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2015-08 Emergency Operations | EOP-004-4

Description:

Start Date: 11/18/2016
End Date: 01/09/2017

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2015-08 Emergency Operations | EOP-004-4 EOP-004-4 AB 2 ST 2015-08 Emergency Operations | EOP-004-4 EOP-004-4 07/25/2016 08/23/2016 12/28/2016 01/09/2017
2015-08 Emergency Operations | EOP-004-4 EOP-004-4 NBP AB 2 NB 2015-08 Emergency Operations | EOP-004-4 EOP-004-4 NBP 07/25/2016 08/23/2016 12/28/2016 01/09/2017

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Hot Answers

Michael Watkins, 1/9/2017

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Michael Watkins, 1/9/2017

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Other Answers

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 12/1/2016

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Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 12/7/2016

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Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 12/7/2016

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Preston Walker, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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The VSLs for R2 need to reflect the change in reporting deadlines to accommodate the reporting entity’s next business day

Colorado Springs Utilities, Segment(s) 5, 3, 1, 6, 5/6/2015

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Thomas Foltz, AEP, 5, 12/14/2016

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Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

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Andrew Pusztai, 12/23/2016

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Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Michael Watkins, 12/28/2016

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Michael Watkins, 12/28/2016

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

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Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

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To clarify the Standard pertains to Event Reporting, Reclamation respectfully proposes the following revised language for Standard EOP-004-4, R1, R2, M1, and M2: 

R1. : Each Responsible Entity shall have an Event Reporting Operating Plan that includes the protocol(s) for reporting the Reportable Events listed in EOP-004-4 Attachment 1 to the Electric Reliability Organization and other organizations (e.g., the Regional Entity, Responsible Entity personnel, the Responsible Entity’s Reliability Coordinator, law enforcement, or governmental authority).

Reclamation suggests re-wording M1 as follows: Each Responsible Entity will have a dated Event Reporting Operating Plan that includes the reporting protocol(s) and name(s) of organization(s) to receive an event report for the Reportable Event(s) specified in EOP-004-4 Attachment 1.

R2.  Each Responsible Entity shall report the types of events specified in EOP-004-4 Attachment 1, to the entities specified per its Event Reporting Operating Plan, by the later of 24 hours after recognition of meeting an event type threshold or by the end of the Responsible Entity’s next business day, whichever is later (4 p.m. local time will be considered the end of the business day).

M2.  Each Responsible Entity will have as evidence of reporting an event either a copy of the completed EOP-004-4 Attachment 2 form or a DOE-OE-417 form and some evidence of submittal (e.g., operator log or other operating documentation, voice recording, electronic mail message, or confirmation of facsimile) demonstrating the event report was submitted within the timeframes identified in R2 above.

 

Reclamation suggests the following change to both R2 and M2: “by the later of 24 hours after recognition of meeting an event type…”

Richard Jackson, U.S. Bureau of Reclamation, 1, 1/3/2017

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Don Schmit, Nebraska Public Power District, 5, 1/4/2017

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Sing Tay, OGE Energy - Oklahoma Gas and Electric Co., 6, 1/4/2017

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The NSRF would like to thank the Standard Drafting Team (SDT) for their thoughtful changes and believes the revisions proposed are valuable.  Please see question two for concerns that we have.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/4/2017

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Laura Nelson, IDACORP - Idaho Power Company, 1, 1/4/2017

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Jerome Gobby, 1/5/2017

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Ryan Olson, Portland General Electric Co., 5, 1/5/2017

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With regard to requirement R2, AZPS recommends modifying the text for clarity to read as “the later of 24 hours following recognition of meeting an event type” as opposed to “the later of 24 hours of recognition of meeting an event type.”

Michelle Amarantos, APS - Arizona Public Service Co., 1, 1/5/2017

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Ryan Olson, Portland General Electric Co., 5, 1/5/2017

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Con Edison, Segment(s) 1, 3, 5, 6, 0, 6/24/2016

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Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Duke Energy requests clarification on the addition of “by the later of” and the use of 4pm as the end of a business day. Is it the drafting team’s intent that the Responsible Entity has the option of submitting an Event Report 24 hours after the Event threshold has been reached, or the entity may choose to submit the report later than the 24 hours, as long as the report is submitted by 4pm the next business day? The proposed language as currently written may create some ambiguity depending on the reader.

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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Jamison Cawley, Nebraska Public Power District, 1, 1/6/2017

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Tony Eddleman, Nebraska Public Power District, 3, 1/6/2017

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As for Requirement R1, we have no concerns pertaining to the proposed changes. However, we feel the clarity notes applicable to Measurement M1 in the comment form are inaccurate (page 2). The notes mentions the correction to the version number however, it doesn’t mention the phrase “but is not limited to the” being stricken from the standard. We suggest the drafting team update all applicable documents to reflect that change.

SPP Standards Review Group, Segment(s) 0, 1/6/2017

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WAPA appreciates the efforts of the Standards Drafting Team (SDT) and welcomes the changes.

sean erickson, Western Area Power Administration, 1, 1/6/2017

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As stated in the comments with the initial ballot, Texas RE noticed there is no requirement specifically indicating how events should be reported.  Additionally, the VSLs indicate that a verbal report is acceptable.  Since an event reporting form exists, Texas RE recommends the requirements specify the form in Attachment 2 be used for event reporting. 

 

In the Severe VSL for R2 “-4_ should be added to the last sentence to maintain consistency (e.g. “EOP-004-4”).

Rachel Coyne, Texas Reliability Entity, Inc., 10, 1/6/2017

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RSC no Dominion, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 12/5/2016

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(1)   We thank the SDT for the development of this draft standard revision and the removal of the administrative burden reflected in Requirement R3 of the current standard.  While we generally agree with the results-based compliance approach presented in this draft, we feel that the SDT has an opportunity to further clarify the intentions of their proposed changes.

(2)   We believe Requirement R2 is intended to provide the Responsible Entity an option of using the criterion that will occur last when reporting.  While either criterion will occur “later” from the initial event discovery, as used in the context of an adverb describing a point in time, the ability to select one criterion versus the other is an adjective that describes the criteria’s comparison.  We recommend using “…by the latter of…” in the requirement text instead.

(3)   The first criterion listed in Requirement R2 states “24 hours of recognition of meeting an event type threshold for reporting.”  We believe the SDT inadvertently removed a necessary and supportive phrase that identifies the duration of the criterion.  We also believe the SDT failed to establish a starting trigger for this criterion with the recognition and discovery of the event.  We recommend rewording the criterion to read “within 24 hours following recognition of meeting an event type threshold for reporting.”

(4)   The second criterion listed in Requirement R2 identifies the end of a business day as 4:00 PM.  What is the rationale for selecting an arbitrary time?  How do joint-filing entities that operate across large geographic regions and multiple time zones identify the local time?  How does a single entity with centralized operations in one time zone identify local time for an event originating in a different time zone?  We agree with the SDT’s intent to remove ambiguity regarding weekends and holidays, but believe the addition of the 4:00 PM local time reference creates unintended confusion.  We recommend removing the reference entirely and allow some flexibility for the Responsible Entity to define its own meaning of “next business day.”  This would allow smaller entities, with a limited impact on BES reliability, to report after an extended weekend and after becoming fully staffed.

(5)   To clearly delineate the possible criteria available for Requirement R2, we believe each criterion should be renumbered into individual subparts list.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 4, 6, 1/6/2017

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BPA believes that the R2 language should only refer to required event reporting to Operating Plan entities (e.g. NERC and/or DOE) within the reporting period.

Ryan Buss, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Elizabeth Axson, 1/6/2017

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Hot Answers

Michael Watkins, 1/9/2017

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Michael Watkins, 1/9/2017

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Other Answers

Under physical threats to a facility, suspicious activity at a facility must be defined.  I suggest suspicious activity be given its own row (removed from within physical threats to a facility).  Specifically, “suspicious device or activity” is ambiguous. Further clarification on “suspicious activity” is needed. For example, does this include photography near a Facility? Also, Attachment 1 should specifically cover cyber related suspicious activity – for example, solicitation attempts or phishing calls at Facilities. There should also be instruction on what an Entity should do if they later realize the incident was NOT suspicious – for example, a prior reported incident which, after further investigation, turns out to be innocuous. The effect of using ambiguous terms and no mechanism for correcting incidents post investigation has left the industry with an output that contains more “trash” than value – many incidents that do not truly meet the definition of EOP 004 are sent out via EISAC which leads to the dilution of truly important incidents.

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 12/1/2016

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Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 12/7/2016

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Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 12/7/2016

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It appears that Attachment 1 is an effort to consolidate two separate reporting requirements. PJM believes the revision adds a bit of confusion. The ‘Automatic’ reporting section today states: via automatic undervoltage or underfrequency load shedding schemes, or SPS/RAS. PJM believes that the Standard should incorporate this clarity in the new EOP requirement so there is no confusion about reporting of ‘automatic’ load shed between 100-300MWs due to loss of BES Facilities (i.e. storms) which could be considered an emergency and also automatic, uncontrolled loss of 300MWs for any reason is reportable, which is why the 100-300MW presents confusion.

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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Colorado Springs Utilities, Segment(s) 5, 3, 1, 6, 5/6/2015

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Thomas Foltz, AEP, 5, 12/14/2016

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Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

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Andrew Pusztai, 12/23/2016

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Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Michael Watkins, 12/28/2016

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Michael Watkins, 12/28/2016

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At times there may be a need for a TOP to implement a public appeal for load reduction in certain areas of their system if there is a system operating limit that can only be controlled by reduced load.  We recommend replacing “BA” with “Initiating BA or TOP.”

The event types with multiple applicable entities such as, “Uncontrolled loss of firm load resulting from a BES Emergency”, and “System separation (islanding)” will most likely have the same event reported multiple times if the BA, TOP or RC are different entities.  This has in the past been a source of confusion with the same event being reported multiple times.  We recommend changing the Entity with Reporting Responsibility for the Event Type, “Uncontrolled loss of firm load resulting from a BES Emergency” to just the BA.  We recommend changing the Entity with Reporting Responsibility for the Event Type, “System separation (islanding)” to just the BA.  This would eliminate multiple reports for the same event, while still making sure the events are reported.

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

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Comments: Attachment 1, Page 10, 1st Row: Event Type: BES Emergency resulting in voltage deviation on a Facility – The voltage deviation range, as described in “Threshold for Reporting,” includes everything greater than -10% of nominal voltage which includes acceptable voltages. (e.g. For 115.0kV, everything greater than -10% would include 103.5 to 126.4kV)

Suggested Language for “Threshold for Reporting”: A voltage deviation of < -10% OR > 10% of nominal voltage sustained for > 15 continuous minutes.

 

Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

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Draft Standard EOP-004-4 Attachment 1, under table heading “Event Type”, Reclamation respectfully suggests consistent application of the replacement of “a” with “its” when referencing the Responsible Entity’s ownership, to be consistent with EOP-004-4 Attachment 2’s use of “its”.

Richard Jackson, U.S. Bureau of Reclamation, 1, 1/3/2017

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In Attachment 1, the Event Type, “Transmission loss” should be eliminated from mandatory reporting.  Events reported under this category are included in voluntary reporting under the NERC Event Analysis Program and this minimum impact level of events should not be included in mandatory compliance reporting subject to fines and penalties.  This category includes BES Facilities experiencing unexpected loss, contrary to design, of three or more BES Facilities.  Facilities are defined 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.).  The following examples support removal of this Event Type:

  1. Renewable generation, such as wind farms, with total generation >75MWs are included in BES Facilities.  A misoperation on a feeder at a wind facility including three (3) or more generators would require a mandatory report under EOP-004-4.  A typical wind farm generator is approximately 1.5 – 3.0 MWs each.  So, under Transmission loss, a generation loss of less than 10 MWs is required to be reported, but under the “Generation loss” Event Type in Attachment 1 to EOP-004-4, the reportable generation loss would need to be greater than 2,000 MWs (Eastern Interconnection) to be subject to mandatory fines and penalties.  10 MWs versus 2,000 MWs is an obvious disparity and clearly shows the minimal level of impact to reliability of the BES is not met.

  2. Under “Transmission loss”, a slow trip of a circuit breaker clearing a bus with 3 or more transmission lines or transformers, or generators, would be reportable under this mandatory compliance obligation and subject to fines and penalties.  This can happen even without a misoperation, if the circuit breaker is merely slow in clearing the fault and the backup protection on the breaker clears the bus.  All the protection systems can operate correctly and an entity is still subject to reporting under this event type.  These types of events are being collected under the NERC Event Analysis Program and these events do not meet the threshold of risk to the BES to enforce fines and penalties.  More significant “Transmission loss” events are included in other Event Types and associated with BES Emergencies.  Minor risk “Transmission loss” events are more appropriately handled through the voluntary NERC Event Analysis Program and do not need to be included in EOP-004 reporting.  The risk of these minor events does not translate to a significant risk to the BES and does not need to be included in mandatory compliance and enforcement.

  3. Under “transmission loss”, misoperations involving 3 or more Transmission lines, transformers, or generators are reportable under EOP-004-4.  Misoperation reporting is mandatory under PRC-004. Redundant reporting under EOP-004 is not needed and subjects entities to double jeopardy for compliance violations.

  4. The NERC Event Analysis Program has matured over the past few years and is an excellent tool for industry to review, discuss, and develop lessons learned to improve reliability.  Compliance obligations under the event type “Transmission loss” are no longer needed and are a detriment to reliability by taking the operational focus away from operation of the BES during these minor events to reporting when these reporting requirements are better handled through other existing programs.

Don Schmit, Nebraska Public Power District, 5, 1/4/2017

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Regarding the Event Type “Transmission Loss” in Attachment 1, we suggest that the SDT consider one of the following options:

1. Modify the threshold language as follows:

“Unexpected loss within its area, contrary to design, of three or more BES Transmission elements caused by a common disturbance (excluding successful automatic reclosing).”

Reasons:

a. The current NERC Glossary of Terms definition of “Facilities” includes generators. Therefore, renewable generation such as wind farms would require reporting for the loss of three or more generators. This loss in MW is minimal compared to the threshold stated in the Event Type “Generation loss”.

b. Generation loss is required to be reported by the BA.  Including generation in the reporting requirements for the TOP as well introduces confusion and the possibility of unnecessary or duplicative reporting.

OR

2. Remove this event type from this section of the document. 

Reasons:

a. Same reasons as listed above

b. This reporting is redundant having already been addressed in the NERC Event Analysis Program.

 

Sing Tay, OGE Energy - Oklahoma Gas and Electric Co., 6, 1/4/2017

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The NSRF believes we discovered a compliance concern that may cause entities to be non-compliant with Attachment 1, Event Type of Transmission loss.  With the use of Facility (and Element) in threshold for reporting, a Transmission Operator may not be aware that the NERC defined term of Facility also contains “a generator”.  Even though Event Type Generation loss is predicated on a MW threshold, a Transmission loss event also contains generators.  So, a TOP may lose 2 BES Transmission Facilities AND a BES Generator is tripped (due to the same Event), the TOP has then met the loss of “three or more BES Facilities” and is required to make a report per EOP-004-4.

 

  Either the SDT or NERC should publically post this clarification so all TOPs understand their obligations to the current enforceable EOP-004-2 and any further enforceable EOP-004. BES Elements (lines, transformers, and I5 reactors) that operate as a single Facility should be counted as one Facility.  This is predicated on the definition that a Facility is “a set of…”.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/4/2017

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Laura Nelson, IDACORP - Idaho Power Company, 1, 1/4/2017

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Jerome Gobby, 1/5/2017

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Ryan Olson, Portland General Electric Co., 5, 1/5/2017

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Michelle Amarantos, APS - Arizona Public Service Co., 1, 1/5/2017

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Ryan Olson, Portland General Electric Co., 5, 1/5/2017

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For the “Complete loss of monitoring or control capability at its staffed BES control center” Event Type, the “Threshold for Reporting” column should be revised as follows: “Complete loss of monitoring or control capability at its staffed BES control center for 30 continuous minutes or more, such that analysis capability (i.e., State Estimator or Contingency Analysis) is rendered inoperable.” The “Threshold for Reporting” language should continue to include the “such that[…]” language to maintain consistency with the EAP.

Con Edison, Segment(s) 1, 3, 5, 6, 0, 6/24/2016

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CenterPoint Energy generally agrees with the SDT’s proposed revisions to EOP-004-3, Attachment 1: Reportable Events, but would like the SDT to consider the following:

The addition of the word “staffed” in front of “BES control center…” becomes a qualifier to distinguish which control center is in scope for reporting to this category. An entity may have more than one control center that is “staffed” but we believe that the control center that is responsible for performing Real-time functions responsible for reliability is the control center that is in scope for when the threshold for complete loss of interpersonal Communication capability has been lost is met. Additionally, the term “control center” is not capitalized. We suggest that the term be capitalized to align with the glossary definition of Control Center and to align with the use Control Center in category 1h as it applies to the loss of monitoring or control at a Control Center. It is not necessary to have BES in front of Control Center because it is already included in the NERC definition.

In summary, CenterPoint energy offers the following suggestions for the Event Type and Threshold for Reporting:

Event Type - Complete loss of Interpersonal Communication and Alternative Interpersonal Communication capability at a Control Center.

Threshold for Reporting - Complete loss of Interpersonal Communication and Alternative Interpersonal Communication capability  affecting a staffed Control Center responsible for performing Real-time functions for the reliability of its BES for 30 continuous minutes or more.  

Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Duke Energy recommends the following edits to Event Types in Attachment 1:

•          Public appeal for load reduction

•          Firm load shedding

We recommend the removal of the phrase “resulting from a BES Emergency” from the Event Type, and placing the phrase in the Threshold for Reporting.

Duke Energy recommends the following edits to Threshold for Reporting in Attachment 1:

•          Public appeal for load reduction resulting from a BES Emergency.

•          System-wide voltage reduction of 3% or more resulting from a BES Emergency.

•          Firm load shedding ≥ 100 MW (manual or automatic) resulting from a BES Emergency.

We recommend the removal of the of the phrase “to maintain continuity of the BES” and replacing with the more widely understood “resulting from a BES Emergency”. We feel that adding “resulting from a BES Emergency” to the “Threshold for Reporting” in both cases consistently creates a better understanding and is less vague.  By doing this, it puts the details in the “Threshold for Reporting” language where we feel they are best suited. Additionally, while we understand the phrase “to maintain continuity of the BES” would mirror the reference used in OE-417, that doesn’t mean that the phrase is any less ambiguous or clearly understood throughout the industry. With BES Emergency being a defined term, and readily used throughout the industry, we believe it better suited than the less known, undefined concept of “to maintain continuity of the BES”.

Firm load shedding resulting from a BES Emergency:

We recommend the drafting team consider adding “or” to the “Entity with Reporting Responsibility” section for this Event Type.  We suggest the following: “Initiating RC, BA, or TOP”.  We feel that the addition of “or” furthers the drafting team’s intent that only one of the listed entities is expected to file the report.  As written, one could still read the language as to state that all entities are required to file a report rather than just the initiating entity.

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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In Attachment 1, the Event Type, “Transmission loss” should be eliminated from mandatory reporting.  Events reported under this category are included in voluntary reporting under the NERC Event Analysis Program and this minimum impact level of events should not be included in mandatory compliance reporting subject to fines and penalties.  This category includes BES Facilities experiencing unexpected loss, contrary to design, of three or more BES Facilities.  Facilities are defined 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.).  The following examples support removal of this Event Type:

  1. Renewable generation, such as wind farms, with total generation >75MWs are included in BES Facilities.  A misoperation on a feeder at a wind facility including three (3) or more generators would require a mandatory report under EOP-004-4.  A typical wind farm generator is approximately 1.5 – 3.0 MWs each.  So, under Transmission loss, a generation loss of less than 10 MWs is required to be reported, but under the “Generation loss” Event Type in Attachment 1 to EOP-004-4, the reportable generation loss would need to be greater than 2,000 MWs (Eastern Interconnection) to be subject to mandatory fines and penalties.  10 MWs versus 2,000 MWs is an obvious disparity and clearly shows the minimal level of impact to reliability of the BES is not met.

  2. Under “Transmission loss”, a slow trip of a circuit breaker clearing a bus with 3 or more transmission lines or transformers, or generators, would be reportable under this mandatory compliance obligation and subject to fines and penalties.  This can happen even without a misoperation, if the circuit breaker is merely slow in clearing the fault and the backup protection on the breaker clears the bus.  All the protection systems can operate correctly and an entity is still subject to reporting under this event type.  These types of events are being collected under the NERC Event Analysis Program and these events do not meet the threshold of risk to the BES to enforce fines and penalties.  More significant “Transmission loss” events are included in other Event Types and associated with BES Emergencies.  Minor risk “Transmission loss” events are more appropriately handled through the voluntary NERC Event Analysis Program and do not need to be included in EOP-004 reporting.  The risk of these minor events does not translate to a significant risk to the BES and does not need to be included in mandatory compliance and enforcement.

  3. Under “transmission loss”, misoperations involving 3 or more Transmission lines, transformers, or generators are reportable under EOP-004-4.  Misoperation reporting is mandatory under PRC-004. Redundant reporting under EOP-004 is not needed and subjects entities to double jeopardy for compliance violations.

  4. The NERC Event Analysis Program has matured over the past few years and is an excellent tool for industry to review, discuss, and develop lessons learned to improve reliability.  Compliance obligations under the event type “Transmission loss” are no longer needed and are a detriment to reliability by taking the operational focus away from operation of the BES during these minor events to reporting when these reporting requirements are better handled through other existing programs.

Jamison Cawley, Nebraska Public Power District, 1, 1/6/2017

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In Attachment 1, the Event Type, “Transmission loss” should be eliminated from mandatory reporting.  Events reported under this category are included in voluntary reporting under the NERC Event Analysis Program and this minimum impact level of events should not be included in mandatory compliance reporting subject to fines and penalties.  This category includes BES Facilities experiencing unexpected loss, contrary to design, of three or more BES Facilities.  Facilities are defined 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.).  The following examples support removal of this Event Type:

  1. Renewable generation, such as wind farms, with total generation >75MWs are included in BES Facilities.  A misoperation on a feeder at a wind facility including three (3) or more generators would require a mandatory report under EOP-004-4.  A typical wind farm generator is approximately 1.5 – 3.0 MWs each.  So, under Transmission loss, a generation loss of less than 10 MWs is required to be reported, but under the “Generation loss” Event Type in Attachment 1 to EOP-004-4, the reportable generation loss would need to be greater than 2,000 MWs (Eastern Interconnection) to be subject to mandatory fines and penalties.  10 MWs versus 2,000 MWs is an obvious disparity and clearly shows the minimal level of impact to reliability of the BES is not met.

  2. Under “Transmission loss”, a slow trip of a circuit breaker clearing a bus with 3 or more transmission lines or transformers, or generators, would be reportable under this mandatory compliance obligation and subject to fines and penalties.  This can happen even without a misoperation, if the circuit breaker is merely slow in clearing the fault and the backup protection on the breaker clears the bus.  All the protection systems can operate correctly and an entity is still subject to reporting under this event type.  These types of events are being collected under the NERC Event Analysis Program and these events do not meet the threshold of risk to the BES to enforce fines and penalties.  More significant “Transmission loss” events are included in other Event Types and associated with BES Emergencies.  Minor risk “Transmission loss” events are more appropriately handled through the voluntary NERC Event Analysis Program and do not need to be included in EOP-004 reporting.  The risk of these minor events does not translate to a significant risk to the BES and does not need to be included in mandatory compliance and enforcement.

  3. Under “transmission loss”, misoperations involving 3 or more Transmission lines, transformers, or generators are reportable under EOP-004-4.  Misoperation reporting is mandatory under PRC-004. Redundant reporting under EOP-004 is not needed and subjects entities to double jeopardy for compliance violations.

  4. The NERC Event Analysis Program has matured over the past few years and is an excellent tool for industry to review, discuss, and develop lessons learned to improve reliability.  Compliance obligations under the event type “Transmission loss” are no longer needed and are a detriment to reliability by taking the operational focus away from operation of the BES during these minor events to reporting when these reporting requirements are better handled through other existing programs.

Tony Eddleman, Nebraska Public Power District, 3, 1/6/2017

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We suggest that the Event Type “Transmission Loss” in Attachment 1 be removed from this section of the document. We feel that this effort is redundant and has been addressed in the NERC Event Analysis Program. Our first example would be applicable to, the renewable generation such as wind farms would require reporting for the loss of three or more generators pertain to a Misoperations. Another example would be, the slow trip of a circuit breaker clearing three or more transmission lines would be reportable even if it didn’t include a Misoperations.

 

SPP Standards Review Group, Segment(s) 0, 1/6/2017

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Overall the changes to the Standard are positive and WAPA appreciates the efforts of the SDT.  However, there is still significant room for confusion regarding reportable Transmission Loss Events as a TOP with the change from Element to Facility.  WAPA would very much appreciate examples within the standard that clarify events which would be reportable and events which would not be reportable.

sean erickson, Western Area Power Administration, 1, 1/6/2017

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Texas RE appreciates the SDT’s response to Texas RE’s previous comments regarding the removal of the IROLTV reporting obligation.  As the SDT noted in its response, the SDT removed the reporting requirement because the new TOP-001-3 R12 requirement requires registered entities to avoid exceeding IROLs for the relevant TV period.  As such, the SDT reasons that entities will self-report any noncompliance and there is no need to retain the corresponding reporting requirement. 

 

Texas RE sees two issues with the SDT’s rationale.  First, as Texas RE noted in its original comments, there is a significant difference in the purpose and timing of the EOP-004 reporting requirements and the substantive obligations set forth under the new TOP-001-3, R12.  Texas RE noted:  “While such an exceedance may be investigated in the compliance or enforcement process, there is necessarily a delay in these activities.  The contemporaneous reporting obligations serve to ensure that the NERC regions have immediate knowledge that a significant risk of a cascading outage has occurred, permitting the region to begin steps to identify the root cause and develop appropriate mitigation.  Because such awareness appears critical to the core reliability functions performed within the NERC regions, Texas RE cautions against eliminating this requirement.”  Simply put, the mere existence of a parallel substantive requirement does not address Texas RE’s concern.  Texas RE cannot support the elimination of the IROLTV reporting obligation based on the SDT’s proffered rationale.

 

Second, the SDT appears to misunderstand the self-reporting process.  Principally, entities are under no obligation to self-report potential noncompliance instances, and may elect not to do so at their sole discretion.  Given that certain utilities are on three- or even six-year audit cycles, an entity could decline to self-report an IROL exceedance violating TOP-001-3, R12 and wait until its next scheduled audit (contingent on the requirement being included in the audit scope).  Accordingly, a potential issue could linger for years before it is addressed in the enforcement process.  This is precisely the reason Texas RE believes the contemporaneous reporting requirement continues to be a necessary part of the NERC Reliability Standards. 

 

 

Texas RE also suggests the Standard is too narrow in its reporting requirements for events.  According to the Events Analysis Process effective January 1, 2017, “The primary reason for participating in an event analysis is to determine if there are lessons to be learned and shared with the industry. The analysis process involves identifying what happened, why it happened, and what can be done to prevent reoccurrence.”  Texas RE recommends broadening the requirements in order to understand prevention as well as what took place when event actually occurred.   Texas RE provides the following suggestions for broadening the reporting requirements.

  • Public appeal for load reduction should not be limited to a BES Emergency.  In some cases the appeal may be done to avoid a BES Emergency and that event should be evaluated per the Events Analysis Process in order to prevent issues from occurring in the future. 

     

  • As previously submitted in comments with the initial ballot, Texas RE recommends adding the TOP function to the public appeal event type.  This will align and be consistent with EOP-001-2.1b Requirement R2, which requires a TOP to “Develop, maintain, and implement a set of plans for load shedding”, EOP-001-2.1b Requirement R3, which requires a TOP emergency plan to include “Load reduction”, and EOP-001-2.1b Requirement R4, which references elements in Attachment 1-EOP-001 that a TOP and BA should consider when developing emergency plans. 

     

  • For the event types, “Complete loss of monitoring or control capability at its staffed BES control center” and “Complete loss of Interpersonal Communications and Alternative Interpersonal Communication capability at its staffed BES control center”, Texas RE recommends removing “its staffed”.  Loss of monitoring or control capability is just as important at a non-staffed site as it is a staffed site and there should be no distinction in staffing status.  Understanding why complete loss of monitoring or control capability and complete loss of Interpersonal and Alternative Interpersonal Communications occurred will increase the likelihood of prevention in the future.

     

    Reliability Standard EOP-004-2 does not take into account GOP Control Centers.  As previously stated, Texas RE recommends adding the GOP to the entity with reporting responsibility.  Reliability Standard CIP-002-5 states that “each Control Center or back up Control Center used to perform the functional obligations of the Generator Operator” (CIP-002-5, Attachment 1, Sections 1.4 and 2.11) should be considered in an entity’s identification of high and medium BES Cyber Systems.  Reliability Standard CIP-008-5 Requirement 1 requires Responsible Entities with High and Medium Impact BES Cyber Systems (which could include GOP Control Centers) to have a process to determine if a Cyber Security Incident is reportable and noticed the E-ISAC.  Since this includes GOP Controls Centers, it would be consistent to include GOP Control Centers in EOP-004-4.  Also, there are several GOPs in Texas (and other regions) that may control more megawatts than some BAs and yet there is no requirement to report events that occur so they are studied and preventative measures are taken in the future.  Since CIP-002-5 has a mechanism for considering GOP Control Centers, and there are several GOP Control Centers that may control as much or more generation than a BA, Texas RE recommends adding the GOP as an entity with reporting responsibility.  From a consistency and reliability stand point, events that occur at a GOP Control Center should be reported on and evaluated.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 1/6/2017

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For the “Complete loss of monitoring or control capability at its staffed BES control center” Event Type, the “Threshold for Reporting” column should be revised as follows: “Complete loss of monitoring or control capability at its staffed BES control center for 30 continuous minutes or more, such that analysis capability (i.e., State Estimator or Contingency Analysis) is rendered inoperable.” The “Threshold for Reporting” language should continue to include the “such that […]” language to maintain consistency with the EAP.

RSC no Dominion, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 12/5/2016

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(1)   We believe the SDT is attempting to align Transmission Loss events with similar reportable criteria listed under the current NERC Event Analysis process.  As identified within supportive documentation for this mature process, Category 1a Events caused by common disturbances affecting BES Facilities only refers to BES-defined lines, generators, and transformers.  When capitalizing Facility in the context of this reportable criterion, this includes equipment like shunt compensators, circuit breakers, and busses.  Furthermore, events caused by Misoperations are reportable under NERC Reliability Standard PRC-004, and could cause repetitive reporting in the process.  If the SDT does not consider the outright removal of this event type from the EOP-004 reportable criteria, we recommend rephrasing the threshold for reporting a Transmission Loss event, as reportable to TOPs only, as “Unexpected loss, within its area and contrary to design or successful automatic reclosing, of three or more Transmission Facilities caused by a common disturbance.”

(2)   The reference to “=/>” in the reporting threshold for a BES Emergency resulting in a voltage deviation literally reads “equal to or greater than.”  Is the intent of the SDT to identify a reporting threshold greater than ± 10% of nominal voltage?  We propose using the symbol “≥” to reflect reporting a sustainable voltage deviation that is greater than or equal to ± 10% of nominal voltage over a continuous 15-minute period.

(3)   We believe the proposed reportable threshold reference under Generation Loss should be clarified to identify Forced Outages only.  Forced Outages is listed under the NERC Glossary and identifies the removal of generation from service for either emergency reasons or unanticipated failures.  We feel the incorporation of references to extreme weather patterns or fuel supply unavailability is unnecessary when used within this context.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 4, 6, 1/6/2017

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BPA believes that the BA or TOP could be the initiating parties for a load appeal.  Also, more clarity should be added for automatic load shedding causes (UVLS, UFLS, RAS).

Ryan Buss, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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ERCOT appreciates the SDT revising the generation loss reporting threshold for the ERCOT Interconnection to 1,400 MW from 1,000 MW in Attachment 1 of EOP-004.  This change is consistent with ERCOT’s September 8, 2016 comments, which requested this revision to align the reporting threshold with the ERO Event Analysis Process (EAP) document’s threshold for initiating an analysis of a Category 3a generation loss event in the ERCOT Interconnection, which, at the time of ERCOT’s comment, was 1,400 MW.

 

However, concurrent with Project 2015-08, the NERC Event Analysis Subcommittee (EAS) proposed changes to the EAP document that, among other things, sought to standardize the event analysis threshold for all Interconnections—including ERCOT—at 2,000 MW.  The draft EAP document was first posted for comment on the NERC website on September 30, 2016, some three weeks after ERCOT submitted its comments to the latest version of EOP-004.  The revised EAP document—version 3.1—was ultimately approved by the NERC Operating Committee at its December 13, 2016 meeting and became effective January 1, 2017.  Thus, the threshold for conducting an analysis of Category 3a events is now 2,000 MW.

 

Consistent with ERCOT’s September 8 comments and with the SDT’s change to the reporting threshold in the last version of the draft standard, ERCOT believes the threshold for generation loss reporting in EOP-004 should continue to align with the EAP document’s threshold for analysis of Category 3a events, which is now 2,000 MW.  If there are any reasons for differentiating between the two thresholds, this justification does not seem immediately obvious.  Fundamentally, in ERCOT’s view, it would make little sense to require development of a written report of a generation loss event and distribute it to various entities if the event did not also justify an analysis under the EAP process.  Furthermore, the reasons cited by the EAS for increasing the event analysis threshold—the implementation of BAL-003-1.1 and BAL-001-TRE-01, and the procurement of greater quantities of responsive reserve in ERCOT, among other reasons—would also appear to justify increasing the event reporting threshold.  See Justification for Proposed Changes to the ERO Event Analysis Process Categories 1g and 3a (attached). 

 

In conclusion, ERCOT appreciates the SDT’s recognition of the need to align the EOP-004 generation loss reporting threshold with the EAP document’s generation loss event analysis threshold and asks the SDT to continue this alignment by setting the generation loss reporting threshold for the ERCOT Interconnection in EOP-004 Attachment 1 to 2,000 MW.

Elizabeth Axson, 1/6/2017

ERO_EAP_Documents DL-Justification_for_Event_Category_1g_and_3a_changes_for_ERCOT.pdf

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Hot Answers

Michael Watkins, 1/9/2017

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Michael Watkins, 1/9/2017

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Other Answers

 I suggest suspicious activity be given its own row.

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 12/1/2016

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Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 12/7/2016

- 0 - 0

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 12/7/2016

- 0 - 0

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

- 0 - 0

Colorado Springs Utilities, Segment(s) 5, 3, 1, 6, 5/6/2015

- 0 - 0

Thomas Foltz, AEP, 5, 12/14/2016

- 0 - 0

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

- 0 - 0

Andrew Pusztai, 12/23/2016

- 0 - 0

Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

- 0 - 0

Michael Watkins, 12/28/2016

- 0 - 0

Michael Watkins, 12/28/2016

- 0 - 0

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

- 0 - 0

Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

- 0 - 0

Reclamation suggests consistent application of the replacement of “a” with “its” as it pertains to the Responsible Entity’s ownership.

Richard Jackson, U.S. Bureau of Reclamation, 1, 1/3/2017

- 0 - 0

Don Schmit, Nebraska Public Power District, 5, 1/4/2017

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Depending on the changes (if any) made to the recommendations stated in Question 2 above for Event Type "Transmission loss", Attachment 2 will need to be revised accordingly.

Sing Tay, OGE Energy - Oklahoma Gas and Electric Co., 6, 1/4/2017

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/4/2017

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 1/4/2017

- 0 - 0

Jerome Gobby, 1/5/2017

- 0 - 0

Ryan Olson, Portland General Electric Co., 5, 1/5/2017

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 1, 1/5/2017

- 0 - 0

Ryan Olson, Portland General Electric Co., 5, 1/5/2017

- 0 - 0

Con Edison, Segment(s) 1, 3, 5, 6, 0, 6/24/2016

- 0 - 0

CenterPoint Energy suggests that the “Tasks” in Attachment 2 Event Reporting Form align with the Event Types in Attachment 1 if revised by the SDT.

Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 1/6/2017

- 0 - 0

- 0 - 0

Tony Eddleman, Nebraska Public Power District, 3, 1/6/2017

- 0 - 0

SPP Standards Review Group, Segment(s) 0, 1/6/2017

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sean erickson, Western Area Power Administration, 1, 1/6/2017

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Please see Texas RE’s comment for #2.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 1/6/2017

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RSC no Dominion, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 12/5/2016

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We find the proposed two-page format of the Attachment 2 form impractical.  We offer a single page solution, as an attachment and proof that this information can be condensed accordingly.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 4, 6, 1/6/2017

Proposed_EOP-004-4_Attachment2.docx

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BPA believes that the language should only refer to required event reporting to Operating Plan entities (e.g. NERC and/or DOE) within the reporting period.

Ryan Buss, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Elizabeth Axson, 1/6/2017

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Hot Answers

Michael Watkins, 1/9/2017

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Michael Watkins, 1/9/2017

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Other Answers

 “Suspicious device or activity” in Attachment 1 is not defined even though Suspicious is capitalized. The NERC Glossary of Terms does not define “Suspicious” either.

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 12/1/2016

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Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 12/7/2016

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Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 12/7/2016

- 0 - 0

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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The VSLs for R2 need to reflect the change in reporting deadlines to accommodate the reporting entity’s next business day

Colorado Springs Utilities, Segment(s) 5, 3, 1, 6, 5/6/2015

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Thomas Foltz, AEP, 5, 12/14/2016

- 0 - 0

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

- 0 - 0

Andrew Pusztai, 12/23/2016

- 0 - 0

R2 of EOP-004-4 state:

Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their event reporting Operating Plan:

-by the later of 24 hours of recognition of meeting an event type threshold for reporting

or

-by the end of the Responsible Entity’s next business day (4 p.m. local time will be considered the end of the business day).

 

The VSL Section state:

The Responsible Entity submitted an event report (e.g., written or verbal) to all required recipients more than 24 hours but less than or equal to 36 hours after recognition of meeting an event threshold for reporting.

Based on this example, if an event occurred at midnight (12 a.m. Tuesday), the entity can submit a report by the end of the next business day (4 p.m. local time will be considered the end of the business day) which is Wednesday 4p.m. That means 40 hours after the event.

On the Lower VSL, Hydro-Quebec TransEnergie suggest to remove this paragraph  “The Responsible Entity submitted an event report (e.g., written or verbal) to all required recipients more than 24 hours but less than or equal to 36 hours after recognition of meeting an event threshold for reporting. OR” .

On the Moderate VSL, Hydro-Quebec TransEnergie suggest modifying as following: “The Responsible Entity submitted an event report (e.g., written or verbal) to all required recipients more than 40 hours but less than or equal to 48 hours after recognition of meeting an event threshold for reporting.”

Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Michael Watkins, 12/28/2016

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Michael Watkins, 12/28/2016

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None.

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

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Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

- 0 - 0

Richard Jackson, U.S. Bureau of Reclamation, 1, 1/3/2017

- 0 - 0

Don Schmit, Nebraska Public Power District, 5, 1/4/2017

- 0 - 0

N/A.

Sing Tay, OGE Energy - Oklahoma Gas and Electric Co., 6, 1/4/2017

- 0 - 0

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/4/2017

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 1/4/2017

- 0 - 0

Jerome Gobby, 1/5/2017

- 0 - 0

Ryan Olson, Portland General Electric Co., 5, 1/5/2017

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 1, 1/5/2017

- 0 - 0

Ryan Olson, Portland General Electric Co., 5, 1/5/2017

- 0 - 0

Con Edison, Segment(s) 1, 3, 5, 6, 0, 6/24/2016

- 0 - 0

Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 1/6/2017

- 0 - 0

- 0 - 0

Tony Eddleman, Nebraska Public Power District, 3, 1/6/2017

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We suggest capitalizing the term “control center” as it’s defined in the NERC Glossary of Terms.  Additionally, the terms “Reliability Coordinator (RC)”, “Balancing Authority (BA)”, and “Transmission Operator (TOP)” (applicable in the Entity with Reporting Responsibility sections of Attachment 1) are terms included in the definition of the term “Control Center” which provides more details on why the term should be capitalized throughout Attachment 1.

SPP Standards Review Group, Segment(s) 0, 1/6/2017

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sean erickson, Western Area Power Administration, 1, 1/6/2017

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In its previous comments, Texas RE requested that the SDT provide the rationale for adopting a 12-month implementation timeframe.  In particular, Texas RE noted that “Given that registered entities presently are required to submit event reports under the current version of EOP-004 and the revised version largely narrows the scope of such reporting activities, it is unclear why a 12-month implementation period is necessary.”  With this comment, Texas RE sought to understand the basis for the SDT’s conclusion that a 12-month period was necessary to give entities appropriate time to address the revised Standard requirements.  Rather than provide a rationale in its response, the SDT merely noted that its intent is for the 12-month Implementation Plan “was to give all entities an appropriate time frame for implementation.” 

 

Texas RE therefore reiterates its request that the SDT provide a substantive basis for its determination that a 12-month time frame is appropriate.  In response, the SDT could describe the additional compliance obligations for entities for the revisions, whether these will impose additional costs, require additional staffing, or other compliance burdens that serve as the basis for its conclusion. 

Rachel Coyne, Texas Reliability Entity, Inc., 10, 1/6/2017

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R2 of EOP-004-4 state:

Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their event reporting Operating Plan:

-by the later of 24 hours of recognition of meeting an event type threshold for reporting

or

-by the end of the Responsible Entity’s next business day (4 p.m. local time will be considered the end of the business day).

The VSL Section state:

The Responsible Entity submitted an event report (e.g., written or verbal) to all required recipients more than 24 hours but less than or equal to 36 hours after recognition of meeting an event threshold for reporting.

By example, if an event occurred at midnight (12 a.m. Tuesday), the entity can submit a report by the end of the next business day (4 p.m. local time will be considered the end of the business day) which is Wednesday 4p.m. That means 40 hours after the event.

We suggest to remove this paragraph “The Responsible Entity submitted an event report (e.g., written or verbal) to all required recipients more than 24 hours but less than or equal to 36 hours after recognition of meeting an event threshold for reporting. OR” of the Lower VSL.

We suggest also modifying the moderate VSL as following: “The Responsible Entity submitted an event report (e.g., written or verbal) to all required recipients more than 40 hours but less than or equal to 48 hours after recognition of meeting an event threshold for reporting.”

 

 

1.      In the section below, not sure why “Event Report” is capitalized?  It seems that this “NOTE” intends to give an entity flexibility on the reporting timing, “under certain adverse conditions”, by differentiating between issuing a “written Event Report” and a “notification” (still to be done within timing requirements of R2), but I’m not sure this is the reasons for capitalizing “Event Report”?  

EOP-004 - Attachment 1: Reportable Events

NOTE: Under certain adverse conditions (e.g. severe weather, multiple events) it may not be possible to report the damage caused by an event and issue a written Event Report within the timing in the standard. In such cases, the affected Responsible Entity shall notify parties per Requirement R2 and provide as much information as is available at the time of the notification. Submit reports to the ERO via one of the following: e-mail: systemawareness@nerc.net, Facsimile 404-446-9770 or Voice: 404-446-9780, select Option 1

2.      For SDT’s consideration - Event Types in the Attachment 1 do not seem to capture GOP BES control centers (either evacuation or physical threats)? 

·         By capitalizing “Facility” in the Event Type for a “Physical Threat to its Facility”, since this term is defined in the NERC Glossary (and does not capture control center in the definition), this category excludes GOPs from reporting physical threats to their BES control centers under EOP-004. 

·         By excluding GOPs from the “Entity with Reporting Responsibility” list in the “Unplanned BES control center evacuation” Event Type, this category excludes GOPs from reporting evacuations from their BES control centers under EOP-004.

·         Same as the bullet above for the “Complete loss of Interpersonal Communication capability at a BES control center”

Not sure if this is an intentional omission?  CIP standards explicitly identify GOP control centers (High, Medium and Low Impact Rating) as subject to CIP requirements.  CIP requirements are being implemented recognizing that there is an impact on BES from a CIP incident on a GOP control center, but EOP-004 doesn’t capture non-cyber events associated with the same facilities for reporting requirements – seems inconsistent. 

At least High Impact GOP control centers, under the “Threshold for Reporting” should be considered for reporting requirements under EOP-004, for the events identified above.

This comment is being submitted recognizing that the current version of EOP-004-2 does not required this reporting either, for the same reasons identified in the three bullets above.

 

RSC no Dominion, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 12/5/2016

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(1)   Based on the specifics of Attachment 1, we believe there is sufficient information available to include an applicability section within the standard pertaining to Facilities.  The intent of this standard is to not capture events occurring on non-BES identified facilities.  This would include reporting on small generating resources or dispersed power producing resources with nameplate ratings under 20 MVA or aggregate nameplate ratings under 75 MVA that are connected to a common connection point at 100 kV or above.

(2)   We question the VSL for Requirement R2 identifying a severity for when a Responsible Entity fails to submit an event report within 24 hours.  We ask the SDT to clarify if the severity is based on 24 hours of the event’s discovery or within 24 hours of the event’s conclusion, independently of the expectation already proposed within the requirement text.

(3)   From the last commenting period for this draft standard revision, we previously recommended the implementation of an event reporting software tool on the NERC website providing capabilities to notify applicable Regional Entities and the DOE.  We thank the SDT for its efforts to align event reporting activities with the DOE.  However, based on the SDT’s response to our comments, we are left with the impression that no automated mechanism is available to share event notifications submitted to the DOE with required Regional Entities, Reliability Coordinators, law enforcement, and other governmental authorities per Requirement R1.  We believe a preventable human performance issue could be diverted through the development of a centralized portal that would disperse event reports to appropriate entities when necessary.  We again ask the NERC Standards Developer assigned to this project to share this comment with NERC’s IT department to see if a viable solution is available or could be developed.

(4)   We thank you for this opportunity to provide feedback.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 4, 6, 1/6/2017

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N/A

Ryan Buss, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Elizabeth Axson, 1/6/2017

- 0 - 0