weather Temperature, documentation of freeze protection measures, cold weather preparedness plan, engineering study, historical data demonstrating one hour of sustained operations by the unit(s) at the applicable Extreme Cold Weather Temperature, and CAP(s).

Further, the SDT should consider adding a definition of “freeze protection measures” (applicable to all of EOP-012 and not just to R2) to clarify what those measures could entail and, importantly, to make clear that those measures do not have to include capital expenditures for redesign or retrofitting. For example, it should be clarified that “freeze protection measures” include temporary equipment like wind barriers. A new definition could be added as follows:

Freeze protection measures include permanent or temporary equipment, procedures, or other measures reasonably targeted to contribute to sustained operation by an existing unit(s) for the timeframe in R1 or R2, as applicable, at the Extreme Cold Weather Temperature.

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

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How does an existing unit "ensure" operation for one hour at a temperature that only occurs during an extreme cold weather event? This creates a liability for post event non-performance while doing little to maximize the possibility the unit will perform during such events. 

In addition, this imposes additional documentation and expense on entities with units that have demonstrated performance during actual events.

Finally, there is no value "ensuring" capability to operate for 1 hour during an extreme event since performance needs to be maintained for the duration of the event, not just one hour.  

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

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AES Clean Energy supports comments submitted by NAGF. AES Clean Energy agrees with NAGF that the 1-hour timeframe will not make a significant difference in performance improvement during an extreme cold weather event and that a better approach that relies on data should be employed in setting the time requirement.

Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

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While providing a clear expectation for Generator Owners to meet a performance level, the 1-hour timeframe to meet the Extreme Cold Weather Temperature has not been shown to make any level of improvement of performance during an extreme event such as Uri. The NAGF notes that the weather in Dallas was at or below the ECWT for over 50 hours straight and the Houston area met or exceeded the ECWT for 30 hours or more. The SDT has also not shown that the ECWT would address the issue the Joint Report mentioned multiple times related to generators failing prior to reaching their minimum design temperature. The NAGF recommends that a comparison of these units’ failure point and the ECWT be provided to industry before a determination is made as to the adequacy of the proposal. 

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

- 0 - 0

ISO-NE believes that Generators will have difficulty creating the needed conditions to “demonstrate” performance for 1-hour at or below the ECWT absent historical data.  How is this enforceable if a Unit can not demonstrate the performance.

ISO-NE recommends that existing units be required to demonstrate through historical information or through design specifications (equipment ratings, etc.) the capability to operate continuously at the Extreme Cold Weather Temperature for the unit(s), assuming a concurrent twenty (20) mph wind speed on any exposed Generator Cold Weather Critical Components;

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

LES, Segment(s) 6, 1, 3, 5, 10/8/2018

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

- 0 - 0

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

- 0 - 0

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 0 - 0

Requirement R4 appears to already fullfill the requirement of R2. The 2 requirements should be merged into one.

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

- 0 - 0

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

- 0 - 0

Please refer to our comments in Question #3. In addition, the delta between R1 requesting 12 hours and R2 requesting 1 hour does not make sense short term / long term. Is it the intent of the SDT to converge to the same amount of time on the long term?

Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

- 0 - 0

Mark Young, Tenaska, Inc., 5, 9/1/2022

- 0 - 0

Imane Mrini, Austin Energy, 6, 9/1/2022

- 0 - 0

MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC).

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

- 0 - 0

Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

- 0 - 0

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

- 0 - 0

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

- 0 - 0

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

- 0 - 0

Invenergy believes the performance expectations of all generators should be the same, and the separate performance criteria proposed for new and existing generating units in R1 and R2 respectively set precedents for the unequitable treatment of Generator Owners based on a fluid effective date of the Requirement.

If the SDT decides to regulate new and existing generators differently, then the SDT should establish a definition for new and existing units not based on the effective date of the Requirement(s), but rather the age of the generating unit.

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

- 0 - 0

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/6/2022

- 0 - 0

There should be more clarity for existing generation units to meet compliance for the 1 hr capability either in the requirement, Measure, or technical rational for the standard

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 9/1/2022

- 0 - 0

Acciona Energy has no comments.

George Brown, Acciona Energy North America, 5, 9/1/2022

- 0 - 0

SMUD / BANC, Segment(s) 3, 6, 1, 4, 5, 8/18/2022

- 0 - 0

R2 requires the GO to operate for no less than 1 continuous hour at the ECW Temperature.  First, wind speed should be specified here as in R1; the wind speed should be classified as “sustained wind speed,” and the “sustained wind speed” should be designated as 20 mph (greater sustained wind speeds exceed the ECW).  Second, this question infers GOs will be required to operate reliably below the ECW Temperature.  That is not the R1 requirement or the R2 requirement.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 5, 9/1/2022

- 0 - 0

While in agreement there should be an allowance for existing generation to demonstrate performance, 1-hour may be too lenient to cover the reliability gap.

Russell Noble, Cowlitz County PUD, 3, 9/1/2022

- 0 - 0

Alyssia Rhoads, Public Utility District No. 1 of Snohomish County, 1, 9/1/2022

- 0 - 0

John Liang, Snohomish County PUD No. 1, 6, 9/1/2022

- 0 - 0

Agree with comments provided by Russell Noble.

Deanna Carlson, Cowlitz County PUD, 5, 9/1/2022

- 0 - 0

While the SRC generally supports the idea of making existing generators demonstrate they can operate at the ECWT (with the proposed revision in Question 2) for at least one hour, that language does not require adding a 20 mph wind, which differs from the requirement for new generation. The SRC believes the BES will be more resilient if all generators must demonstrate the ability to operate at the ECWT plus a 20 mph wind.

The SRC believes Generators will have difficulty creating the needed conditions to demonstrate performance for one hour at or below the ECWT absent historical data. Thus, the SRC recommends the Standard require existing units to demonstrate - through historical information or design specifications (equipment ratings, etc.) - the capability to operate continuously at the ECWT for the unit(s), assuming a concurrent twenty (20) mph wind speed on any exposed Generator Cold Weather Critical Components.

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 9/1/2022

- 0 - 0

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 9/1/2022

- 0 - 0

Avista supports the proposed R2 language that requires GOs of existing Generating units ensure new or modify existing freeze protection measures provide the capability to operate for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature.

Mike Magruder, Avista - Avista Corporation, 1, 9/1/2022

- 0 - 0

Invenergy believes the performance expectations of all generators should be the same, and the separate performance criteria proposed for new and existing generating units in R1 and R2 respectively set precedents for the unequitable treatment of Generator Owners based on a fluid effective date of the Standard.

If the SDT decides to regulate new and existing generators differently, then the SDT should establish a definition for new and existing units not based on the effective date of the Requirement, but rather the age of the generating unit.

Rhonda Jones, Invenergy LLC, 5, 9/1/2022

- 0 - 0

Hot Answers

Please refer to comments in question 2.

Natalie Johnson, Enel Green Power, 5, 9/1/2022

- 0 - 0

Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

- 0 - 0

Other Answers

We see no technical justification for the 20 MW threashold.  How will this apply to Hydro resouces that are run-of-the-river where their capacity may diminish, but due to water flow (low fuel), they would never be able to generate to thier capacity?

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

- 0 - 0

Entergy, Segment(s) 1, 5, 12/13/2017

- 0 - 0

Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

- 0 - 0

Diana Torres, Imperial Irrigation District, 6, 8/23/2022

- 0 - 0

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

- 0 - 0

The value of 20 MW is suitable, but it needs to be applied for EOP-012-1 in plant-total fashion, not per generation unit as in the presently proposed definition of a Generator Cold Weather Reliability Event.  A criterion of 20 MW per wind turbine would be meaningless.

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

- 1 - 0

Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

- 0 - 0

Talen Energy Marketing supports Talen Generation's comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

- 0 - 0

WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

- 0 - 0

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

- 0 - 0

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

In the definition of Generator Cold Weather Reliability Event, Tacoma Power recommends changing “total capacity of the unit” to “facility rating of the unit.” Tacoma Power is concerned with the regulatory burden of trying to document the total capacity of a unit that is seasonally dependent/variable. By changing to “facility rating”, this would ensure a fixed and predictable number that constitutes the 10% value. 

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

- 1 - 0

Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

- 0 - 0

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

- 0 - 0

Yes, AECI supports the suggested approach.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

- 0 - 0

Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

- 0 - 0

Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

- 0 - 0

All generation, regardless of size, needs to be reliable for the range of conditions the industry agrees to.

Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

- 0 - 0

Avista supports the addition of a 20 megawatt minimum with the proposed Generator Cold Weather Reliability Event and its impact on GO responsibilities as it relates to CAPS within Requirement R6.

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

- 0 - 0

Portland General Electric Company supports the survey response provided by EEI.

Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

- 0 - 0

Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

- 0 - 0

Glenn Pressler, CPS Energy, 3, 8/30/2022

- 0 - 0

Avista supports the addition of a 20 megawatt minimum with the proposed Generator Cold Weather Reliability Event and its impact on GO responsibilities as it relates to CAPS within Requirement R6.

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

- 0 - 0

We support the 20 megawatt threshold with the following caveats.  We recommend that the SDT couple the MW threshold with a narrow dead band to the ECWT.  If a generator is experiencing any derate due to a freezing issue, a minor derate may be signaling a potential weak link in its freeze protection measures.  This derate would be particularly worrisome if the derate occurred at a temperature well exceeding the ECWT.

 

Additionally, the proposed draft allows for an exemption from developing a CAP only if the derate is less than four hours, yet the proposed standard for existing generators is one hour.  Clearly, a four hour derate is longer than the one hour standard, so what would be the CAP for a derate of less than 20 MW and greater than four hours (particularly if the derate started in the 2nd hour)?  What would be the CAP for a derate of greater than 20 MW but starting in hour two?  Would the CAPs simply state that the generator met the reliability standard and no further action is required?

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

- 1 - 0

Ameren agrees with the EEI and the NAGF comments.

David Jendras, Ameren - Ameren Services, 3, 8/31/2022

- 0 - 0

Xcel Energy supports comments from EEI. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

- 0 - 0

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

- 0 - 0

PG&E supports the addition of the 20 MW minimum, and supports the input provided by EEI on additional clarification on aligning the minimum threshold value with the BES Definition.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

- 0 - 0

With reference to the definition of a “Generator Cold Weather Reliability Event” we believe the 20 MW minimum should apply not only to (1), but (2) and (3) as well. Having said that however, it is not clear how this 20 MW minimum would apply to dispersed generation, either collectively (say, in the case of a wind farm) or to their individual units. Various interpretations of its application are possible, and the requirement would benefit by including text which clearly shows exactly how the minimum would be applied to dispersed units.

Thomas Foltz, AEP, 5, 8/31/2022

- 0 - 0

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

LouisvilleG&E/KU support EEI's comments. 

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

- 0 - 0

This does not apply to HHWP, so we choose to not weigh-in regarding this.

Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

- 0 - 0

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

- 0 - 0

Southern Company agrees that the 20 MW minimum is appropriate.  

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

- 0 - 0

Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

- 0 - 0

Reclamation does not agree with the fine-toothed level of specificity that is proposed. Too much effort is required to be spent determining whether or not the requirements apply or if they can be avoided. Reclamation recommends the standard be written in a plain and straightforward set of requirements. Please refer to the proposal submitted in Reclamation’s comments to Draft 1 Question 4.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

- 0 - 0

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

- 0 - 0

Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

- 0 - 0

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

- 0 - 0

“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

- 0 - 0

Claudine Bates, Black Hills Corporation, 6, 8/31/2022

- 0 - 0

Josh Combs, Black Hills Corporation, 3, 8/31/2022

- 0 - 0

Micah Runner, Black Hills Corporation, 1, 8/31/2022

- 0 - 0

Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

- 0 - 0

Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

- 0 - 0

PNM supports EEI’s comments.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

- 0 - 0

James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

- 0 - 0

Vistra has no comments on this proposed change.

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

- 0 - 0

Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #6.

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

- 0 - 0

Exelon concurs with EEI's comment to Question 6. 

 

Submitted on behalf of Exelon, Segments 1 & 3

Daniel Gacek, Exelon, 1, 9/1/2022

- 0 - 0

SIGE does not oppose the 20 megawatts minimum; however, SIGE does have recommendations for how it is currently addressed in the Generator Cold Weather Reliability Event definition. See SIGE’s response to Question 2. 

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

- 0 - 0

Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

- 0 - 0

Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

- 0 - 0

Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

- 0 - 0

Vistra has no comments on this proposed change.

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

- 0 - 0

This language exempts distributed generation, which is trending upward and is becoming a larger percentage of total generation, and creates a "perverse incentive" to implement multiple small units to avoid requirements. This subverts the purpose of mitigating reliability impacts during extreme cold weather. 

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

- 0 - 0

Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

- 0 - 0

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

- 0 - 0

ISO-NE believes the term Generating unit is vague and is open to interpretation.  Does this mean each generating unit or is it an entire facility.  Depending on the interpretation of unit by a GO, they could declare each unit separate in the large plant with many separate units which could preclude them from the applicability section of this standard as well as exempt form the CAP requirements outlined in Requirement 6.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

LES, Segment(s) 6, 1, 3, 5, 10/8/2018

- 0 - 0

Yes, the addition of a 20 megawatt minimum component to the 10% minimum adequately addresses the reliability need while uniformly applying the derate threshold to generating units regardless of total capacity or fuel source.

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

- 0 - 0

Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

- 0 - 0

Please refer to comments provided by  the MRO NSRF for the Generator Cold Weather Reliability Event definition, in question 2.

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 0 - 0

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

MidAmerican Energy supports the MRO NSRF response to this question, referring to the answer to question 2 regarding the Generator Cold Weather Reliability Event definition.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

- 0 - 0

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

- 0 - 0

The 20MW value is reasonable; however, for solar and wind generation, the term generating unit needs further definition for aggregate production (total-plant) vs. individual generator/inverter-based resource. EDF supports the comments submitted by Talen Generation.

Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

- 0 - 0

As long as the 10% is an additional criteria, e.g. 10% AND 20 MW. We do not support just a 20 MW derate alone.

Mark Young, Tenaska, Inc., 5, 9/1/2022

- 0 - 0

Imane Mrini, Austin Energy, 6, 9/1/2022

- 0 - 0

MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC).

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

- 0 - 0

Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

- 0 - 0

Madison Gas and Electric supports the comments from the MRO NSRF.

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

- 0 - 0

Madison Gas and Electric supports the comments of the MRO NSRF

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

- 0 - 0

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

- 0 - 0

Invenergy supports the addition of a megawatt minimum for requiring CAPs for derates. However, Invenergy believes the minimum could be better aligned with NERC’s BES criteria by establishing a minimum of 20 MVA for individual generating units identified under Inclusion I2 of the BES definition, or a minimum of 75 MVA for generating units identified under Inclusion I4 of the BES definition.

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

- 0 - 0

No Comment

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/6/2022

- 0 - 0

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 9/1/2022

- 0 - 0

Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 9/1/2022

- 0 - 0

SMUD / BANC, Segment(s) 3, 6, 1, 4, 5, 8/18/2022

- 0 - 0

The definition should be clarified. Is it 10% of the unit or 10% of the power block? In addition, as written, it is interpreted that it is only reportable if the impact is 10% of the unit capacity and exceeds 20 MW. The definition is not written as “or” as implied in the question.

Further, there is no tie for the derate to be the result of a GCWRE.  For example, a failed thermocouple on a duct burner runner in a heat recovery steam generator will require a CAP under this proposed language.  However, thermocouples are consumable components that are replaced routinely due to the cyclic nature of duct burner operation in combined cycle power plants.  Besides clarifying the definition of GCWRE to pertain only to GCWCC, NERC should consider implementing tiered limits (e.g., 50 MW for 500 MW or more, 25 MW for less than 500 MW, etc.).  This type of tiering system would alleviate potentially excessive administrative burdens on plant staff associated with CAPs.  For smaller units (less than 20 MWs), a CAP should not be required.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

EEI supports the addition of a 20 megawatt minimum, as proposed in the definition for a “Generator Gold Weather Event”, however, Question 6 and language contained in the Technical Rationale (see page 8, Requirement R6), raises an important question about the intended alignment of the minimum value (as described in the definition of Generator Cold Weather Reliability Event) with the BES definition.  If this threshold is intended to align with the BES definition, then the threshold should be adjusted to consider the differences between conventional and distributed/IBR resources.  While the 20 MW value aligns with the BES definition for the minimum individual conventional generating resources, (see Inclusion I2); the threshold for Inverter Based Resources (i.e., dispersed power producing resources/Inclusion I4) is measure by the aggregated capacity of a plant resulting in a minimum value of 75 MW.  For this reason, EEI asks for additional clarification whether the minimum threshold value is to be aligned with the BES definition, or not.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

APS supports the addition of a 20 megawatt minimum as proposed in the definition of a “Generator Cold Weather Reliability Event.” Additionally, APS echoes EEI’s comments questioning the intended alignment of the minimum value described in the “Generator Cold Weather Reliability Event” definition with the BES definition. If the threshold is intended to align with the BES definition, then it should be adjusted to consider the differences between conventional and inverter-based resources. While the 20 MW value aligns with the BES definition for the minimum individual conventional generating resources, (see Inclusion I2); the threshold for Inverter Based Resources (i.e., dispersed power producing resources/Inclusion I4) is measure by the aggregated capacity of a plant resulting in a minimum value of 75 MW.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 9/1/2022

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/1/2022

- 0 - 0

Alyssia Rhoads, Public Utility District No. 1 of Snohomish County, 1, 9/1/2022

- 0 - 0

John Liang, Snohomish County PUD No. 1, 6, 9/1/2022

- 0 - 0

Deanna Carlson, Cowlitz PUD, 5, 9/1/22

Deanna Carlson, Cowlitz County PUD, 5, 9/1/2022

- 0 - 0

The SRC supports the addition of a 20 MW minimum to align with the BES definition of a generating unit. That said, we do not support the corresponding limitations on Corrective Action Plans (CAPs) in the Generator Cold Weather Reliability Event (GCWRE) definition. As written, when taking the proposed GCWRE definition in conjunction with Requirement 6, a GO must develop a CAP if a unit experiences, “a forced derate of more than 10% of the total capacity of the unit, and exceeding 20 MWs, for longer than four hours in duration….”   The SRC believes this language could be interpreted to exclude all units rated at 200 MWs or less. Specifically, for 10% of unit capacity to exceed 20 MWs, the unit must have nameplate capacity of at least 201 MWs (i.e., 10% of 201 MWs = 20.1 MWs).

The SRC cannot support such a broad carve out of applicability. The SRC recommends the SDT revise the GCWRE definition to make clear a plant or facility consisting of individual units less than 200 MW must aggregate the derate to apply to the entire plant/facility to reach the 10% and 20 MW threshold; i.e., the GO of a plant consisting of five 190 MW units (950 MW) each experiencing a 10% derate (19 MWs) would aggregate the unit derates to determine whether the 20 MW threshold is met (19 MWs times 5 units = 95 MWs; because 95 MWs > 20 MWs, the Standard would apply). 

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 9/1/2022

- 0 - 0

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 9/1/2022

- 0 - 0

Avista supports the addition of a 20 megawatt minimum with the proposed Generator Cold Weather Reliability Event and its impact on GO responsibilities as it relates to CAPS within Requirement R6.

Mike Magruder, Avista - Avista Corporation, 1, 9/1/2022

- 0 - 0

Invenergy supports the addition of a megawatt minimum for requiring CAPs for derates. However, Invenergy believes the minimum could be better aligned with NERC’s BES criteria by establishing a minimum of 20 MVA for individual generating units identified under Inclusion I2 of the BES definition, or a minimum of 75 MVA for generating units identified under Inclusion I4 of the BES definition.

Rhonda Jones, Invenergy LLC, 5, 9/1/2022

- 0 - 0

Hot Answers

Natalie Johnson, Enel Green Power, 5, 9/1/2022

- 0 - 0

Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

- 0 - 0

Other Answers

This implementation is so extended, that these requirements will not be in force when the next Texas winter weather event occures.

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

- 0 - 0

Entergy, Segment(s) 1, 5, 12/13/2017

- 0 - 0

Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

- 0 - 0

Diana Torres, Imperial Irrigation District, 6, 8/23/2022

- 0 - 0

DTE Electric supports NAGF comments provided for this project

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

- 0 - 0

The implementation plan must be reconsidered in light of the the changes recommended in these comments.

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

- 0 - 0

Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

- 0 - 0

Talen Energy Marketing supports Talen Generation's comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

- 0 - 0

WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

- 0 - 0

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

- 0 - 0

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

- 0 - 0

Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

- 0 - 0

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

- 0 - 0

Yes, AECI supports the suggested approach.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

- 0 - 0

Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

- 0 - 0

Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

- 0 - 0

Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

- 0 - 0

Avista supports the proposed Implementation Plan.

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

- 0 - 0

Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

- 0 - 0

Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

- 0 - 0

Glenn Pressler, CPS Energy, 3, 8/30/2022

- 0 - 0

Avista supports the proposed Implementation Plan.

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

- 0 - 0

We appreciate the SDT’s consideration of industry comments and the modifications to the implementation timeline.

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

- 1 - 0

Ameren agrees with the EEI and the NAGF comments.

David Jendras, Ameren - Ameren Services, 3, 8/31/2022

- 0 - 0

Xcel Energy supports comments from EEI. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

- 0 - 0

Texas RE appreciates the drafting team’s efforts to make the implementation plan more clear by adding a graphic with the various effective and compliance dates.  Texas RE is concerned, however, with the 60-month timeframe to comply with Requirements R1 and R2.  Texas RE believes this poses a reliability risk and that entities should implement freeze protection measures and provide the capability to operated for at least one hour at the unit(s) Extreme Cold Weather Temperature as soon as possible in order to ensure there is no reliability gap. 

 

In the ERCOT region, generation entities were not given five years to comply with weather emergency preparedness rules and required to complete winter weather emergency preparation measures by December 1, 2021.  These measures included winterization, operation readiness, structural preparations, enclose sensors for cold weather critical components, address cold weather critical components failures that occurred between November 30, 2020, and March 1, 2020, provide training on winter weather preparations, and determine minimum design temperature or minimum experienced operating temperature, among other items.

 

Texas RE understands the intent of compliance various thresholds set forth in both Requirements R1 and R2 is to recognize that existing generation resources may find it more difficult to retrofit appropriate freeze protection measures.  Texas RE understand the technical rationale for requiring existing units to ensure capability of operating for at least one hour at the Extreme Cold Weather Temperature (R2) whereas new generation should be able to demonstrate it can operate for 12 hours at the Extreme Cold Weather Temperature given the putative differences between newer and older generating units. 

 

While Texas RE notes that the recently implemented Texas rules do not recognize this distinction between new and existing resources, Texas RE believes that the current proposed EOP-012-1 R1 and R2 define the scope of “existing” resources too broadly by appearing to connect the definition of “existing” resources to the effective date of the standard requirement.  Instead, Texas RE recommends the language in Requirements R1 and R2 reference the effective date of the governmental authority’s order approving EOP-012-1.  The effective date of the FERC order puts new and existing generating entities on notice that they will need to comply with the standard by the compliance date, obviating the need to extend the lower R2 compliance thresholds for “existing” resources to units constructed following the effective date of the FERC order. Otherwise, generating units built as much as 60 months from the FERC order date will be treated as “existing” units subject to the lower R2 requirements.  As Texas RE stated above, entities should not have five years to comply with these requirements, but at a minimum, resources constructed within this five-year window should not be treated as “existing” resources, but rather be required to meet the 12-hour requirements for new generation resources. 

 

Finally, Texas RE recommends clarifying the first section of the graphic to say that it is the Effective date of the Governmental Authorities’ approval of EOP-012-1 and the implementation plan.  This is consistent with the language in the paragraph below regarding the effective date of EOP-012-1.  Texas RE furthermore recommends that the Standard EOP-012-1 section on page 4 specify that the effective date of the standard applies to all requirements unless specified for a different compliance date or initial performance date.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

- 0 - 0

PG&E believes the implementation timeframes are reasonable.  PG&E agrees with the concerns raised by EEI and NAGF that are noted in the input to the earlier questions.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

- 0 - 0

Thomas Foltz, AEP, 5, 8/31/2022

- 0 - 0

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

LouisvilleG&E/KU support EEI's comments. 

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

- 0 - 0

Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

- 0 - 0

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

- 0 - 0

Southern Company agrees with EEI and supports the proposed implementation plan.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

- 0 - 0

Constellation has no additional comments. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

- 0 - 0

Reclamation supports the 18-month implementation time frame. Reclamation disagrees with the 60-month and 78-month implementation time frames. A 5-6 year implementation period is inconsistent with the expedited time frame that has been applied to the standards development process. Reclamation recommends the time would be better spent to conscientiously develop a workable standard than to expedite a defective standard and provide 5-6 years to try to make it work.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

- 0 - 0

Excluding the concerns raised in previous questions, these proposed implementation times are reasonable except for R7. Since R1 and R2 are not enforceable until 60 months, then a CAP implementation for R7 identified under R2 should follow this, not precede this time interval. 

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

- 0 - 0

Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

- 0 - 0

Excluding the concerns raised in previous questions, these proposed implementation times are reasonable except for R7. Since R1 and R2 are not enforceable until 60 months, then a CAP implementation for R7 identified under R2 should follow this, not precede this time interval. 

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

- 0 - 0

“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

- 0 - 0

Claudine Bates, Black Hills Corporation, 6, 8/31/2022

- 0 - 0

Josh Combs, Black Hills Corporation, 3, 8/31/2022

- 0 - 0

Micah Runner, Black Hills Corporation, 1, 8/31/2022

- 0 - 0

Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

- 0 - 0

Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

- 0 - 0

PNM supports the Implementation Plan.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

- 0 - 0

We recommend a twelve month implementation time frame for all revised and new requirements; and a three year implementation time frame for EOP-012-1 Requirements R1 and R2 as this seems to be a sufficient amount of time to become compliant given that the new requirements were included in The Joint Inquiry Report published on November 18, 2021, the additional year for standard development and regulatory review requirements.   A twelve month implementation would only miss implementation for one winter (2023-2024).

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

- 0 - 0

James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

- 0 - 0

The implementation timeline seems reasonable if the adopted standards are modified as recommended in these comments.

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

- 0 - 0

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

- 0 - 0

Exelon supports the proposed implementation plan.  

 

Submitted on behalf of Exelon, Segments 1 & 3

Daniel Gacek, Exelon, 1, 9/1/2022

- 0 - 0

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

- 0 - 0

Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

- 0 - 0

Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

- 0 - 0

Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

- 0 - 0

The implementation timeline seems reasonable if the adopted standards are modified as recommended in these comments.

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

- 0 - 0

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

- 0 - 0

Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

- 0 - 0

Excluding the concerns raised in previous questions, the NAGF believes that the proposed implementation times are reasonable.

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

- 0 - 0

ISO-NE reiterates its comments regarding the implementation plan from the Round 1 Comments.

ISO-NE believes the proposed 18 months for the implementation is excessive due to the fact that the first requirements that become effective with this 18 months are carried over from EOP-011-2 R7 & R8 into EOP-012-1 R3 and R5.  These requirements are already due to be effective April 1, 2023.  These “new” requirements in EOP-012-1 have been written to provide further details required for a previously written Generator Cold Weather Preparedness Plan, and changed Training to Annual Training.  Also, based on the CAP requirements in R6 and R7, “A CAP shall be written within 150 days or by July 1st, whichever is earlier” already provides some additional time from the original effective date for Generators that actually experience a trip attrinuted to freezing under the Standard.  Determined by the NERC Board approval date, an effective date of 12 months will potentially include the majority of the Winter Season of 2023-2024 under R3 and R5 instead of pushing the Standard off for another winter season, which was a concern for the EOP-011-2 implementation plan. 

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

LES, Segment(s) 6, 1, 3, 5, 10/8/2018

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

- 0 - 0

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

- 0 - 0

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 0 - 0

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

- 0 - 0

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

- 0 - 0

Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

- 0 - 0

Mark Young, Tenaska, Inc., 5, 9/1/2022

- 0 - 0

Imane Mrini, Austin Energy, 6, 9/1/2022

- 0 - 0

MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC).

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

- 0 - 0

Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

- 0 - 0

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

- 0 - 0

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

- 0 - 0

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

- 0 - 0

Invenergy supports the proposed implementation time frame.

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

- 0 - 0

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/6/2022

- 0 - 0

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 9/1/2022

- 0 - 0

Acciona Energy has no comments.

George Brown, Acciona Energy North America, 5, 9/1/2022

- 0 - 0

SMUD / BANC, Segment(s) 3, 6, 1, 4, 5, 8/18/2022

- 0 - 0

No for R6 only.  R6 should read, “a [GO] that experiences a Generator Cold Weather Reliability Event shall develop a CAP, no longer than July 1….”  This will ensure that sufficient time is allotted for corrective actions to be developed that may take many months to plan and implement effectively in accordance with all design and code requirements.  The primary focus of the GO if a GCWRE should occur should be to first implement immediate corrective actions that will allow the forced outage to be ended and the generating unit to be returned to service as safely and quickly as possible during an extreme cold weather event, and then develop long term corrective actions.  Allowing for additional time for development of a CAP will allow for improved engineering solutions since more planning and engineering resources can be allocated to developing and implementing the correction actions(s).  Additionally, the implementation of a CAP should be for up to 24 months due to supply chain challenges that the industry continues to experience.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

EEI supports the proposed Implementation Plan.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 5, 9/1/2022

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/1/2022

- 0 - 0

Alyssia Rhoads, Public Utility District No. 1 of Snohomish County, 1, 9/1/2022

- 0 - 0

John Liang, Snohomish County PUD No. 1, 6, 9/1/2022

- 0 - 0

Deanna Carlson, Cowlitz PUD, 5, 9/1/22

Deanna Carlson, Cowlitz County PUD, 5, 9/1/2022

- 0 - 0

The proposed implementation plan provides up to sixty months to implement the standard for individual units (eighteen months to identify the ECWT and develop a winterization plan and forty-two months to meet the reporting requirements), which could deter earlier compliance. Specifically, many units compete in wholesale markets and a unit owner may refrain from spending capital dollars (driving up its costs and thus its market bids) earlier than its competitors who delay compliance to later dates. In this way, the timeline works as a disincentive to early compliance.

The SRC understands the need to recognize the complexities of winterization for different technologies and individual unit characteristics, but to avoid creating disincentives to earlier compliance, the SRC recommends a shorter period of twelve months to identify the ECWT and develop a winterization plan and an additional twenty-four months for all units (new and old) to comply with the winterization requirements and adding an exception process to the extent a GO can document compliance will take longer due to an individual unit’s characteristics. The GO should have to document unit-specific exceptions and make the documentation available for review and audit.

The SRC believes an implementation plan with an early, but realistic, compliance date that allows for reasonable exceptions avoids the disincentive created by a lengthy process that would allow even units facing minimal winterization requirements to refrain from complying earlier.

 

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 9/1/2022

- 0 - 0

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 9/1/2022

- 0 - 0

Avista supports the proposed Implementation Plan.

Mike Magruder, Avista - Avista Corporation, 1, 9/1/2022

- 0 - 0

Invenergy supports the proposed implementation time frame.

Rhonda Jones, Invenergy LLC, 5, 9/1/2022

- 0 - 0

Hot Answers

Natalie Johnson, Enel Green Power, 5, 9/1/2022

- 0 - 0

R3.2 and R3.3 are unnecessary from a performance-based standard perspective. Requiring a CAP for any failure to run or any derate from a cold weather event is sufficient to provide performance under the standard. However, requiring the creation of lists of equipment and protective measures, while good engineering practice, are not good compliance activities. This results in administrative burden for administration’s sake.

In addition, the standard is full of subjective, ambiguous, and in-auditable language. Phrases like “typically available”, and provisions that allow for any “technical, commercial or operational constraints” as defined by the GO are subjective and open to interpretation, and will compliance certainty difficult for entities. This includes referencing non-NERC contracts such as OATTs or “other contracatual arrangement[s]” in the Applicability language. All of these factors will result in a high compliance burden and risk of fines and significant capital spends on upgrades due to standard uncertainty and ambiguity.

Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

- 0 - 0

Other Answers

The modifications continue to burden small utilities who already operate in sub-freezing weather.  These requirments put significant burden on staff unnecessarily, and expose the parent company to administrative penalties, not performance penalties.

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

- 0 - 0

Entergy, Segment(s) 1, 5, 12/13/2017

- 0 - 0

Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

- 0 - 0

Diana Torres, Imperial Irrigation District, 6, 8/23/2022

- 0 - 0

DTE Electric supports NAGF comments provided for this project

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

- 0 - 0

The cost-effective sequence of events for bolstering generation plant cold weather protection is to firstly obtain valid capability data (based on WCT or DBT-plus-20 mph, not DBT alone), then have RCs, BAs and TOPs identify their true reserve margins for extreme cold weather events.  These parties can then adopt the appropriate market solutions – incentivizing upgrades where shortages are predicted, and accepting the status quo where no action is needed.

EOP-012-1 presently takes an extremely non-cost-effective approach, immediately leaping to a draconian and unnecessary requirement for retrofitting of existing units.  This problem is exacerbated by using an incorrect basis for Extreme Cold Weather Temperature (DBT only, instead of WCT or DBT-plus-20 mph) and an incorrect protect-to target (0.2 percentile instead of historical worst-case weather).  GOs can thereby be lured into installing inadequate protection, setting them up for immense market losses for 43 hours per decade (or more) if sold-ahead and, due to freeze-up, having to buy power on the spot market at prices that can reach $1000/MWh or higher (large units can lose $1MM per hour in this fashion).  This situation also paves the way for having to tear-out marginal, EOP-012-1-based heat tracing/insulation systems that fail to protect as hoped and start over as an R6 CAP.

It also bears mentioning that the ultimate, “low hanging fruit,” for enhancing BES wintertime reliability is to put additional generation units online out-of-merit when an extreme storm is impending, since it is far easier to keep a unit running during severe weather than it is to start-up under such circumstances.  EOP-012-1 may not be the place to address this issue, but until NERC acts in this respect, or at least encourages ISOs to act, it is not apparent that a sincere effort is being made regarding cost effectiveness.

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

- 0 - 0

Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

- 0 - 0

Talen Energy Marketing supports Talen Generation's comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

- 0 - 0

We believe that establishing a new Extreme Cold Weather Temperature may result in the need for costly upgrades to coal handling facilities, which may only become apparent during the implementation period.  Generator Owners will be reluctant to make these costly investments unless and until the need for them is proven.

WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

- 0 - 0

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

- 0 - 0

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

- 0 - 0

NextEra Energy is not supplying a position or comment on the cost effectiveness of these proposed changes.

Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

- 0 - 0

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

- 0 - 0

Yes, AECI supports the suggested approach. 

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

- 0 - 0

Without a definition of “commercial constraints” it is difficult to know how R1 and R7 should be evaluated for compliance. We recommend the Standard Drafting Team make it clear in the standard that “commercial constraint” is limited to the inability to obtain necessary equipment or services after reasonable efforts due to supply issues or unavailability of services. Without this limitation, “commercial constraints” could be interpreted to mean cost prohibitions or economic pressures on the commercial profitability of a unit. It is our understanding that cost prohibitions or economic pressures are not intended to be acceptable justifications for not implementing freeze protection measures. 

Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

- 1 - 0

Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

- 0 - 0

Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

- 0 - 0

Avista supports the proposed change to the standard.

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

- 0 - 0

Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

- 0 - 0

Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

- 0 - 0

Glenn Pressler, CPS Energy, 3, 8/30/2022

- 0 - 0

Avista supports the proposed change to the standard.

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

- 0 - 0

Most BAs in the US are summer peaking systems (the seasonal spread increases to the south), and a significant fraction of generation is located in the RTOs with annual capacity markets that offer no distinction between summer peaking generators and all others generators.  Consequently, the proposed standard will impose a requirement on a significant number of generators that are not needed to meet the winter load.  Moreover, generators that historically have not been needed to serve winter load typically do not procure firm transportation rights or forward contract for fuel.  This forces generators that may or may not be able to obtain fuel and have historically not been needed to serve winter load to incur the cost of compliance.  Regardless whether these costs are born by the ratepayer or absorbed by the generator owner, this is not a cost effective outcome.  A cost effective approach, while enhancing reliability, would be to procure the exact quantity, and no more, of reliable generation necessary to prevent wide-scale manual load shedding. 

We reiterate that the BAs are best positioned to quantify their needs under a range of weather scenarios aligned with their Emergency Operating Plans, to specify an absolute performance requirement (inclusive of weather, fuel, environmental restrictions, etc.), and levy penalties for non-performance in the most cost effective manner.  As an example, if a BA procured sufficient weatherized winter supply backed by certain fuel, the SDT’s concern of “premature retirements” would be moot.  Additionally, the Regional Entities’ would have bright line criteria to apply to determine whether generator owners are complying with any commitments made to their BAs.

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

- 1 - 0

David Jendras, Ameren - Ameren Services, 3, 8/31/2022

- 0 - 0

Xcel Energy can support the cost-effectiveness of implementing this Standard, predicated on the ability that R2 is tied to R6 and, subsequently, R7. The ability to declare qualifying units as unable to implement corrective actions is a required element for Xcel Energy to support the implementation of this Standard in a cost-effective manner. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

- 0 - 0

Texas RE recommends the SDT consider including parameters or examples for when the use of a technical, commercial, or operational constraint is justifiable for not implementing a CAP in Requirement R7.  The use of the phrase “as defined by the Generator Owner” is broad and could lead to reliability gaps.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

- 0 - 0

At this time PG&E cannot determine if the proposed modifications are cost effective.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

- 0 - 0

Thomas Foltz, AEP, 5, 8/31/2022

- 0 - 0

Dominion Energy is of the opinion that the recommended alternative for Requirement 2 discussed previously in response to Question 5 is a more cost-effective manner to address the reliability concerns of generation not operating as planned during extreme cold weather.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

LouisvilleG&E/KU support EEI's comments. 

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

- 0 - 0

Difficult to weigh-in since actual potential costs are unknown at this time.

Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

- 0 - 0

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

- 0 - 0

Southen Company agrees that the proposed requirements are cost effective assuming the exceptions provided in R1 and R7 remain the same.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

EOP-012 achieves a cost effective solution because of the exemptions built in R7 for technical, commercial, or operational constraints that may apply to a particular generator. Constellation notes, however, that the standard could provide greater clarification that lack of cost recovery is a commercial constraint to implementation of Requirement R1 and any Corrective Action Plan (CAP) under Requirement R2 or exception under Requirement R7. It is critical that any adopted weatherization requirements clearly ensure that lack of cost recovery is included under the qualified “commercial” constraints listed in Requirements R1, R2 and R7 and specifically outline how determinations for each category of constraint will be decided. In addition, under Requirement R2, Generator Owners should have the option to develop and implement a CAP or be allowed to explain in a declaration why corrective actions are not being implemented due to any technical, commercial, or operational constraints as defined by the Generator Owner. These options should not be across two separate Requirements (R2 and R7) within the draft standard. Streamlining R2 and R7 into one Requirement will create efficiencies in compliance for Generator Owners and in compliance monitoring reviews for the NERC Regional Entities.

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

- 0 - 0

EOP-012 achieves a cost effective solution because of the exemptions built in R7 for technical, commercial, or operational constraints that may apply to a particular generator. Constellation notes, however, that the standard could provide greater clarification that lack of cost recovery is a commercial constraint to implementation of Requirement R1 and any Corrective Action Plan (CAP) under Requirement R2 or exception under Requirement R7. It is critical that any adopted weatherization requirements clearly ensure that lack of cost recovery is included under the qualified “commercial” constraints listed in Requirements R1, R2 and R7 and specifically outline how determinations for each category of constraint will be decided. In addition, under Requirement R2, Generator Owners should have the option to develop and implement a CAP or be allowed to explain in a declaration why corrective actions are not being implemented due to any technical, commercial, or operational constraints as defined by the Generator Owner. These options should not be across two separate Requirements (R2 and R7) within the draft standard. Streamlining R2 and R7 into one Requirement will create efficiencies in compliance for Generator Owners and in compliance monitoring reviews for the NERC Regional Entities.

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

- 0 - 0

Reclamation observes that the SDT has asserted that it has the support of industry except for minor details in the standard and is promising improvements in “Phase 2” of this project. Reclamation can identify no basis for this assertion based on the failure of the previous ballot and the refusal of this SDT and other SDTs to modify “legacy” language in subsequent standards modification projects once language has been approved. Reclamation asserts that a two-phase approach to developing standards that inherently requires re-versioning Phase 1 standards in Phase 2 is not cost effective. Reclamation recommends a good approach to promulgating quality standards is not to force a defective product through the system but rather to spend the necessary time to make the product right the first time. Reclamation observes that many entities have provided direct suggestions for improvement starting with Draft 1 of this project, but the SDT took neither the time nor the effort to properly consider them.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

- 0 - 0

The recommendations are inherently not cost-effective for Generator Owners, so changing the standard language will not make them so.

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

- 0 - 0

Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

- 0 - 0

The recommendations are inherently not cost-effective for Generator Owners, so changing the standard language will not make them so.   

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

- 0 - 0

“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

- 0 - 0

BHC agrees with the first statement but cannot determine cost effectiveness and offers no comment on cost effectiveness. 

Claudine Bates, Black Hills Corporation, 6, 8/31/2022

- 0 - 0

BHC agrees with the first statement but cannot determine cost effectiveness and offers no comment on cost effectiveness. 

Josh Combs, Black Hills Corporation, 3, 8/31/2022

- 0 - 0

BHC agrees with the first statement but cannot determine cost effectiveness and offers no comment on cost effectiveness.

Micah Runner, Black Hills Corporation, 1, 8/31/2022

- 0 - 0

BHC agrees with the first statement but cannot determine cost effectiveness and offers no comment on cost effectiveness.

Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

- 0 - 0

Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

- 0 - 0

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

- 0 - 0

James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

- 0 - 0

The modifications in proposed EOP-012-1 continue to raise cost effectiveness concerns, because the standards are tied to a very conservative temperature standard of the 0.2 percentile lowest hourly temperature experienced at the closest weather station since Jan. 1, 2000. Generators in the TRE region have no mechanism for cost recovery for any capital expenditures or other expenses they incur to implement the new standards. Generators in other reliability regions similarly may not have the ability to recover costs to implement weather preparedness standards, especially if they are not rate regulated companies. If the standards are revised as recommended throughout Vistra’s comments (and the comments being filed by Texas Competitive Power Advocates, of which Vistra is a member), then the standard would meet the key recommendations in The Report in a cost-effective manner. However, if the standard is adopted as currently proposed, there would be serious questions regarding the cost-effectiveness of the standard, and it could even lead to early retirements or cancellations or delays of new resources.

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

- 0 - 0

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

- 0 - 0

Daniel Gacek, Exelon, 1, 9/1/2022

- 0 - 0

At this time, SIGE is unable to quantify if the modifications will be cost-effective. 

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

- 0 - 0

Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

- 0 - 0

Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

- 0 - 0

Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

- 0 - 0

The modifications in proposed EOP-012-1 continue to raise cost effectiveness concerns, because the standards are tied to a very conservative temperature standard of the 0.2 percentile lowest hourly temperature experienced at the closest weather station since Jan. 1, 2000. Generators in the TRE region have no mechanism for cost recovery for any capital expenditures or other expenses they incur to implement the new standards. Generators in other reliability regions similarly may not have the ability to recover costs to implement weather preparedness standards, especially if they are not rate regulated companies. If the standards are revised as recommended throughout Vistra’s comments (and the comments being filed by Texas Competitive Power Advocates, of which Vistra is a member), then the standard would meet the key recommendations in The Report in a cost-effective manner. However, if the standard is adopted as currently proposed, there would be serious questions regarding the cost-effectiveness of the standard, and it could even lead to early retirements or cancellations or delays of new resources.

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

- 0 - 0

Refer to above comments

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

- 0 - 0

AES Clean Energy supports comments submitted by NAGF.

Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

- 0 - 0

The NAGF does not agree that the draft EOP-012 addresses the concerns from the Report in a cost-effective manner.  The NAGF is concerned that the proposal, while a great improvement from the initial posting, fails to address the concerns from the Report in several areas. These areas include:

  • The proposed standard does not require significant changes beyond calculating the Extreme Cold Weather Temperature and listing components susceptible to the cold weather.
  • The design requirements only require the Generator Owner to identify why nothing was done, not make changes to the design to make the generator more reliable during winter. As the SDT is trying to address the issue of retrofit without being able to address the compensation issue, we understand why this compromise is being proposed.
  • The Report states that many units failed before reaching their minimum design criteria. The proposed standard does not require a CAP if this occurs. The CAP is only required if a failure occurs above the ECWT, which has no significant meaning to a generator’s design capability. This feature also appears to undermine the requirement to provide the BA, TOP and RC with a minimum operating temperature to be used during the planning process.
  • The proposed standard does require generators to address the conditions seen, specifically temperature, wind and moisture combined. For example, a wind turbine is likely able to operate to a minimum temperature of 20 degrees Fahrenheit if it is dry but will have blade icing occur at 32 degrees Fahrenheit if there is moisture. If the ECWT for that site is 25, a CAP will be required for blade icing, but not if the nacelle ices at 22 degrees due to failure to close vents. 

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

- 0 - 0

ISO-NE supports the comments of the SRC that cost recovery mechanism be left to FERC and the Industry to determine how to compensate GOs for any upgrades if needed. 

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

LES, Segment(s) 6, 1, 3, 5, 10/8/2018

- 0 - 0

NPPD agrees EOP-012-1 meets the key recommendations in The Report in a cost effective manner.  The sum of all the components of the proposed Standard as written create a balanced approach between the need to improve grid reliability and resiliency during cold weather events and the need to participate in a competitive market.

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

- 0 - 0

Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

- 0 - 0

The MRO NSRF agrees EOP-012-1 meets the key recommendations in The Report in a cost effective manner.  The sum of all the components of the proposed Standard as written create a balanced approach between the need to improve grid reliability and resiliency during cold weather events and the need to participate in a competitive market.

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 0 - 0

For Canadian entites, the necessary cold weather practices are already in place. The administrative burden associated to the tasks being required in the standards outweigh the reliability benefits, as we already have a good handle on planning, operations and maintenance activites in cold (and even extreme cold) weather.

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

MidAmerican Energy supports the MRO NSRF comments for this question. 

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

- 0 - 0

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

- 0 - 0

EDFR supports the comments submitted by NAGF.

Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

- 0 - 0

This is essentially a return on investment question.  It is difficult to answer this question until there is an understanding of total cost recovery required to implement this design standard for the entire BES.   The Report’s #2 recommendation was for markets or consumers to provide cost recovery. While NERC cannot mandate cost recovery, NERC can provide exemptions for compliance until markets and regulatory agencies determine the need and the method of compensating Generator Owners for their investment in winter weatherization.

Mark Young, Tenaska, Inc., 5, 9/1/2022

- 0 - 0

Imane Mrini, Austin Energy, 6, 9/1/2022

- 0 - 0

MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC).

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

- 0 - 0

Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

- 0 - 0

Madison Gas and Electric supports the comments from the MRO NSRF.

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

- 0 - 0

Madison Gas and Electric supports the comments of the MRO NSRF

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

- 0 - 0

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

- 0 - 0

For EOP-012-1, Invenergy is unable to quantify the overall costs and benefits to arrive at a definitive conclusion about the cost effectiveness of the current draft.

However, as noted in Invenergy’s previous responses, the current proposal yields an arbitrarily stringent standard that could impose more onerous requirements than are necessary to ensure generator availability during the prolonged extreme cold events – occurring over multiple hours or days – that this Standard is intended to address. The alternative approach Invenergy suggests would reasonably be expected to yield a more cost-effective approach to meeting the key recommendations in the Joint Inquiry Report.

Invenergy also remains concerned that certain generating units, including independent power producers, may be required to bear significant incremental costs to comply with the standard without a corresponding mechanism for recovering those costs.

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

- 0 - 0

No Comment

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/6/2022

- 0 - 0

CEPM believes that as an IPP (non-Utility) there needs to be better defined means for IPPs to recoup costs for modification of existing units to operate to the minimum operating temerpature prior to R2 becoming enforcable. We believe the SDT does have an obligation with support of these approaches along with the GO and ISO/RTO.

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 9/1/2022

- 0 - 0

Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 9/1/2022

- 0 - 0

SMUD / BANC, Segment(s) 3, 6, 1, 4, 5, 8/18/2022

- 0 - 0

No for R5 only.  The R5 requirement should focus on the content of the training to be given, the desired audience of that training, and the completion date.  Requiring identification of the entity responsible for actually giving the training in the requirement will not increase the efficacy of the training material.  It simply creates an administrative item to be tracked that adds nothing to generating unit reliability.  Content, audience and completion of the required training accomplish that, not the denotation of who will be performing the training.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 5, 9/1/2022

- 0 - 0

Cowlitz agrees with comments provided by the North American Generator Forum.

Russell Noble, Cowlitz County PUD, 3, 9/1/2022

- 0 - 0

Alyssia Rhoads, Public Utility District No. 1 of Snohomish County, 1, 9/1/2022

- 0 - 0

John Liang, Snohomish County PUD No. 1, 6, 9/1/2022

- 0 - 0

Agree with comments provided by Russell Noble.

Deanna Carlson, Cowlitz County PUD, 5, 9/1/2022

- 0 - 0

The SRC believes the proposed revisions do not meet the key recommendations, regardless of whether they are “cost effective” (based on our comments, above). If the goal of this Standard is to ensure generators ride-through extreme weather events, the SDT should draft a Standard to accomplish that goal. NERC should leave the issue of compensation to FERC and other regulators to determine how to compensate GOs for the cost of winterization and freeze protection measures (e.g., areas of the country using cost-based rates could include the cost of upgrades in the rate base to establish customer pricing; parts of the country with wholesale markets can develop market tools to provide compensation to generators who upgrade resources). See, Key Recommendation 2 in the Joint Report.

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 9/1/2022

- 0 - 0

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 9/1/2022

- 0 - 0

Avista supports the proposed change to the standard.

Mike Magruder, Avista - Avista Corporation, 1, 9/1/2022

- 0 - 0

For EOP-012-1, Invenergy is unable to quantify the overall costs and benefits to arrive at a definitive conclusion about the cost effectiveness of the current draft.

However, as noted in Invenergy’s previous responses, the current proposal yields an arbitrarily stringent standard that could impose more onerous requirements than are necessary to ensure generator availability during the prolonged extreme cold events – occurring over multiple hours or days – that this Standard is intended to address. The alternative approach Invenergy suggests would reasonably be expected to yield a more cost-effective approach to meeting the key recommendations in the Joint Inquiry Report.

Invenergy also remains concerned that certain generating units, including independent power producers, may be required to bear significant incremental costs to comply with the standard without a corresponding mechanism for recovering those costs.

Rhonda Jones, Invenergy LLC, 5, 9/1/2022

- 0 - 0

Hot Answers

Enel would like clarifications included that criteria applies only to available capacity as indicated by the forecasted power curve.  Intermittent resources may not be available due to low wind or irradiance.  Another example would be a planned outage for maintenance.  It should be clarified that criteria applies to available capacity and not nameplate for intermittent resources.  Enel suggests this clarification could be added with an accompanying footnote in the appropriate places.

Enel also suggests that R2 adds the following clarifying language:  Generating unit(s) that are not capable of operating for one (1) hour at its Extreme Cold Weather Temperature shall develop a Corrective Action Plan (CAP), according to R7, for the identified issues, including identification of any needed modifications to the cold weather preparedness plan required under Requirement R3.

Additionally, Enel suggests that the language for CAPS only refer to 150 days for a deadline without the July 1 reference for clarity and fairness so everyone gets the same deadline. 

Enel agrees with MRO NSRF’s concern regarding the concurrent twenty (20) mph wind speed.

Natalie Johnson, Enel Green Power, 5, 9/1/2022

2021-07_Unofficial_Comment_Form_second ballot_082022 (Enel 9-1-2022).docx

- 0 - 0

FMPA also supports the comments of the Transmission Access Policy Study Group (TAPS), which are as follows:

We understand R1 and R2 as requiring GOs to implement freeze control measures that they reasonably believe, based on good engineering judgment and their experience with their particular units and weather patterns, will result in the unit being able to operate continuously for the applicable time at the Extreme Cold Weather Temperature.  Our understanding of the proposed requirements is that if a new or existing unit experiences a Forced Outage as a result of a Generator Cold Weather Reliability Event, even if the Forced Outage occurs after less than twelve hours (for a new generator) or one hour (for an existing generator) of continuous operations, the Forced Outage will not constitute evidence of noncompliance with R1 or R2.  Instead, the GO will develop and implement a CAP pursuant to R6 and R7, as it would in response to any Generator Cold Weather Reliability Event.  The contrary interpretation—that R1 and R2 require freeze protection measures that are 100% guaranteed to work—would require a level of certainty that simply does not exist.  Generators are complex machines; they sometimes fail in unforeseen ways.  This problem is only compounded by the fact that, as noted by multiple panelists at the April 27-28, 2022 FERC, NERC, and Regional Entities Technical Conference on Improving Winter-Readiness of Generating Units, a cold weather event cannot be simulated ahead of time to allow functional testing of a unit’s set of winterization measures.  Finding a GO noncompliant with R1 or R2 based on the failure in a particular instance of winterization measures it reasonably believed, based on the information available to it prior to the cold weather event, would be adequate, would not enhance reliability. 

We read R2 as providing that, where an existing unit is not capable of operating continuously for one hour at the Extreme Cold Weather Temperature, the method by which the GO “ensure[s] its generating unit(s) add new or modify existing freeze protection measures as needed” is the development of a CAP pursuant to R2.  In other words, a GO demonstrates compliance with R2 by demonstrating either that it has implemented appropriate freeze protection measures, or that it has developed a CAP. 

The SDT has indicated that it plans to revisit the language of EOP-012-1 as part of Phase 2 of this project.  Although we believe that our readings of the requirements, as outlined above, are consistent with the SDT’s intent, we strongly recommend that Phase 2 clarify the language of R1 and R2 on these issues.  Expressing the SDT’s intent more clearly would reduce the risk of confusion and conflicting interpretations.

 

Florida Municipal Power Agency (FMPA), Segment(s) 5, 4, 3, 6, 6/17/2022

- 0 - 0

Other Answers

The focus needs to be on those entities who have failed to perform during cold weather, and should not impact those who operate facilities located and operated in cold climates where freezing temperatures are common.  The standard and VSLs all point to admistrative activities and not performance activities.  This creates a nighmare during audits and exposure to many companies who should not be considered risks.

Kevin Conway, On Behalf of: Public Utility District No. 1 of Pend Oreille County, , Segments 1, 3, 5, 6

- 0 - 0

General area aspects have not been captured to help determine the extreme weather temperature aspect.  Geographic guidance from the BA could be beneficial. From a technical view should we have some type of forwarding looking element.

Entergy, Segment(s) 1, 5, 12/13/2017

- 0 - 0

Sean Steffensen, IDACORP - Idaho Power Company, 1, 8/23/2022

- 0 - 0

None

Diana Torres, Imperial Irrigation District, 6, 8/23/2022

- 0 - 0

DTE Electric supports NAGF comments provided for this project

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

- 0 - 0

Talen Energy supports the supplemental comments of the NAGF, and adds those presented below.

{C}1.      {C}R1 says that GO/GOPs must, “Explain in a declaration, any technical, commercial, or operational constraints,” but there is no mechanism for these inputs to be conveyed to RCs, BAs and TOPs.  Such limitations should be declared in R3.5 of EOP-012-1, and R3.5 should be amended to require that data be sent to RCs, BAs and TOPs.

{C}2.      {C}The exceptions of the second bullet point of R1 should be revised to disallow failure to winterize new units simply because the owners don’t feel like spending the money.  Reliability standards should set the rules for being allowed to sit at the table.  Perhaps the expression, “preclude the ability,” was not meant to grant carte blanche in this respect, but if so it is an example of the need for use of clear language in reliability standards.

If there is an implied regulatory hurdle to be cleared in this respect, as opposed to relying solely on the judgment of GOs, guidance is required in EOP-012-1 for emerging technologies such as preventing ice accumulation on wind turbine blades.  It may not be possible to set firm rules in such cases, but NERC should create incentives to advance the state of the art (the “best available technology”) rather than permanent loopholes.

{C}3.      {C}The “demonstrates” of M1 should be limited to major freeze prevention measures, such as heat tracing/insulation systems and wind turbine nacelle heating.  GOs should not have to obtain design calculations for every lube/seal oil reservoir heater, building heater, enclosure heater and other minor winterization measure for plants built many decades ago, especially since there are no calculations for wind barriers, CTG inlet air heaters and the like.

{C}4.      {C}The entry, “features. Any,” in M1 should be, “features, any.”

{C}5.      {C}The, “add new or modify,” language of R2 should be expunged, as well as the percentile based performance criterion of the Extreme Cold Weather Temperature definition, for the reasons given earlier in these comments.  The CAPs of R2 should allow revising the capability declaration of R3.5.2 in lieu of modifying the facility, again as explained earlier.

{C}6.      {C}The Extreme Cold Weather Temperature criterion should be replaced in R3.1, and everywhere else it is used in EOP-012-1, with the historical worst-case WCT (or DBT-with-20 mph wind value), as mentioned previously.  The only calculations then required involve converting DBT+wind values to WCT, which is so simplistic that there’s no need to document the math as compliance evidence. 

{C}7.      {C}The Guidance section of EOP-012-1 should explain that the high level of uncertainty inherent in winterization makes it unnecessary to seek perfection in compiling weather data for R3 of EOP-012-1.  Readings from the nearest airport are acceptable, and in fact are often more accurate than plant measurements.  Non-official sources of weather data are acceptable so long as they have a reputable basis, e.g. extremeweatherwatch.com draws its information from the NOAA database. 

{C}8.      {C}Revise or eliminate R3.2, “Documentation identifying the Generator Cold Weather Critical Components,” as discussed earlier in these comments.

{C}9.      {C}Revise R3.3 in accordance with our earlier comments, i.e.

{C}-         include congealing when defining the term “freezing”

{C}-         have precipitation stand separate from temperature/wind-related considerations

{C}-         differentiate between principal and secondary winterization measures

{C}-         cover temperature and wind in a combined fashion (WCT, or DBT-plus-20 mph) 

Regarding the last of these points, DBT and wind speed are inputs to a single heat transfer calculation, ref. the formulae in IEEE-515, and must therefore be handled together.  Calling for identification of DBT capability and, separately, “the  cooling effects of wind,” is like identifying the load capability of a generator in terms of voltage, with separate consideration of the effect of current.

{C}10.  {C}R3.5 is unchanged from EOP-011-2 and might therefore be thought to be noncontroversial, but this earlier standard is not yet enforceable, so no case law has been developed to bring its ambiguities and omissions into focus.  These gaps should be closed in the Guidance section of EOP-012-1 as follows:

{C}a.      “Capability” in the present context means real and reactive power output.  That is, NERC is seeking information regarding factors that could limit output during winter storms below the values that grid operators are expecting. “Availability” refers to ability to start-up and remain online

{C}b.     The word, “concerns,” in R3.5.1.2 pertains to fuel supply and inventory issues known to GO/GOPs or reasonably expected, not speculations about what might go wrong.  Known inability of a NG pipeline company to support all plants on their system at maximum load during extended periods of peak demand would be reportable, for example, but GO/GOPs are not expected to evaluate fuel suppliers’ pipelines, compression/pumping equipment, contract terms or other matters over which generation entities have no control.  Also, do not provide non-actionable inputs such as, “Fuel contracts contain a force majeure clause,” or, “Can’t get fuel oil deliveries if the roads are closed.”

{C}c.      The term, “Environmental constraints,” in R3.5.1.4 pertains to maximum output.  Narrowing of the max-to-min load environmentally compliant turndown range as the weather gets colder, as may be experienced by some combustion turbine generator units with dry low-NOx combustors, need not be reported.

{C}d.     Cold-startup times for extreme winter weather conditions should be added to R3.5.1, given the use of this criterion in defining the term, “Generator Cold Weather Reliability Event”

{C}e.      The need to provide evidence for the design temperature option of R3.5.2 should be limited to major freeze prevention elements, as was mentioned earlier in these comments.  A unit with heat tracing and insulation designed for -25 F DBT and a 10 mph wind (-47 F WCT) may report a value of -19 F (-47 F WCT with a 20 mph wind), for example, without confirming that the lube oil heater has the same capability.  This approach is especially important for peaking units that were built long ago and run primarily in the summer, not winter.  They may not have the one-hour proof of R2, and design information for minor freeze prevention elements simply doesn’t exist.  Demanding that such equipment be reverse-engineered would be unreasonable.

{C}f.       A look-back period should be specified for the historical operating temperature option of R3.5.2.  We suggest the shorter of five years and the time that the unit has been in service, with going back to the most recent extreme cold weather event being preferred for units old enough to do so.

{C}g.      A requirement to report data to the RC, BA and TOP should be added to R3.5.  They need to use these inputs, but there’s presently no requirement that they be reported to them.

{C}11.  {C}R4 should be deleted.  Plants must perform pre-winter preparations annually, and these activities should include updating for the past year the cold weather capability and other information communicated under R3.5 to the RC, BA and TOP.  There is no benefit from endlessly repeating analyses, especially after implementing the changes recommended above.

{C}12.  {C}The term, “unit-specific,” in R5 should be changed to, “plant-specific.”  A facility with three fossil units, for example, should cover any individual-unit idiosynchrosies, but it does not need three different training courses.

{C}13.  {C}The Guidance section of the standard should make it clear that annual training of maintenance and operations personnel for R5 should include on-condition activities in addition to the the NERC cold weather preparedness plan.  That is, R3.4 establishes that the measures covered by EOP-012-1 are limited to those performed prior to winter in once-and-done fashion, and plants also have tasks to be performed as real-time weather conditions dictate, such as enhanced operator rounds, call-outs, and cycling mechanical-draft cooling tower fans to prevent excessive ice formation.  The Guidance section of the standard should also advise that training may be split into a generic freeze prevention course and a supplemental, plant-specific module.

{C}14.  {C}R6.3 does not identify the level of performance to be achieved by CAPs.  It should be revised to explicitly say that it can consist of equipment modifications or adjustments to the cold weather capability declared for R3.5.2.  If for example a plant with heat tracing and insulation designed for -20 F with a 20 mph wind incurs a freeze-related forced outage it can revise the R3.5.2 value or, as a market decision, add-to or modify equipment.

{C}15.  {C}Regarding our earlier comments on historical worst-case temperature vs the present basis of the Extreme Cold Weather Temperature definition, R6 presently says that forced outages, derates and failures to start must be corrected if occurring during 0.2 percentile-and-up conditions, but for the coldest 43 hours per decade freeze-up instances and the blackouts, deaths and damage they cause, are acceptable – no corrective action is needed.  How can this be called a “reliability” standard?

{C}16.  {C}Having R6 require CAPs and R7 provide a no-limits offramp (“technical, commercial, or operational constraints”) is strange and ineffective.  PRC-004 has been cited as establishing a precedent in this respect, but this is not the case.  R5 of PRC-004-6 says that entities must establish a CAP or state a valid technical (not commercial) justification for not doing so (“beyond the entity’s control or would not improve BES reliability”), then R6 says that CAPs developed in R5 must be implemented.   

R7.1 should be amended to simply require implementation of the CAP, given the R6.3 changes requested above (modification of R3.5.2 capability declarations is sufficient).  Justifications are not then required.  The present R6-R7 combination seems to says that GO/GOPs must identify solutions to freeze-up problems, then they have the option of doing nothing, but if they choose this alternative it remains an open compliance issue forever.

Donald Lock, Talen Generation, LLC, 5, 8/25/2022

- 0 - 0

The cold weather exclusion should be removed from the Applicability section and instead a requirement should be added to require the GO to prove operability in cold weather through analysis/studies. This is a common practice among standards that apply to a subset of BES Elements or Facilities. Tri-State suggests that the SDT look at similar standards/requirements such as TPL-007-4, R5, PRC-023-4 R6, and PRC-002-2 R1.

The Applicability section is not auditable and leaving the exception within that section could allow for entities to incorrectly exclude their units with no repercussions. This in turn could cause a reduction in grid reliability as Generator Owners continue to be unprepared for cold weather events.

Donna Wood, Tri-State G and T Association, Inc., 1, 8/25/2022

- 0 - 0

Talen Energy Marketing supports Talen Generation's additional comments.

Jennifer Hohenshilt, On Behalf of: Talen Energy Marketing, LLC, , Segments 6

- 0 - 0

WEC Energy Group, Segment(s) 3, 4, 5, 6, 7/14/2022

- 0 - 0

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 8/26/2022

- 0 - 0

No additional comments.

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

For EOP-012-1 R6, Tacoma Power recommends deleting the “or by July 1, whichever is earlier” language. If a cold weather event occurred in late Spring or early Summer (i.e. April through June), an entity would have less than 150 days to holistically review the event and develop a CAP.

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

- 0 - 0

NextEra Energy supports a weatherization framework that provides flexibility for generators to adopt new effective, commercially viable and proven technologies, but cautions against requiring the adoption of unproven technology that could damage equipment or otherwise reduce the operating life and void warranties, thereby reducing overall reliability.

Silvia Mitchell, NextEra Energy - Florida Power and Light Co., 1, 8/30/2022

- 0 - 0

None at this time.

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 8/30/2022

- 0 - 0

AECI has 2 additional comments for this standard not covered in the previous comment sections. These comments are specific to R5 and R6 respectively.


R5: In regards to the proposed verbiage requiring “generating unit-specific training”, it is our opinion that this could be overly burdensome for stations with multiple units; particular for those stations with multiple units of a similar design (a.k.a. “sister” units). Recommend modifying this
requirement to require station-specific training in lieu of generating unit-specific training. It is our opinion that this modification will allow the GO/GOP the flexibility to develop their training modules with an appropriate level of detail so as to sufficiently train station personnel
without requiring them to create multiple modules with similar or identical content.

 

R6: Concerning the proposed timeline for the development of a CAP, it is our recommendation that the July 1st date be removed from this requirement. The rationale for this recommendations is thus: 150 days prior to July 1st is Feb 1st for non-leap years and Feb 2nd for leap years. Moreover, the July 1st timeline is further condensed if a Generator Cold Weather Reliability Event (GCWRE) occurs in March or April. Lastly, the stated intent of the timeframe options within the Technical Rationale is to allow GO’s to review multiple events holistically following a winter season. In certain areas of the country, a GCWRE could realistically occur as early as late-October. In this instance, the latest possible date for the development of a CAP would be March 30th.


Given that it is also realistic for a GCWRE to occur in March, 150 days seems a reasonable number of days to cover all but the most extreme scenarios. Therefore, we recommend removing the hard deadline of July 1st.


Thank you for the opportunity to comment. AECI thanks the standard drafting team for their diligence and commitment to improve system reliability with an expedited timeline.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

- 0 - 0

We request the SDT confirm in a Consideration of Comments that only one of the three bullets under 3.5.2 is required for a given generating unit.

We recommend the SDT consider whether the proposed interaction between R2/R4/R6 and R7 will cause GOs needing to take the declaration in 7.1 an R2/R4/R6 noncompliance based on the Glossary of Terms definition of Corrective Action Plan. R7.1 allows an entity with an appropriate justification to declare that a CAP will not be implemented, but developing a CAP requires both developing a list of actions AND extablishing an associated timetable for implementation. As a timetable for implementation is not reasonable to require for corrective actions a GO is constrained from implementing, we recommend replacing “CAP” with “list of corrective actions” in R2/R4/R6 and changing R7 part 7.1 to “Create and Implement one or more Corrective Action Plans addressing each corrective action identified pursuant to Requirements R2, R4, or R6, or explain in a declaration why one or more identified corrective actions will not be implemented due to technical, commercial, or operational constraints as defined by the Generator Owner.”

Lindsey Mannion, On Behalf of: ReliabilityFirst , , Segments 10

- 0 - 0

We understand R1 and R2 as requiring GOs to implement freeze control measures that they reasonably believe, based on good engineering judgment and their experience with their particular units and weather patterns, will result in the unit being able to operate continuously for the applicable time at the Extreme Cold Weather Temperature.  Our understanding of the proposed requirements is that if a new or existing unit experiences a Forced Outage as a result of a Generator Cold Weather Reliability Event, even if the Forced Outage occurs after less than twelve hours (for a new generator) or one hour (for an existing generator) of continuous operations, the Forced Outage will not constitute evidence of noncompliance with R1 or R2.  Instead, the GO will develop and implement a CAP pursuant to R6 and R7, as it would in response to any Generator Cold Weather Reliability Event.  The contrary interpretation—that R1 and R2 require freeze protection measures that are 100% guaranteed to work—would require a level of certainty that simply does not exist.  Generators are complex machines; they sometimes fail in unforeseen ways.  This problem is only compounded by the fact that, as noted by multiple panelists at the April 27-28, 2022 FERC, NERC, and Regional Entities Technical Conference on Improving Winter-Readiness of Generating Units, a cold weather event cannot be simulated ahead of time to allow functional testing of a unit’s set of winterization measures.  Finding a GO noncompliant with R1 or R2 based on the failure in a particular instance of winterization measures it reasonably believed, based on the information available to it prior to the cold weather event, would be adequate, would not enhance reliability. 

We read R2 as providing that, where an existing unit is not capable of operating continuously for one hour at the Extreme Cold Weather Temperature, the method by which the GO “ensure[s] its generating unit(s) add new or modify existing freeze protection measures as needed” is the development of a CAP pursuant to R2.  In other words, a GO demonstrates compliance with R2 by demonstrating either that it has implemented appropriate freeze protection measures, or that it has developed a CAP[A1] . 

 

Suggested edit to Requirement R2 (making the 2 sentences in the Requirement ‘or’ statements):

R2.         For each generating unit(s) in commercial operation prior to [Effective Date of this requirement], the Generator Owner shall ensure its generating unit(s):

·                Add new or modify existing freeze protection measures as needed to provide the capability to operate for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature; or

·                If generating unit(s) are not capable of operating for one (1) hour at its Extreme Cold Weather Temperature, shall develop a Corrective Action Plan (CAP) for the identified issues, including identification of any needed modifications to the cold weather preparedness plan required under Requirement R3.

Suggested edit to Measure M2 (add the clause “ability to operate for 1 hour at”):

M2.      Each Generator Owner will have dated evidence that demonstrates it has freeze protection measures for its unit(s) in accordance with R2, or it has developed a CAP for the identified issues. Acceptable evidence may include the following (electronic or hardcopy format): Identification of generating units ability to operate for 1 hour at the minimum temperature per Part 3.5.2 which is equal to or less than the unit’s Extreme Cold Weather Temperature, documentation of freeze protection measures, cold weather preparedness plan, and CAP(s).

 

Brian Evans-Mongeon, Utility Services, Inc., 4, 8/30/2022

- 1 - 0

Israel Perez, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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OMPA agrees with the TAPs comments below:

We understand R1 and R2 as requiring GOs to implement freeze control measures that they reasonably believe, based on good engineering judgment and their experience with their particular units and weather patterns, will result in the unit being able to operate continuously for the applicable time at the Extreme Cold Weather Temperature.  Our understanding of the proposed requirements is that if a new or existing unit experiences a Forced Outage as a result of a Generator Cold Weather Reliability Event, even if the Forced Outage occurs after less than twelve hours (for a new generator) or one hour (for an existing generator) of continuous operations, the Forced Outage will not constitute evidence of noncompliance with R1 or R2.  Instead, the GO will develop and implement a CAP pursuant to R6 and R7, as it would in response to any Generator Cold Weather Reliability Event.  The contrary interpretation—that R1 and R2 require freeze protection measures that are 100% guaranteed to work—would require a level of certainty that simply does not exist.  Generators are complex machines; they sometimes fail in unforeseen ways.  This problem is only compounded by the fact that, as noted by multiple panelists at the April 27-28, 2022 FERC, NERC, and Regional Entities Technical Conference on Improving Winter-Readiness of Generating Units, a cold weather event cannot be simulated ahead of time to allow functional testing of a unit’s set of winterization measures.  Finding a GO noncompliant with R1 or R2 based on the failure in a particular instance of winterization measures it reasonably believed, based on the information available to it prior to the cold weather event, would be adequate, would not enhance reliability. 

We read R2 as providing that, where an existing unit is not capable of operating continuously for one hour at the Extreme Cold Weather Temperature, the method by which the GO “ensure[s] its generating unit(s) add new or modify existing freeze protection measures as needed” is the development of a CAP pursuant to R2.  In other words, a GO demonstrates compliance with R2 by demonstrating either that it has implemented appropriate freeze protection measures, or that it has developed a CAP. 

The SDT has indicated that it plans to revisit the language of EOP-012-1 as part of Phase 2 of this project.  Although we believe that our readings of the requirements, as outlined above, are consistent with the SDT’s intent, we strongly recommend that Phase 2 clarify the language of R1 and R2 on these issues.  Expressing the SDT’s intent more clearly would reduce the risk of confusion and conflicting interpretations.

 

Michael Watt, Oklahoma Municipal Power Authority, 4, 8/30/2022

- 1 - 0

Avista recommends some reconsideration as to the applicability of the EOP 12-2 as it relates to ALL BES generating facilities. Both the letter and intent of the draft standard appear to be related specifically to thermal or steam process plants that use a Rankin cycle to generate electricity, and their susceptibility for freezing during cold weather. Can the permit team under Part 2 reconsider the applicability of facilities to consider to just those facilities related to the Rankin cycle that use steam as a means of generating electricity. Many facilities such as hydroelectric facilities internal combustion generation, wind turbine generators, and are much less susceptible to extreme cold weather and should not be treated the same regarding compliance requirements of such a standard.

Glen Farmer, Avista - Avista Corporation, 5, 8/30/2022

- 0 - 0

Portland General Electric Company supports the survey response provided by EEI.

Portland General Electric Co., Segment(s) 1, 6, 5, 3, 8/30/2022

- 0 - 0

We understand R1 and R2 as requiring GOs to implement freeze control measures that they reasonably believe, based on good engineering judgment and their experience with their particular units and weather patterns, will result in the unit being able to operate continuously for the applicable time at the Extreme Cold Weather Temperature.  Our understanding of the proposed requirements is that if a new or existing unit experiences a Forced Outage as a result of a Generator Cold Weather Reliability Event, even if the Forced Outage occurs after less than twelve hours (for a new generator) or one hour (for an existing generator) of continuous operations, the Forced Outage will not constitute evidence of noncompliance with R1 or R2.  Instead, the GO will develop and implement a CAP pursuant to R6 and R7, as it would in response to any Generator Cold Weather Reliability Event.  The contrary interpretation—that R1 and R2 require freeze protection measures that are 100% guaranteed to work—would require a level of certainty that simply does not exist.  Generators are complex machines; they sometimes fail in unforeseen ways.  This problem is only compounded by the fact that, as noted by multiple panelists at the April 27-28, 2022 FERC, NERC, and Regional Entities Technical Conference on Improving Winter-Readiness of Generating Units, a cold weather event cannot be simulated ahead of time to allow functional testing of a unit’s set of winterization measures.  Finding a GO noncompliant with R1 or R2 based on the failure in a particular instance of winterization measures it reasonably believed, based on the information available to it prior to the cold weather event, would be adequate, would not enhance reliability. 

We read R2 as providing that, where an existing unit is not capable of operating continuously for one hour at the Extreme Cold Weather Temperature, the method by which the GO “ensure[s] its generating unit(s) add new or modify existing freeze protection measures as needed” is the development of a CAP pursuant to R2.  In other words, a GO demonstrates compliance with R2 by demonstrating either that it has implemented appropriate freeze protection measures, or that it has developed a CAP. 

The SDT has indicated that it plans to revisit the language of EOP-012-1 as part of Phase 2 of this project.  Although we believe that our readings of the requirements, as outlined above, are consistent with the SDT’s intent, we strongly recommend that Phase 2 clarify the language of R1 and R2 on these issues.  Expressing the SDT’s intent more clearly would reduce the risk of confusion and conflicting interpretations.

Devon Tremont, Taunton Municipal Lighting Plant, 1, 8/30/2022

- 0 - 0

Glenn Pressler, CPS Energy, 3, 8/30/2022

- 0 - 0

Avista recommends some reconsideration as to the applicability of the EOP 12-2 as it relates to ALL BES generating facilities. Both the letter and intent of the draft standard appear to be related specifically to thermal or steam process plants that use a Rankin cycle to generate electricity, and their susceptibility for freezing during cold weather. Can the permit team under Part 2 reconsider the applicability of facilities to consider to just those facilities related to the Rankin cycle that use steam as a means of generating electricity. Many facilities such as hydroelectric facilities internal combustion generation, wind turbine generators, and are much less susceptible to extreme cold weather and should not be treated the same regarding compliance requirements of such a standard. 

Scott Kinney, Avista - Avista Corporation, 3, 8/30/2022

- 0 - 0

The SDT states that “cost recovery” is outside the scope of its work, yet wades into economic regulation by i) applying different standards to new and existing generators and ii) offering a “commercial constraint” exemption.  In the former instance, the only justification the SDT offered is that a more stringent standard could create premature retirements.  This is despite the plain language requirement of the statute that all prudent and necessary costs to comply with the reliability standards shall be recoverable.  If generator owners are held harmless from the cost of compliance, then why would a rigorous standard drive retirements?  In the latter case, the commercial constraint would violate NERC Market Principles.  As an illustrative example, if two generators, A and B, were participating in the same market, owner of Generator A declared its intention to retire “soon” and declared a “commercial constraint” exemption from compliance.  Generator A is not saddled with the compliance costs because of its “constraint,” while Generator B has compliance costs; yet both generators compete in the same market in the same interval.  We cannot think of a clearer example of a reliability standard creating an unfair competitive advantage.

 

Additionally, the SDT’s attempt at economic regulation is producing a diluted reliability standard that could actually reduce reliability.  Our analysis demonstrates that all locations that experience freezing temperatures experienced multiple events that lasted more than one hour at or below their respective ECWT.  As we describe above, we are concerned that fleet performance will regress towards the new 1-hour standard, even for existing generators that may have had historically good performance.  This would reduce reliability.  Additionally, setting a 12-hour duration for new resources would take decades to have any meaningful reliability impact as new generators replace existing.  For these reasons, we urge the SDT to set a common standard for existing and new that will meaningfully enhance reliability.

 

We also urge the SDT to eliminate the “commercial constraint” exemption.  We are not aware of a similar provision in any other approved NERC reliability standard, and this provision may create unwanted debate regarding other reliability standards.  First, it leaves it to the generator owner’s discretion to determine whether it is exempt from compliance, which favors states and merchant generators to rely on the most liberal interpretation of the exemption that achieves the lowest cost.  This is extremely bad precedent.  Second, the vaguely defined exemption will create inevitable disagreements between generator owners and auditors that may only be raised at the time of the audit.  Third, it raises the question that if a retirement decision is a valid exemption then why should a generator that is “due to retire soon” be required to comply with any NERC reliability standard?  This is bad precedent.  Finally, a generator owner could make an argument that if its tariff does not allow cost recovery that too is a commercial constraint and merits an exemption.  Unlike the regulated markets, this is particularly worrisome for the organized markets where cost recovery is not guaranteed before an investment is made.

 

We are also concerned NERC may not have the authority under the Federal Power Act to impose the proposed standard.  NERC cites the definition of “reliability standard” as its authority to impose requirements on existing generators.  The definition from the statute is replicated below:

 

 “The term ‘reliability standard’ means a requirement, approved by the Commission under this section, to provide for reliable operation of the bulk-power system. The term includes requirements for the operation of existing bulk-power system facilities, including cybersecurity protection, and the design of planned additions or modifications to such facilities to the extent necessary to provide for reliable operation of the bulk-power system, but the term does not include any requirement to enlarge such facilities or to construct new transmission capacity or generation capacity.”

 

However, the statute also defines the term “reliable operations”:

 

“The term ‘reliable operation’ means operating the elements of the bulk-power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of system elements.”

 

The term ‘reliable operations’ is expressly limited to items that cause “sudden disturbances, including a cybersecurity incident” or an “unanticipated failure of system elements.”  “[U]nanticipated failure” is not a failure of a generator at a temperature below its cold weather rating.  Thus, it appears that mandating expanded performance obligations directly on existing generators through a reliability standard is outside the scope of this definition.  Additionally, we are not aware of any approved reliability standard mandating generators install components for an expanded range of services.

 

            For these reasons, we encourage NERC to reconsider its approach.  We offer an alternative approach that would require the BAs to procure this expanded service and harmonize it with attributes in addition to freeze protection – e.g., fuel, environmental limitations, etc.  Relying on BAs to procure their reliability needs is a more defensible and economically efficient approach to enhancing reliability.  It is also an approach that eliminates the need for a “commercial constraint” exemption and permits for a more robust reliability standard.  However, if NERC does not consider this alternate, we recommend that the Commission hold the compliance date in abeyance until cost recovery has been properly addressed.  As background, in the ISO New England CIP IROL proceeding certain generators were designated IROL facilities, were promised that they would have an opportunity to recover their costs, and incurred substantial compliance costs.  Unfortunately, the ISO’s filing was after many generators incurred the costs and thus the Commission found that recovery of costs prior to the filing would violate the filed rate doctrine, and rejected recovery of those pre-filing costs.

Mark Spencer, LS Power Development, LLC, 5, 8/30/2022

- 1 - 0

Ameren agrees with the EEI and the NAGF comments.

David Jendras, Ameren - Ameren Services, 3, 8/31/2022

- 0 - 0

Xcel Energy supports comments from EEI.  

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

OG&E supports the comments submitted by EEI.

OGE Energy, Segment(s) 3, 1, 5, 6, 8/31/2022

- 0 - 0

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/31/2022

- 0 - 0

PG&E thanks the SDT’s for their effort to address the industry's concerns regarding the proposed Standard, the effort it has taken to complete the work up to this point, and the work necessary to complete the modifications in Phase Two of the project.

 

PG&E also supports the additional input provided by EEI related to Requirement R2, and the NAGF concerns related to retrofitting and compensation on those retrofits.  This includes the NAGF input  that the Requirements in EOP-011 which is enforceable on 4/1/2023 should be allowed to take effect and determine if they are sufficient to address cold weather operations.  PG&E also supports the NAGF proposed language if NERC wishes to add in the reliability requirements language.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

- 0 - 0

AEP recognizes the importance of this project, and the priority which it has been given. Having said that, AEP hopes that industry’s outstanding concerns (those not currently met in the current draft) will be fully addressed in a Phase II of this project. In addition, we recommend that industry be allowed the customary time period to develop comments and cast ballots at that time.

Thomas Foltz, AEP, 5, 8/31/2022

- 0 - 0

As stated above, Dominion Energy remains concerned with the requirement to retrofit or otherwise improve an existing generator’s cold weather performance capability and proposes the drafting team consider the more cost-effective option of requiring generators to communicate their extreme cold weather operating capabilities to the BA and RC. Communicating operating capabilities and failing to meet them during an event would result in the CAP as outlined in R6. This option allows the BA and RC to appropriately plan for extreme cold weather events without placing a potentially unnecessary burden to retrofit existing generators and require them to perform beyond established designed operating parameters.

Dominion Energy is of the opinion that ensuring operating parameters for extreme cold weather are communicated and understood by the appropriate entities is more beneficial to reliability during these events than a blanket retrofit requirement.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

LouisvilleG&E/KU support EEI's comments. 

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

- 0 - 0

No additional comments.

Lenise Kimes, On Behalf of: City and County of San Francisco - WECC - Segments 1, 5

- 0 - 0

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 8/11/2022

- 0 - 0

Southern Company would suggest the SDT include additional language in R1 to strengthen expectations that a generator that is committed or contractually obligated to serve a BA load per Appicablility section 4.2.1 will design and plan to operate under the conditions described in R1.  The “Or” clause in R1, currently in this version, leaves too much latitude for generators not to perform prior to actually experiencing a Generator Cold Weather Reliability Event.

Southern Company suggests the following language to be added to R1:

  • “If the generating unit(s) are contractually obligated to operate in the aforementioned conditions, and any technical, commercial, or operational constraint is identified by the Generator Owner, the Generator Owner shall notify their applicable Generator Operator, Transmission Operator, Balancing Authority and Reliability Coordinator in a timely manner. The Generator Owner shall specify the anticipated time required for mitigation and identify an approximate return to service date.”

 

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

One of the most important aspects of this Phase 1 EOP-12 and existing EOP-11-2 is the communication of limiting temperatures to the BA/TOP via IRO-010 and TOP-003. Although how the BA/TOP will use the temperature information is outside the scope of these efforts, BA/TOP knowledge of limiting operating temperature and Extreme Cold Weather Temperature (ECWT), and the expected dialogue between GO/GOPs and BA/TOPs, is expected to result in more robust, realistic cold weather resource planning. ..... Two editorial comments on the Technical Rationale doc: 1) The last two bullet points supporting R6 in the Technical Rationale document should be reworded, perhaps with examples. That is, the current bullet point language that the use of the ECWT instead of minimum operating temperature removes incentives and disincentives is confusing, and the two appear to be addressing the same issue, just coming from different perspectives. 2) Also in the same section is the capitalization of Generator Unit Minimum Temperature. Recommend a check be made to ensure this is an official definition. 

 

Kimberly Turco, on behalf of Segments 5 and 6

Kimberly Turco, Constellation, 6, 8/31/2022

- 0 - 0

One of the most important aspects of this Phase 1 EOP-12 and existing EOP-11-2 is the communication of limiting temperatures to the BA/TOP via IRO-010 and TOP-003. Although how the BA/TOP will use the temperature information is outside the scope of these efforts, BA/TOP knowledge of limiting operating temperature and Extreme Cold Weather Temperature (ECWT), and the expected dialogue between GO/GOPs and BA/TOPs, is expected to result in more robust, realistic cold weather resource planning. ..... Two editorial comments on the Technical Rationale doc: 1) The last two bullet points supporting R6 in the Technical Rationale document should be reworded, perhaps with examples. That is, the current bullet point language that the use of the ECWT instead of minimum operating temperature removes incentives and disincentives is confusing, and the two appear to be addressing the same issue, just coming from different perspectives. 2) Also in the same section is the capitalization of Generator Unit Minimum Temperature. Recommend a check be made to ensure this is an official definition

 

Kimberly Turco, on behalf of Segments 5 and 6

Alison Mackellar, Constellation, 5, 8/31/2022

- 0 - 0

Reclamation is providing the language it proposed for EOP-012 in Draft 1 here for convenience:

Reclamation recommends rewriting the requirements of EOP-012-1 as follows:

R1. *use existing language from Draft 1 EOP-012-1 R1.1* with the following corrections:

Each Generator Owner shall design new and maintain existing generating units to be capable of continuous operations at the documented minimum hourly temperature experienced at each unit’s location since 1/1/1975 or a lesser period if reliable data is not available to 1975.

R2. *use existing language from Draft 1 EOP-012-1 R1* with the following corrections:

Each Generator Owner shall implement new or modify existing protection based on the documented minimum hourly temperature for its generating units including the following minimum criteria:

R2.1. the cooling effect of wind; and

R2.2. impacts on equipment operation due to precipitation (e.g., sleet, snow, ice, and freezing rain).

R3. *use existing language from Draft 1 EOP-012-1 R1.4* with the following corrections:

For each existing generating unit that requires new or modified protection based on the documented minimum hourly temperature, the Generator Owner shall develop and implement a Corrective Action Plan (CAP) or, where deemed appropriate by the Generator Owner based on the review of parts R3.1.1 through R3.1.3., declare that no corrective actions will be taken.

R3.1. A CAP shall contain the following minimum information:

R3.1.1. Corrective action(s) for the affected unit(s).

R3.1.2. Any temporary operating limitations that would apply until the corrective actions are implemented.

R3.1.3. A schedule for implementing the corrective action(s).

R3.2. A declaration shall document any technical, commercial, or operational constraints of each affected unit, as defined by the Generator Owner, in support of the declaration.

R4. *use existing language from Draft 1 EOP-012-1 R2* with the following corrections:

Each Generator Owner that does not implement new or modify existing protection based on the documented minimum hourly temperature in accordance with R2 due to technical, commercial, or operational constraints, as defined by the Generator Owner, shall:

R4.1. Document its determination and the constraints; and

R4.2. Review its determination every five calendar years to determine whether the constraints remain applicable.

R5. *use existing language from Draft 1 EOP-012-1 R3*

R6. *use existing language from Draft 1 EOP-012-1 R4, update Part numbers as necessary*

R7. *use existing language from Draft 1 EOP-012-1 R5* with the following corrections:

Each Generator Owner, in conjunction with its Generator Operator, shall ensure generating unit-specific cold weather preparedness plan training is provided to its personnel responsible for implementing cold weather preparedness plans.

R7.1. The Generator Owner and Generator Operator shall identify the entity responsible for providing the training.

R7.2. The Generator Owner and Generator Operator shall ensure the training is provided to personnel responsible for implementing cold weather preparedness plans upon entrance on duty and annually thereafter.

R8. *use existing language from Draft 1 EOP-012-1 R6* with the following corrections:

Each Generator Owner that owns a generating unit that experiences an event resulting in a derate of more than 10% of the total capacity of the unit for longer than four hours in duration, a start-up failure where the unit fails to synchronize within a specified start-up time, or a Forced Outage for which (i) the apparent cause(s) of the event is due to extreme cold weather effects within the Generator Owner’s control to protect against, and (ii) the ambient conditions at the site at the time of the event are at or above the temperature documented in Part 3.4.2 shall:

R8.1. No later than 150 days subsequent to the event or by July 1 that follows the event, whichever is later, develop a CAP; or

R8.2. Declare, where deemed appropriate by the Generator Owner based on review of Parts 8.3.1. through 8.3.5, that no revisions to the cold weather preparedness plan are required and that no further corrective actions will be taken.

R8.3. At a minimum, a CAP shall contain:

R8.3.1. A summary of the identified cause(s) of the equipment derate, failure to start, or Forced Outage, and any relevant associated data.

8.3.2 use existing 6.2.1. language

8.3.3. use existing 6.2.2. language

8.3.4. (modified 6.2.3.) Specific corrective action(s) for the affected unit(s) and identified similar units, including:

8.3.4.1. (modified 6.2.3.) any necessary modifications to the Generator Owner’s cold weather preparedness plan(s); and

8.3.4.2. (modified 6.2.4.) consideration of any technical, commercial, or operational constraints, as defined by the Generator Owner.

8.3.5. A schedule for implementing the corrective actions.

R8.4. At a minimum, a declaration shall document technical, commercial, or operational constraints, as defined by the Generator Owner, as support for the declaration.

Reclamation recommends the timeframe for developing a CAP be 150 days subsequent to the event or by July 1 that follows the event, whichever is later. Using whichever is earlier could subject an entity to an unreasonably short deadline depending on when the event occurs.

Reclamation recommends moving the language pertaining to the cold weather preparedness plans from the original R1 to the original R3 (new R5 based on Reclamation’s proposed renumbering in the above comments). Modifications to the cold weather preparedness plan should relate back to the CAP, if necessary, not the CAP requirements relating forward to the cold weather preparedness plan.

Reclamation recommends not limiting the training on cold weather preparedness plans to “maintenance or operations” personnel, as other personnel may also be responsible for implementing cold weather preparedness plans and should not be excluded from the training. Reclamation recommends the annual cold weather preparedness plan training be contained in PER-006 instead of EOP-012.

Reclamation supports the retention and reuse of pertinent information from the Draft 1 Measures.

Richard Jackson, U.S. Bureau of Reclamation, 1, 8/31/2022

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NRG agrees with the NAGF that communicating operating parameters for extreme cold weather that are understood by the appropriate entities is more appropriate and beneficial to reliability during these events rather than a blanket retrofit requirement to operate to a defined condition.

 We realize NERC cannot address the compensation issue for required improvements, but unless there is agreement from and with parties that can provide compensation for upgrades, this standard becomes an unfunded mandate on Generator Owners.

Martin Sidor, NRG - NRG Energy, Inc., 6, 8/31/2022

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Please see comments submitted by the Edison Electric Institute

Romel Aquino, Edison International - Southern California Edison Company, 3, 8/31/2022

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NRG agrees with the NAGF that communicating operating parameters for extreme cold weather that are understood by the appropriate entities is more appropriate and beneficial to reliability during these events than a blanket retrofit requirement to operate to a defined condition.

 

We realize NERC cannot address the compensation issue for required improvements, but unless there is agreement from and with parties that can provide compensation for upgrades, this standard becomes an unfunded mandate on Generator Owners.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 8/31/2022

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“Please see comments submitted by the Edison Electric Institute”

Selene Willis, Edison International - Southern California Edison Company, 5, 8/31/2022

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Claudine Bates, Black Hills Corporation, 6, 8/31/2022

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Josh Combs, Black Hills Corporation, 3, 8/31/2022

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Micah Runner, Black Hills Corporation, 1, 8/31/2022

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Sheila Suurmeier, On Behalf of: Black Hills Corporation, , Segments 1, 3, 5, 6

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Tony Skourtas, Los Angeles Department of Water and Power, 3, 8/31/2022

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PNM supports EEI’s comments regarding modification of Requirement R2 to link with Requirement R7.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3

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The IESO reiterates its comment for Draft 1, where it requested that removal of the ‘commercial’ reference in Requirements 1 and 7.1 as this language is vague, creates an ambiguity as to the obligation otherwise provided for in the standard, and a review of commercial issues is not within NERC’s domain and expertise.

In the Reliability Standard CIP-014 – Physical Security, NERC recognized that it does not have the physical security expertise to appropriately evaluate the risk assessment performed by the Transmission Owner.  As such, CIP-014 requires an unaffiliated third party with the appropriate expertise to verify it. 

Given that NERC’s purview is reliability of the bulk power system, and not commercial matters, the SRC proposes that NERC adopt a similar approach for the proposed standard.  Should a  Generator Owner opt out of a Corrective Action Plan for commercial constraints, an unaffiliated third party should verify the finanacial assessment performed by the Generator Owner. The third party should have financial analysis experience, such as an auditing/accounting firm. 

We also suggest that NERC develop clear boundaries regarding the use of commercial constraints to opt out of a CAP, such as: 

  • the investment in freezing protection measures is cost prohibitive due to new technology not yet advanced (i.e., economies of scale to yet reached) or
  • the investment is below the registered entity’s rate of return. 

 We recognize that cost recovery for generators is also not within the purview of NERC.  Cost recovery for generators usually falls within state/provincial purview, and through market mechanisms.  The SRC proposes that NERC consider adding a stakeholder process in the proposed requirement, similar to that in Reliability Standard TPL-001 – Transmission Planning on use of planned consequential load loss.  An open stakeholder process that ensures state/provincial agencies  are aware of the need for freeze protection measures to meet the reliability requirements in the proposed standard will allow affected parties to assess the cost recovery issues.

 

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2022

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James Baldwin, Lower Colorado River Authority, 1, 9/1/2022

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Vistra has additional recommendations/requested clarifications on the proposed requirements described below:

 

The NERC Calculating Extreme Cold Weather Temperature guide should be modified to address circumstances where National Oceanic and Atmospheric Administration (NOAA) data dating back to January 1, 2000 does not exist for the particular location. For example, NOAA has weather data for Andrews, Texas dating back only to 2014, and there are no other representative NOAA locations in the dataset. There may be other instances of rural airports or other NOAA weather data locations that do not have data going back to 2000. The Guide should specify an alternate source(s) of acceptable weather data for calculation of the Extreme Cold Weather Temperature in instances where NOAA data does not exist back to 2000, as well as how to select the location for the substitute temperature data, how to input that substitute data into the NOAA dataset, and how to treat missing temperature data (blanks) when the NOAA report is run.

 

Proposed R3.1 requires that a Generator Owner include in its cold weather preparedness plan the “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data.” If the Technical Requirements document titled “Calculating Extreme Cold Weather Temperature” is intended to provide the source of temperature data for all Generator Owners, then this language should be modified to state “Extreme Cold Weather Temperature for their unit(s) including the calculation date using NERC’s guide for Calculating Extreme Cold Weather Temperature.” Otherwise, the standard should be modified to clarify what sources of data are permissible, including data provided by the balancing authority (as noted in response to Question 2).

 

Proposed R3.5.1.2 requires Generator Owners to include within their cold weather preparedness plans “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns.” This language should be revised to clarify that the Generator Owner is only responsible for fuel supply and inventory within its control and knowledge, as Generator Owners do not always own the source or transportation for their fuel supply and thus cannot always identify or anticipate fuel supply and inventory concerns. For example, the requirement could be modified to read: “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns, to the extent known to the Generator Owner.”

 

Proposed R4 should clarify that a redesign of the unit(s) will not be required every five years. The standard requires that a Generator Owner calculate a new Extreme Cold Weather Temperature and update its cold weather preparedness plan and freeze protection measures as needed, or else, develop a Corrective Action Plan (CAP). As drafted, the standard could be interpreted as potentially requiring a redesign or retrofitting of a unit every 5 years. Vistra recommends that, in conjunction with adding a definition of “freeze protection measures” that includes procedures and temporary equipment among those measures (as recommended under Question 5), R4.3 could be modified to add the following sentence at the end: “If a CAP is required under this Requirement R4, the CAP cannot require a Generator Owner to redesign or retrofit its unit to meet the requirements in R1 or R2, as applicable, at the updated Extreme Cold Weather Temperature for the unit(s).”

 

Proposed R5 should clarify that the required training will be site-specific, rather than unit-specific: “Each Generator Owner in conjunction with its Generator Operator shall identify the entity responsible for providing the generating unit-site specific training, and that identified entity shall provide annual training at each site to its maintenance or operations personnel responsible for implementing the cold weather preparedness plan(s) at that site developed pursuant to Requirement R3.”

 

Proposed R6 should require a CAP to be developed within 150 days, rather than the earlier of 150 days or July 1. If a Generator Cold Weather Reliability Event occurs at the end of the winter season (or during a freak winter-like storm in March or April), a Generator Owner could have significantly fewer than 150 days to develop a CAP if the standard is based on the earlier of July 1 or 150 days. At the same time, even if an event occurred as late as early April, the 150 day standard would still require that the CAP be developed in advance of the next winter season (e.g., 150 days, or roughly 5 months, after April would still be in September). Thus, R6 should strike the alternative reference to July 1.

Dan Roethemeyer, Vistra Energy, 5, 9/1/2022

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) for question #9.

Alan Kloster, On Behalf of: Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Kevin Frick, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

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Exelon concurs with EEI's comment to Question 9

 

Submitted on behalf of Exelon, Segments 1 & 3

Daniel Gacek, Exelon, 1, 9/1/2022

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Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Nothing additional to add at this time.

Teresa Krabe, Lower Colorado River Authority, 5, 9/1/2022

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For R5: In regards to the proposed verbiage requiring "generating unit-specific training", it is OPC's opinion that this could be overly repetitious for stations that have multiple units, which are considered sister units and hence would have the same generator protection measures in place. We recomenend modifying this requirement to require station-specitic training in lieu of generating unit-specific training. In cased where there are different freeze protection measures for unit(s), those measures would be defined within the training anyway since it covers freeze protection for all units at a station.

Donna Johnson, Oglethorpe Power Corporation, 5, 9/1/2022

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For R5: In regards to the proposed verbiage requiring “generating unit-specific training”, it is OPC’s opinion that this could be overly repetitious for stations that have multiple units, which are considered sister units and hence would have the same generator protection measures in place.  We recommend modifying this requirement to require station-specific training in lieu of generating unit-specifc training.  In cases where there are different freeze protection measures for unit(s), those measures would be defined within the training anyway since it covers freeze protection for all units at a station.

Scott McGough, Georgia System Operations Corporation, 3, 9/1/2022

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Vistra has additional recommendations/requested clarifications on the proposed requirements described below:

The NERC Calculating Extreme Cold Weather Temperature guide should be modified to address circumstances where National Oceanic and Atmospheric Administration (NOAA) data dating back to January 1, 2000 does not exist for the particular location. For example, NOAA has weather data for Andrews, Texas dating back only to 2014, and there are no other representative NOAA locations in the dataset. There may be other instances of rural airports or other NOAA weather data locations that do not have data going back to 2000. The Guide should specify an alternate source(s) of acceptable weather data for calculation of the Extreme Cold Weather Temperature in instances where NOAA data does not exist back to 2000, as well as how to select the location for the substitute temperature data, how to input that substitute data into the NOAA dataset, and how to treat missing temperature data (blanks) when the NOAA report is run.

Proposed R3.1 requires that a Generator Owner include in its cold weather preparedness plan the “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data.” If the Technical Requirements document titled “Calculating Extreme Cold Weather Temperature” is intended to provide the source of temperature data for all Generator Owners, then this language should be modified to state “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data, using NERC’s guide for Calculating Extreme Cold Weather Temperature.” Otherwise, the standard should be modified to clarify what sources of data are permissible, including data provided by the balancing authority (as noted in response to Question 2).

 

Proposed R3.5.1.2 requires Generator Owners to include within their cold weather preparedness plans “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns.” This language should be revised to clarify that the Generator Owner is only responsible for fuel supply and inventory within its control and knowledge, as Generator Owners do not always own the source or transportation for their fuel supply and thus cannot always identify or anticipate fuel supply and inventory concerns. For example, the requirement could be modified to read: “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns, to the extent known to the Generator Owner.”

 

Proposed R4 should clarify that a redesign of the unit(s) will not be required every five years. The standard requires that a Generator Owner calculate a new Extreme Cold Weather Temperature and update its cold weather preparedness plan and freeze protection measures as needed, or else, develop a Corrective Action Plan (CAP). As drafted, the standard could be interpreted as potentially requiring a redesign or retrofitting of a unit every 5 years. Vistra recommends that, in conjunction with adding a definition of “freeze protection measures” that includes procedures and temporary equipment among those measures (as recommended under Question 5), R4.3 could be modified to add the following sentence at the end: “If a CAP is required under this Requirement R4, the CAP cannot require a Generator Owner to redesign or retrofit its unit to meet the requirements in R1 or R2, as applicable, at the updated Extreme Cold Weather Temperature for the unit(s).”

 

Proposed R5 should clarify that the required training will be site-specific, rather than unit-specific: “Each Generator Owner in conjunction with its Generator Operator shall identify the entity responsible for providing the generating unit-site specific training, and that identified entity shall provide annual training at each site to its maintenance or operations personnel responsible for implementing the cold weather preparedness plan(s) at that site developed pursuant to Requirement R3.”

 

Proposed R6 should require a CAP to be developed within 150 days, rather than the earlier of 150 days or July 1. If a Generator Cold Weather Reliability Event occurs at the end of the winter season (or during a freak winter-like storm in March or April), a Generator Owner could have significantly fewer than 150 days to develop a CAP if the standard is based on the earlier of July 1 or 150 days. At the same time, even if an event occurred as late as early April, the 150 day standard would still require that the CAP be developed in advance of the next winter season (e.g., 150 days, or roughly 5 months, after April would still be in September). Thus, R6 should strike the alternative reference to July 1.

 

 

Proposed R3.1 requires that a Generator Owner include in its cold weather preparedness plan the “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data.” If the Technical Requirements document titled “Calculating Extreme Cold Weather Temperature” is intended to provide the source of temperature data for all Generator Owners, then this language should be modified to state “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data, using NERC’s guide for Calculating Extreme Cold Weather Temperature.” Otherwise, the standard should be modified to clarify what sources of data are permissible, including data provided by the balancing authority (as noted in response to Question 2).

 

Proposed R3.5.1.2 requires Generator Owners to include within their cold weather preparedness plans “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns.” This language should be revised to clarify that the Generator Owner is only responsible for fuel supply and inventory within its control and knowledge, as Generator Owners do not always own the source or transportation for their fuel supply and thus cannot always identify or anticipate fuel supply and inventory concerns. For example, the requirement could be modified to read: “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns, to the extent known to the Generator Owner.”

 

Proposed R4 should clarify that a redesign of the unit(s) will not be required every five years. The standard requires that a Generator Owner calculate a new Extreme Cold Weather Temperature and update its cold weather preparedness plan and freeze protection measures as needed, or else, develop a Corrective Action Plan (CAP). As drafted, the standard could be interpreted as potentially requiring a redesign or retrofitting of a unit every 5 years. Vistra recommends that, in conjunction with adding a definition of “freeze protection measures” that includes procedures and temporary equipment among those measures (as recommended under Question 5), R4.3 could be modified to add the following sentence at the end: “If a CAP is required under this Requirement R4, the CAP cannot require a Generator Owner to redesign or retrofit its unit to meet the requirements in R1 or R2, as applicable, at the updated Extreme Cold Weather Temperature for the unit(s).”

 

Proposed R5 should clarify that the required training will be site-specific, rather than unit-specific: “Each Generator Owner in conjunction with its Generator Operator shall identify the entity responsible for providing the generating unit-site specific training, and that identified entity shall provide annual training at each site to its maintenance or operations personnel responsible for implementing the cold weather preparedness plan(s) at that site developed pursuant to Requirement R3.”

 

Proposed R6 should require a CAP to be developed within 150 days, rather than the earlier of 150 days or July 1. If a Generator Cold Weather Reliability Event occurs at the end of the winter season (or during a freak winter-like storm in March or April), a Generator Owner could have significantly fewer than 150 days to develop a CAP if the standard is based on the earlier of July 1 or 150 days. At the same time, even if an event occurred as late as early April, the 150 day standard would still require that the CAP be developed in advance of the next winter season (e.g., 150 days, or roughly 5 months, after April would still be in September). Thus, R6 should strike the alternative reference to July 1.

Proposed R3.1 requires that a Generator Owner include in its cold weather preparedness plan the “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data.” If the Technical Requirements document titled “Calculating Extreme Cold Weather Temperature” is intended to provide the source of temperature data for all Generator Owners, then this language should be modified to state “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data, using NERC’s guide for Calculating Extreme Cold Weather Temperature.” Otherwise, the standard should be modified to clarify what sources of data are permissible, including data provided by the balancing authority (as noted in response to Question 2).

 

Proposed R3.5.1.2 requires Generator Owners to include within their cold weather preparedness plans “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns.” This language should be revised to clarify that the Generator Owner is only responsible for fuel supply and inventory within its control and knowledge, as Generator Owners do not always own the source or transportation for their fuel supply and thus cannot always identify or anticipate fuel supply and inventory concerns. For example, the requirement could be modified to read: “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns, to the extent known to the Generator Owner.”

 

Proposed R4 should clarify that a redesign of the unit(s) will not be required every five years. The standard requires that a Generator Owner calculate a new Extreme Cold Weather Temperature and update its cold weather preparedness plan and freeze protection measures as needed, or else, develop a Corrective Action Plan (CAP). As drafted, the standard could be interpreted as potentially requiring a redesign or retrofitting of a unit every 5 years. Vistra recommends that, in conjunction with adding a definition of “freeze protection measures” that includes procedures and temporary equipment among those measures (as recommended under Question 5), R4.3 could be modified to add the following sentence at the end: “If a CAP is required under this Requirement R4, the CAP cannot require a Generator Owner to redesign or retrofit its unit to meet the requirements in R1 or R2, as applicable, at the updated Extreme Cold Weather Temperature for the unit(s).”

 

Proposed R5 should clarify that the required training will be site-specific, rather than unit-specific: “Each Generator Owner in conjunction with its Generator Operator shall identify the entity responsible for providing the generating unit-site specific training, and that identified entity shall provide annual training at each site to its maintenance or operations personnel responsible for implementing the cold weather preparedness plan(s) at that site developed pursuant to Requirement R3.”

 

Proposed R6 should require a CAP to be developed within 150 days, rather than the earlier of 150 days or July 1. If a Generator Cold Weather Reliability Event occurs at the end of the winter season (or during a freak winter-like storm in March or April), a Generator Owner could have significantly fewer than 150 days to develop a CAP if the standard is based on the earlier of July 1 or 150 days. At the same time, even if an event occurred as late as early April, the 150 day standard would still require that the CAP be developed in advance of the next winter season (e.g., 150 days, or roughly 5 months, after April would still be in September). Thus, R6 should strike the alternative reference to July 1.

Proposed R3.1 requires that a Generator Owner include in its cold weather preparedness plan the “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data.” If the Technical Requirements document titled “Calculating Extreme Cold Weather Temperature” is intended to provide the source of temperature data for all Generator Owners, then this language should be modified to state “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data, using NERC’s guide for Calculating Extreme Cold Weather Temperature.” Otherwise, the standard should be modified to clarify what sources of data are permissible, including data provided by the balancing authority (as noted in response to Question 2).

 

Proposed R3.5.1.2 requires Generator Owners to include within their cold weather preparedness plans “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns.” This language should be revised to clarify that the Generator Owner is only responsible for fuel supply and inventory within its control and knowledge, as Generator Owners do not always own the source or transportation for their fuel supply and thus cannot always identify or anticipate fuel supply and inventory concerns. For example, the requirement could be modified to read: “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns, to the extent known to the Generator Owner.”

 

Proposed R4 should clarify that a redesign of the unit(s) will not be required every five years. The standard requires that a Generator Owner calculate a new Extreme Cold Weather Temperature and update its cold weather preparedness plan and freeze protection measures as needed, or else, develop a Corrective Action Plan (CAP). As drafted, the standard could be interpreted as potentially requiring a redesign or retrofitting of a unit every 5 years. Vistra recommends that, in conjunction with adding a definition of “freeze protection measures” that includes procedures and temporary equipment among those measures (as recommended under Question 5), R4.3 could be modified to add the following sentence at the end: “If a CAP is required under this Requirement R4, the CAP cannot require a Generator Owner to redesign or retrofit its unit to meet the requirements in R1 or R2, as applicable, at the updated Extreme Cold Weather Temperature for the unit(s).”

 

Proposed R5 should clarify that the required training will be site-specific, rather than unit-specific: “Each Generator Owner in conjunction with its Generator Operator shall identify the entity responsible for providing the generating unit-site specific training, and that identified entity shall provide annual training at each site to its maintenance or operations personnel responsible for implementing the cold weather preparedness plan(s) at that site developed pursuant to Requirement R3.”

 

Proposed R6 should require a CAP to be developed within 150 days, rather than the earlier of 150 days or July 1. If a Generator Cold Weather Reliability Event occurs at the end of the winter season (or during a freak winter-like storm in March or April), a Generator Owner could have significantly fewer than 150 days to develop a CAP if the standard is based on the earlier of July 1 or 150 days. At the same time, even if an event occurred as late as early April, the 150 day standard would still require that the CAP be developed in advance of the next winter season (e.g., 150 days, or roughly 5 months, after April would still be in September). Thus, R6 should strike the alternative reference to July 1.

Proposed R3.1 requires that a Generator Owner include in its cold weather preparedness plan the “Extreme Cold Weather Temperature for their unit(s) including the calculation date and source of temperature data.” If the Technical Requirements document titled “Calculating Extreme Cold Weather Temperature” is intended to provide the source of temperature data for all Generator Owners, then this language should be modified to state “Extreme Cold Weather Temperature for their unit(s) including the calculation date, using NERC’s guide for Calculating Extreme Cold Weather Temperature.” Otherwise, the standard should be modified to clarify what sources of data are permissible, including data provided by the balancing authority (as noted in response to Question 2).

Proposed R3.5.1.2 requires Generator Owners to include within their cold weather preparedness plans “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns.” This language should be revised to clarify that the Generator Owner is only responsible for fuel supply and inventory within its control and knowledge, as Generator Owners do not always own the source or transportation for their fuel supply and thus cannot always identify or anticipate fuel supply and inventory concerns. For example, the requirement could be modified to read: “Generating unit(s) cold weather data, to include: … Fuel supply and inventory concerns, to the extent known to the Generator Owner.”

Proposed R4 should clarify that a redesign of the unit(s) will not be required every five years. The standard requires that a Generator Owner calculate a new Extreme Cold Weather Temperature and update its cold weather preparedness plan and freeze protection measures as needed, or else, develop a Corrective Action Plan (CAP). As drafted, the standard could be interpreted as potentially requiring a redesign or retrofitting of a unit every 5 years. Vistra recommends that, in conjunction with adding a definition of “freeze protection measures” that includes procedures and temporary equipment among those measures (as recommended under Question 5), R4.3 could be modified to add the following sentence at the end: “If a CAP is required under this Requirement R4, the CAP cannot require a Generator Owner to redesign or retrofit its unit to meet the requirements in R1 or R2, as applicable, at the updated Extreme Cold Weather Temperature for the unit(s).”

 

Proposed R5 should clarify that the required training will be site-specific, rather than unit-specific: “Each Generator Owner in conjunction with its Generator Operator shall identify the entity responsible for providing the generating unit-site specific training, and that identified entity shall provide annual training at each site to its maintenance or operations personnel responsible for implementing the cold weather preparedness plan(s) at that site developed pursuant to Requirement R3.”

Proposed R6 should require a CAP to be developed within 150 days, rather than the earlier of 150 days or July 1. If a Generator Cold Weather Reliability Event occurs at the end of the winter season (or during a freak winter-like storm in March or April), a Generator Owner could have significantly fewer than 150 days to develop a CAP if the standard is based on the earlier of July 1 or 150 days. At the same time, even if an event occurred as late as early April, the 150 day standard would still require that the CAP be developed in advance of the next winter season (e.g., 150 days, or roughly 5 months, after April would still be in September). Thus, R6 should strike the alternative reference to July 1. 

 

 

 

 

 

Stewart Rake, On Behalf of: Luminant Mining Company LLC, , Segments 7

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The industry already voted other requirements into standards, and now the SDT is expanding the requirements to a new standard which is unnecessary. These requirements are not an emergency operations standard as written. If such standards are needed, they constitute a facilities standard (as in Facilities Design, Connections, and Maintenance).

LeRoy Patterson, Public Utility District No. 2 of Grant County, Washington, 6, 9/1/2022

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AES Clean Energy agrees with the comments submitted by NAGF.

Ruchi Shah, On Behalf of: AES - AES Corporation, , Segments 5

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NAGF membership is concerned with the requirement to retrofit or otherwise improve an existing generator’s cold weather performance capability without NERC having the ability to address the compensation issue identified in the Joint Inquiry Report under Key Recommendation 2. There is also concern that the proposed design requirements are not sufficient to protect against another event like Uri. Until industry addresses the compensation issue, it is unreasonable to adopt a design requirement for existing generating units.

While the NAGF supports efforts for generators to take reasonable steps to provide reliable service through cold weather events, a mandatory requirement without reasonable compensation puts some generators at an unfair and potentially fatal disadvantage, which is detrimental for the electric industry. It has also been noted that some generators are unable to meet the design requirements due to technological issues or availability. With the efforts made by the drafting team to address these conflicting issues, the proposed requirements are optional at best and therefore unlikely to provide improved reliability.

Given all of the challenges that we are seeing across the different regions regarding infrastructure issues , the creation of more uncertainty in the generation arena has the potential to further aggravate the situation rather than improve it.  NAGF members support ensuring generator operating parameters are communicated to, understood, and used in the planning processes by the appropriate entities is more appropriate and beneficial to reliability during these events than a blanket retrofit requirement to operate to an arbitrary condition.

The NAGF believes that the existing requirements in EOP-011 that are to be implemented no later than April 1, 2023, should be used first to determine if these proposed requirements are warranted. Until such time as these requirements become effective, NERC and FERC do not know where the need for further improvements exist.

To the extent that NERC and FERC wish to add to the reliability requirements related to cold weather operation, the NAGF proposes the following language:

“Generator Owners shall identify their minimum operating temperature based on operating history. This information shall include lowest temperature operated to, lowest wind chill temperature operated to, and the lowest temperature during which precipitation was occurring, if possible. These numbers shall be reviewed once each year to determine if new limits have been determined. “

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

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For all above questions,we are agaisnt this standard as for some Canadian entites, units already operate in cold weather annually from November to March. These requirements represent an added administrative burden.

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 9/1/2022

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ISO-NE appreciates the efforts of the SDT however, as an ISO acting as the RC and BA for our area ISO has some concerns as described in the above comments as well as in the comments provided by the SRC.  It appears that the Standard as written will ensure continued reliable operation of the BES under normal cold weather conditions, but would have limited effect on “Extreme” cold weather conditions such as those experienced during the 2014 Polar Vortex, the 2021 Storm Uri, or the 1994 North American cold wave (January 18-22).  ISO-NE recommends that the Standard address at a minimum the extreme cold temperatures and duration experienced during the 2021 Storm Uri which has been the primary example as the need for this new Standard.

ISO-NE Supports the Comments Provided by the SRC.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

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LES, Segment(s) 6, 1, 3, 5, 10/8/2018

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NPPD suggests removing the ‘July 1’ requirement for the deadline in generating a corrective action plan and making the deadline a straight 150 days from the event. If an event occurs in early March an entity might only have approx. 110 days to generate the corrective action plan. With a straight 150 days, an entity can still create the CAP before the next winter season.

We believe the timeframe for development of Corrective Action Plans (CAP) in R2 and R4.3 is unclear. The glossary definition of CAP is A list of actions and an associated timetable for implementation to remedy a specific problem. While the language is clear that CAPs are to be developed within the Requirements, it is not clear how long an entity has to develop the CAP.

Proposed language:

R2: “…shall develop a Corrective Action Plan (CAP) within 150 days for the identified issues…”

R4.3: “…and if not develop a CAP within 150 days for the identified issues…”

R6: “…shall develop a CAP, within 150 days that contains at a minimum:”

NPPD would like to propose the following language modification for Requirement R3.4:

Existing language “Annual inspection and maintenance of generating unit(s)…”

Proposed language “Annual inspection and maintenance as determined by the results of the inspection, of generating unit(s)…”

Jamison Cawley, Nebraska Public Power District, 1, 9/1/2022

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 9/1/2022

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Requirement R1

The MRO NSRF is concerned about Requirement R1, Bullet 1 as it relates to a “concurrent twenty (20) mph wind speed”.  The MRO NSRF believes that 20 mph is an arbitrary velocity that will not capture the actual conditions based on the geographic location of the generating unit, unnecessarily raise the operational cost of the generating unit and not increase the reliability of the generating unit, as the fixed velocity may be too low/high for the geographical location.  Rather than used a fixed velocity the MRO NSRF would like to suggest allowing the Generator Owner to calculate the appropriate wind speed using a statical methodology similar to how the Extreme Cold Weather Temperature is calculated.  Entity B would like to suggest the following Requirement R1 language modification and §6. Definitions Used in this proposed standard:

R1, Bullet 1: “… assuming a Concurrent Wind Speed on any exposed Generator Cold Weather Critical Components; or”

Concurrent Wind Speed – The wind speed equal to the highest X percentile of the hourly wind speeds for the geographic location of the generating unit, measured in December, January and February for the previous 30 years through the date the temperature is calculated.

Proposed language modifications:

The MRO NSRF would like to propose the following language modification for Requirement R3.4:

Existing language “Annual inspection and maintenance of generating unit(s)…”
Proposed language “Annual inspection and maintenance, as determined by the results of the inspection, of generating unit(s)…”

The MRO NSRF would like to propose the following language modification for Requirement R4:

Existing language “Once every five calendar years, each Generator Owner shall for each generating unit:”

Proposed language “Once every five calendar years, with a calendar year starting on the first day of a new year (January 1) after an activity pursuant to the subparts below has been completed, each Generator owner shall for each generating unit:” 

The MRO NSRF believes defining the calendar year, as it is in NERC Reliability Standard PRC-005-6, will provide added confines to when the five year cycle begins and does not leave interpretation for it to be a 60-month cycle.

The MRO NSRF would like to propose the following language modification for Requirement R6:

Existing language: “…experiences a Generator Cold Weather Reliability Event shall develop a CAP, within 150 days or by July 1, whichever is earlier, that contains at a minimum…”

Proposed language: “…experiences a Generator Cold Weather Reliability Event shall develop a CAP, within 150 calendar days, that contains at a minimum…”

We believe that 150 calendar days after a Generator Cold Weather Reliability Event should be the standard to develop a CAP. If the generating unit experiences a Generator Cold Weather Reliability Event on February 28, a Generator Owner will only have 120 days to develop a CAP.  Since CAPs may take additional resources to analyze and develop, 150 calendar days provides the same amount of time for Generator Owners to develop a CAP regardless of when during the winter season a Generator Cold Weather Reliably Event occurs. In addition, to align with the language in NERC Reliability Standard PRC-004-6, Entity B is recommending the inclusion of the word “calendar”. Also please consdier adding timeframe requirements for the development of Corrective Action Plans (CAP) in R2 and R4.3. The glossary definition of CAP is “A list of actions and an associated timetable for implementation to remedy a specific problem”. While the language is clear that CAPs are to be developed within the Requirements, it is not clear how long an entity has to develop the CAP. Proposed language:

R2: “…shall develop a Corrective Action Plan (CAP) within 150 days for the identified issues…”

R4.3: “…and if not develop a CAP within 150 days for the identified issues…”

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

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Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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MidAmerican Energy supports both the MRO NSRF and EEI comments for this section.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/1/2022

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Please see attached comments 

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

TCPA Comments on Revised NERC Weatherization Proposal - Filed 9-1-22.docx

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Note – From a design/development perspective, inverter-based generation resources are mostly operating to -25C for utility scale application. Any temperature below this would force the inverters to stop producing.

Steven Sconce, On Behalf of: EDF Renewable Energy, , Segments 5

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See attached comments document

Mark Young, Tenaska, Inc., 5, 9/1/2022

EOP-012-1 Second Draft - Tenaska Comments Rev 4 final.docx

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Imane Mrini, Austin Energy, 6, 9/1/2022

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MISO supports the comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC). In addition, we are submitting comments on behalf of MISO as an individual entity.

Guidance should be provided as to what is “economically feasible” so a consistent approach is used to assess “commercial constraints.”  (Part 7.1)

With respect to Part 7.1, which states:

“Each Generator Owner shall implement each CAP developed pursuant to Requirements R2, R4, or R6, or explain in a declaration why corrective actions are not being implemented due to any technical, commercial, or operational constraints as defined by the Generator Owner”

MISO observes that “commercial” aspects are typically outside of NERC’s purview which raises the question: how will this provision be monitored and enforced without pre-defined criteria? Therefore, MISO asks the SDT to set guidance as to what is “economically feasible.” Without meaningful guidance, providing a broad commercial "out" could encourage generators to elect this option as opposed to making improvements, particularly if a neighboring generator does likewise, thereby leaving the BES no more reliable than before the standard was drafted.

Finally, MISO acknowledges it is important to get this standard “right,” particularly in light of the changing resource mix. As traditional resources retire and are replaced with intermittent resources, it will be important to have design criteria, such as the Extreme Cold Weather Temperature definition, set appropriately to ensure reliability benefits are achieved and maintained over time.   

Bobbi Welch, Midcontinent ISO, Inc., 2, 9/1/2022

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Capital Power supports the North American Generators Forum (NAGF) response to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 9/1/2022

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Madison Gas and Electric supports the comments from the MRO NSRF.

Ronald Bauer, MGE Energy - Madison Gas and Electric Co., 3, 9/1/2022

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Madison Gas and Electric supports the comments of the MRO NSRF

Adam Lee, MGE Energy - Madison Gas and Electric Co., 4, 9/1/2022

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We have 2 additional comments for this standard not covered in the previous comment sections. These comments are specific to R5 and R6 respectively.

R5: In regards to the proposed verbiage requiring “generating unit-specific training”, it is our opinion that this could be overly burdensome for stations with multiple units; particular for those stations with multiple units of a similar design (a.k.a. “sister” units). Recommend modifying this requirement to require station-specific training in lieu of generating unit-specific training.

It is our opinion that this modification will allow the GO/GOP the flexibility to develop their training modules with an appropriate level of detail so as to sufficiently train station personnel without requiring them to create multiple modules with similar or identical content.

R6: Concerning the proposed timeline for the development of a CAP, it is our recommendation that the July 1st date be removed from this requirement. The rationale for this recommendations is thus: 150 days prior to July 1st is Feb 1st for non-leap years and Feb 2nd for leap years.  Moreover, the July 1st timeline is further condensed if a Generator Cold Weather Reliability Event (GCWRE) occurs in March or April.  Lastly, the stated intent of the timeframe options within the Technical Rationale is to allow GO’s to review multiple events holistically following a winter season. In certain areas of the country, a GCWRE could realistically occur as early as late-October. In this instance, the latest possible date for the development of a CAP would be March 30th. 

Given that it is also realistic for a GCWRE to occur in March, 150 days seems a reasonable number of days to cover all but the most extreme scenarios. Therefore, we recommend removing the hard deadline of July 1st.

Further, ACES has one member with the the following comments we would like to capture:

  • It should be noted that wind turbines are also highly susceptible to cold weather events. Ignoring wind units at a time when the grid is using them more and more may have long lasting consequences. 
  • Finally, extreme weather should include calm cloudy days. The standard is targeted to units that are being retired more and more from the grid. Piling on additional compliance burdens will only hasten these units departures. The SDT should consider targeted reliability standards that require intermittent resources to run, ride through, and in general operate more reliably. Intermittent resources no longer operate on the periphery, they are a core component of the functional power grid.

Thank you for the opportunity to comment.

ACES Standard Collaborations, Segment(s) 1, 3, 5, 9/1/2022

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Invenergy appreciates the SDT's time and work on this important project, and would like to offer the below additional comments.

Invenergy recommends the following change to R2 to better align it with R1:

For each generating unit(s) in commercial operation prior to [Effective Date of this requirement], the Generator Owner shall:

  • Add new or modify existing freeze protection measures as needed to provide the capability to operate for a period of not less than one (1) hour at the unit(s) Extreme Cold Weather Temperature.

Generating unit(s) that are not capable of operating for one (1) hour at its Extreme Cold Weather Temperature shall:

  • Develop a Corrective Action Plan (CAP) for the identified issue(s), including identification of any needed modifications to the cold weather preparedness plan required under Requirement R3; or
  • Explain in a declaration, any technical, commercial, or operational constraints as defined by the Generator Owner that preclude any ability to implement or modify appropriate freeze protection measures to provide capability of operating for one (1) hour at the documented Extreme Cold Weather Temperature.

Corresponding changes to other sections of the standard that flow from this section should be made as well.  In particular, the Violation Severity Level table for R2 should be edited to match those for R1.

Additionally, the SDT should consider adding language relieving Generator Owners of the need to develop CAPs for Generator Cold Weather Critical Components for which a technical, commercial, or operational constraint has already been declared.

Lastly, the SDT should clarify how a Generator Owner is expected to incorporate the wind speed criterion in R1 (“...assuming a concurrent twenty (20) mph wind speed on any exposed Generator Cold Weather Critical Components;") into their design. Specifically, is it purely a design consideration, or is it meant to be factored into the calculation of the Extreme Cold Weather Temperature?

Colin Chilcoat, Invenergy LLC, 6, 9/1/2022

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