p-1 spp reliability ors 5 6 2014 final - nerc reliability... · 5/19/2014 2 fg 6009 cooper south...

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SPP Reliability Coordinator:Proxy FlowgateReport

May 6‐7, 2014

Robert Rhodes

[email protected]

501‐614‐3241

Proxy Flowgates for this Reporting Period:

2

February 1, 2014 – April 15, 2014

Flowgate (6009): Cooper South

Flowgate (6104): Iatan – St Joe 345kV (Iatan – Eastown 345kV)

Flowgate (6147): Ft Calhoun – Raun 345kV

Flowgate (18982): Axtell – Post Rock 345kV ftlo Red Willow – Mingo 345kV

Flowgate (6126): Sub 1226 – Tekamah 161kV ftlo Sub 3451 – Raun 345kV

Presentation 1

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FG 6009 Cooper South

TLR DATE Return to Zero TLR Level

3/30/2014 15:00 3/30/2014 22:00 3


• Temporary Proxy for

• FG 5228 Iatan – Stranger 345kV ftlo St. Joe – Hawthorn 345kV

• OATI IDC was reporting inconsistent market flows on FG 5228.

• Used FG 6009 as proxy to obtain relief in lieu of TLR on FG 5228.

• Ended use of proxy once market flows were being reported correctly on FG 5228.

4

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Proxy Elements

Monitored Elements

FG 6104 Iatan – St. Joe 345kV


3/20/2014 07:30 3/20/2014 13:00 3

3/25/2014 20:00 3/26/2014 00:00 3

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• FG 5496 Eastown 345/161kV ftlo St. Joe – Eastown 345kV

• Heavy South – North loading across system

• CME and TLR on FG 5496 insufficient in providing relief

• Proxy used to control heavy loading across system to acceptable levels


Monitored Elements

Proxy Element

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FG 6147 Ft. Calhoun – Raun 345kV


3/23/2014 07:00 3/23/2014 08:45 3



• FG 20163 Ft. Calhoun – Raun 345kV ftlo Hoskins – Shell Creek 345kV

• Heavy South‐North loading across system

• Proxy (FG 6147) used to control loading while temporary flowgate (FG 20163) was being built

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11

Proxy Element

Monitored Element


Raun

Ft.Calhoun

Tekamah

Hoskins

Shell Creek

FG 18982 Axtell – Post Rock 345kV ftlo Red Willow – Mingo 345kV


2/12/2014 20:55 2/12/2014 22:00 3

3/05/2014 22:00 3/06/2014 07:50 5

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• Used to control high North‐South flows out of Nebraska into Kansas

Heavy post contingent loading on Knoll – N. Hays 115kV ftlo Post Rock – S. Hays 230kV

Multiple constraints with heavy post contingent loading including the Mingo 345/115kV transformer

Proxy (FG 18982) used to maintain North‐South loading across system to acceptable levels

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FG 18982 Axtell – Post Rock 345kV ftlo Red Willow – Mingo 345kV

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Axtell

Post Rock

Mingo

Red Willow

Knoll-N.Hays

Monitored Element

Proxy Element

FG 18982 Axtell – Postrock 345kV ftlo Red Willow – Mingo 345kV

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FG 6126 Sub 1226 – Tekamah 161kV ftlo Ft. Calhoun – Raun 345kV


2/12/2014 10:35 2/12/2014 19:00 5

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• FG 20005 Sub 1226 – Tekamah 161kV ftlo NW 68th & Holdridge – Columbus East 345kV

• Ft. Calhoun – Raun 345kV line was out

• Proxy used to control Real‐time and Post Contingent loading on Sub 1226 – Tekamah 161kV while temporary FG 20005 was being built

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17

Ft. Calhoun

Raun

Tekamah

Sub 1226Monitored Element

Proxy Element

Outage Element

NW 68th & Holdridge

Columbus

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NERC ORS Meeting 5/6/2014Phil Hart AECI

1

2

Presentation 2

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3

Ameren

AECI

ITCAECI AmerenAmeren

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June 2012•Load Shed Request issued to AECI for Loading in the Palmyra Area

July 2012•Permanent Flowgates for the Palmyra Transformer added and coordinated with MISO and SPP

July 2013•Additional Flowgates coordinated with MISO for Market Flow Reporting

August 2013•Five TLRs on the Palmyra Flowgate

•Each event became increasingly difficult

January 2014•MME Flowgate Accepted and Passed for Coordination

•Flowgate included in Palmyra Op-Guide

February 2014•6 TLRs on the Palmyra Flowgate

March 2014•Flowgate 2658 begins Reporting Market Flow

April 2014•MISO terminated reporting of market flow on FG2658

May 2014•Palmyra Transformer returns to service, TLR issued 5/5/2014

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Weather

Load

Outages

AECI 2014 Peak

6

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ITC

427 MVA

-33 MVA 62 MVA 256 MVA 141 MVA

-9% 17% 70% 38%

115% 02/27/2014 10:06 AM

345 kV

161 kV

AMRN AMRNAECI

7

370 MW Rating

Net MISO Market Flow391MW

>5% Impacts: ‐47 MW<5% Impacts: 391 MW

106%

2/27/2013Flowgate 1030: Palmyra 345/161 kV XFMR FLO Adair ‐ Thomas Hill 161 kV

MISO Market Flow Available for Curtailment

‐12 MW

12%

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2/15/2014 1030 Palmyra 345/161 kV XFMR FLO Adair ‐ Thomas Hill 161 kV 421.20 114% ‐12.2 ‐3%

9:22:52 1031 Palmyra 345/161 kV XFMR FLO Hills ‐ Sub T ‐ Louisa 345 kV 382.10 103% ‐11.1 ‐3%

2/24/2014 1030 Palmyra 345/161 kV XFMR FLO Adair ‐ Thomas Hill 161 kV 366.10 99% 34.1 9%


2/27/2014 1030 Palmyra 345/161 kV XFMR FLO Adair ‐ Thomas Hill 161 kV 391.40 106% ‐46.9 ‐13%


Date FGID FlowgateNet Market Flow

0% 5%

1030 Palmyra 345/161 kV XFMR FLO Adair ‐ Thomas Hill 161 kV 204.45 55.26% ‐24.81 ‐6.70%

1031 Palmyra 345/161 kV XFMR FLO Hills ‐ Sub T ‐ Louisa 345 kV 293.68 79.37% 9.20 2.49%

FGID Flowgate

Averages over 12 Events

0 5

9

TLR Process w/Single Element Flowgates

TLR Process w/Multiple Element Flowgates

Op Guide

Local Generation

10

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Palmyra is very sensitive to large system transfers

Current tools have not been effective to mitigate congestion

AECI has made a full effort to improve congestion management, however assistance is needed.◦ Recommend MISO reinstate reporting market flows

on FG#2658

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12

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Element Limit Type 104F 95F 86F 77F 68F 50F 32F

Palmyra 345/161kV XF *

Continuous 336 336 336 336 336 386 386Short Term (120 Minute, with pre-loading of 235 MVA)

399 415 430 443 454 454 454

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AMEREN 345 Path

Spencer Creek –

Palmyra – Sub T

161 Path

Thomas Hill ‐ Adair –

Appanoose

AECI 161 Path

Enon – Ethlyn

AECI 161 Path

Palmyra – Novelty – Adair

ITC 161 Path

Palmyra ‐ Viele

AMEREN 161 Path

Palmyra – Peno Creek

AMEREN 161 Path

Palmyra – North

Marblehead

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15

1030: Palmyra 345/161 kV XFMR FLO Adair - Thomas Hill 161 kV

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1031: Palmyra 345/161 kV XFMR FLO Hills - Sub T - Louisa 345 kV

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2658: Palmyra 345/161 kV XFMR and Thomas Hill – Adair FLO Hills – Sub T – Louisa

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427 – 370 MVA = 57 MW of required relief

Thomas Hill = 1200 MW @ 2.4% GSF

57/.024 = 50,000 MW

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RELIABILITY | ACCOUNTABILITY1

– Emergency Operations


• The EOP Standard Drafting Team (SDT) was charged withresponding to a Standard Authorization Request (SAR) toimplement the changes identified by the EOP Five‐Year ReviewTeam (FYRT), the Independent Experts Review Project report,and FERC directives as related to EOP‐001‐2.1b, EOP‐002‐3.1and EOP‐003‐2.

• The EOP SDT posted proposed EOP‐011‐1 for an informalcomment period that closed on April 28 so industry couldreview and help guide the current body of work.

EOP-011-1 – Emergency Operations

Presentation 3

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• High‐level summary:

The current EOP‐001‐2.1b, EOP‐002‐3.1, and EOP‐003‐2 and their associated attachments were consolidated into a single standard, EOP‐011‐1, or incorporated into Project 2008‐02 UVLS (Requirements R2, R4 and R7 in EOP‐003‐2).

In EOP‐001‐2.1b, the list of items in Attachment 1 were moved to Requirements R1 and R2 of EOP‐011‐1.

Reliability Coordinator approval of Emergency Operating Plans has been added to the standard.

Procedures, processes, or strategies that are to be included in the Emergency Operations Plan have been specified as to the Balancing Authority or Transmission Operator as directed by FERC.

EOP-011-1 – Emergency Operations


• An informal comment period for EOP‐011‐1 was open until Friday, April 28.

• The EOP SDT is meeting May 13–15 to review comments and further develop the EOP‐011‐1 standard.

• EOP‐011‐1 is scheduled to be posted for the first formal comment period and ballot the week of June 12th.

• Submittal to the NERC Board of Trustees and subsequent regulatory filing is targeted for the end of 2014 or early 2015.

Key Milestones

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• These slides from the EOP and UVLS joint webinar are posted on NERC.com. Click on “Standards” and then “Webinars”.

• Please contact the respective NERC Standards Developers for more information or to schedule an outreach session, or to be added to a project’s email distribution list: Project 2009‐03 EOP: Laura Anderson at [email protected]

Project 2008‐02 UVLS: Erika Chanzes at [email protected]

Additional Information


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Physical Security Reliability StandardRobert RhodesORS MeetingMay 6-7, 2014


• Project Overview Standard overview

Reliability Standard Audit Workheet (RSAW) approach

• Review effort to‐date

• Draft Standard

Agenda

Presentation 4

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Name Entity

Susan Ivey (Chair) Exelon Corporation

Lou Oberski (Vice Chair) Dominion

John Breckenridge Kansas City Power & Light

Ross Johnson Capital Power

Kathleen Judge National Grid

Mike O’Neil Florida Power & Light / NextEra, Inc.

Stephen Pelcher Santee Cooper

John Pespisa Southern California Edison

Robert Rhodes Southwest Power Pool

Allan Wick Tri-State Generation and Transmission

Manho Yeung Pacific Gas and Electric Company

Standard Drafting Team


• At a Glance: The Top Items to Know about Proposed Reliability Standard CIP‐014‐1.

• The standard includes only those Transmission stations and Transmission substations (and associated primary control centers) that if rendered inoperable or damaged could result in widespread instability, uncontrolled separation, or Cascading within an Interconnection.

• Only a relatively small number of Transmission Owners and Transmission Operators will need to comply with the entire Standard.

• The Standards Committee (SC) approved waivers to shorten the initial comment/ballot period and the final ballot period.

Project Overview

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• “To identify and protect Transmission stations and Transmission substations, and their associated primary control centers, that if rendered inoperable or damaged as a result of a physical attack could result in widespread instability, uncontrolled separation, or Cascading within an Interconnection.”

• Drafted as Critical Infrastructure Protection (CIP) family of standards.

Purpose

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• The applicability of proposed CIP‐014‐1 starts with those Transmission Owners that own Transmission facilities that meet the bright line criteria in Reliability Standard CIP‐002‐5.1 for a “medium impact” rating.

• The SDT sought to ensure that entities could apply the same set of criteria to assist with identification of facilities under CIP Version 5 and proposed CIP‐014‐1.

• By application of the requirements, only certain Transmission Operators that are notified under the standard’s Requirement R3 have obligations under the standard.

Applicability


• The first three requirements of CIP‐014‐1 require Transmission Owners to: Perform risk assessments to identify those Transmission stations and Transmission substations that meet the “medium impact” criteria from CIP‐002‐5.1, and their associated primary control centers

Arrange for a third party verification (as directed in the order) of the identifications; and

Notify certain Transmission Operators of identified primary control centers that operationally control the identified and verified Transmission stations and Transmission substations.

The requirements provide the periodicity for satisfying these obligations. Only an entity that owns or operates one or more of the identified facilities has further obligations in Requirements R4 through R6. If an entity identifies a null set after applying Requirements R1 through R2, the rest of the standard does not apply.

Requirements R1-R3

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• The final three requirements of CIP‐014‐1 require: The evaluation of potential threats and vulnerabilities of a physical attack to the facilities identified and verified according to the earlier requirements,

The development and implementation of a security plan(s) designed in response to the evaluation, and

A third party review of the evaluation and security plan(s) (as directed in the order).

Requirements R4-R6


• RSAW team has provided an RSAW that was posted concurrently with the CIP‐014‐1 standard. RSAW team consists of 12 members from NERC and the Regional Entities.

• Team members attend technical conference and SDT meetings RSAW is reviewed with the SDT prior to posting

• Industry commented on the draft RSAW.

• Special notes included in RSAW providing guidance regarding third party verifications and reviews (see page 4 of RSAW).

CIP-014-1 RSAW Development

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• Note to Auditors Concerning Third Party Verifications and Reviews

• Requirements R2 and R6 prescribe, respectively, unaffiliated third party verifications for Requirement R1 and unaffiliated third party reviews for Requirements R4 and R5. Auditors are encouraged to rely on the verifications and reviews performed in cases where the verifying or reviewing entities are qualified, unaffiliated with the audited entity, and the scope of their verification or review is clear. The concept of reliance means using the work of others to avoid duplication of efforts and is consistent with recognized professional auditing standards, which are required for Compliance Audits per NERC’s Rules of Procedure.

CIP-014-1 RSAW


• Reliance in the context of this Reliability Standard means using the Requirement R2 verifications and Requirement R6 reviews to reduce audit risk and the related rigor of audit testing for Requirements R1, R4, and R5. However, in cases where the verifying or reviewing entity lacks the qualifications specified in Requirement R2 for verifications or Requirement R6 for reviewers, the required unaffiliation from the audited entity, or where the scope of the third party entity’s verification or review is unclear, auditors may need to apply audit testing of Requirements R1, R4, or R5.

CIP-014-1 RSAW

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• For this reason, the Evidence Requested and Compliance Assessment Approach Sections are still present in this RSAW for Requirements R1, R4, and R5. The intent is that those sections will also facilitate expectations for entities and their unaffiliated third party verifiers and reviewers, assist Electric Reliability Organization (ERO) auditors to understand the audit procedures applied by unaffiliated third party verifiers and reviewers, and provide transparency between ERO auditors and Industry, should circumstances require audit testing of Requirements R1, R4, or R5. Further, it is an objective of the ERO to have transparent Evidence Requests and Compliance Assessment Approaches for every enforceable standard, whether they are in audit scope or not.

CIP-014-1 RSAW


• Requirement R1 requires the Transmission Owner perform a risk assessment through transmission analysis to identify: Each transmission substation (existing and planned) that, if rendered inoperable or damaged, could result in instability, uncontrolled separation, or cascading within an Interconnection

Associated control centers

• Requirement R1 specifies that the assessment shall be conducted at least: Once every 30 months for a Transmission Owner that has identified in its previous risk assessment (as verified according to Requirement R2) one or more Transmission stations or Transmission substations…

At least once every 60 calendar months for a Transmission Owner that has not identified in its previous risk assessment (as verified according to Requirement R2) any Transmission stations or Transmission substations…

Requirement R1

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Requirement R1 - RSAW

The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the RSAW Developer’s Guide for more information.

(R1) Review entity’s process for determining Transmission stations/substations subject to identification in accordance with Requirement R1, including weighting described in Section 4.1.1.2.

(R1) Review entity’s risk assessment process to determine the Transmission stations/substations that if rendered inoperable or damaged could result in widespread instability, uncontrolled separation, or Cascading within an interconnection.

(R1) Ensure entity’s risk assessment process includes Transmission stations/substations planned in the next 24 months.

(R1) Ensure risk assessment(s) covers each Transmission station/substation meeting applicability described in Section 4.1.

(R1 Part 1.1) If applicable, review any prior risk assessments and verify whether or not Transmission stations/substations were identified.

(R1 Part 1.1) Review evidence that risk assessment was performed and verify that it occurred within the past 30 months where items were identified in the previous risk assessment and 60 months where no items were identified in the previous risk assessment.

Note to Auditor: Review entity’s answer to the above Question and if the auditor can verify the answer is ‘no,’ Requirements R3‐R6 do not apply and no further audit testing of Requirements R3‐R6 is necessary, unless the entity performs the Transmission Operator function for a station/substation meeting the criteria of Requirment R1, Part 1.2. The 24 month period referenced for Transmission stations/substations planned to be in service is as of the date of the risk assessment not the date of the audit. See above Note Concerning Third Party Verifications for important details regarding audit risk assessment and related rigor of audit procedures to be applied for this Requirement.


• Requirement R2 requires the Transmission Owner to have an unaffiliated third party verify the risk assessment performed under Requirement R1. The verification may occur concurrent with or after the risk assessment performed under Requirement R1.

• This requirement includes confidentiality provisions.

Requirement R2

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(R2) Review evidence of third party verification of the entity’s risk assessment and verify the following:

(R2 Part 2.1) The reviewing entity is registered in accordance with Part 2.1 or has transmission planning or analysis experience.

(R2 Part 2.2) Verification was completed within 90 calendar days of risk assessment.

(R2 Part 2.3) Verifying entity’s recommendations, if any, were used to modify the entity’s Requirement R1 identification or the technical basis for not modifying the Requirement R1 identification is documented within 60 calendar days of completion of the verification.

(R2 Part 2.4) Review non‐disclosure agreement (or other evidence) to verify procedures for protecting sensitive or confidential information between the entity and third party were implemented.

Note to Auditor See Guidelines and Technical Basis section of the standard and Rationale for Requirement R2 associated with the Standard for additional details regarding the term ‘unaffiliated.’ The third party verification may occur concurrent with or after the risk assessment performed under Requirement R1.


• Requirement R3 requires the Transmission Owner notify the Transmission Operator that operates the primary control center identified in Requirement R1 and verified under Requirement R2 of such identification.

Requirement R3

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(R3) For each applicable primary control center identified in Requirement R1 Part 1.2 not under the control of the entity’s registration, verify notification exists and contains the date of completion of Requirement R2.

(R3 Part 3.1) For each Transmission station/substation removed under Part 3.1, ensure the responsible Transmission Operator was notified of the removal within seven calendar days of removal from identification.

Note to Auditor: Note the entity’s response to the above Question. If auditor can verify the entity’s answer of ‘No,’ then Requirement R3 is not applicable and no further audit testing is required.


• Requirement R4 requires the Transmission Owner and Transmission Operator of identified facilities to conduct an evaluation of potential physical threats and vulnerabilities

• Evaluation must consider any unique characteristics of the facility, prior history or attack on similar facilities and intelligence or threat warnings.

Requirement R4

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(R4) Review evidence of evaluation and verify it considers the following:

(R4) Potential threats and vulnerabilities as described in Requirement R4.

(R4 Part 4.1) Unique characteristics as described in Requirement R4 Part 4.1.

(R4 Part 4.2) Prior history of attack on similar facilities taking into account the frequency, geographic proximity, and severity of past physical security related events.

(R4 Part 4.3) Intelligence or warnings as described in Part 4.3.

Note to Auditor: See above Note Concerning Third Party Verifications for important details regarding audit risk assessment and related rigor of audit procedures to be applied for this Requirement. Auditor should cross reference the Transmission stations/substations and primary control centers identified in the risk assessment performed under Requirement R1 to the evaluation prescribed in Requirement R4 to ensure it is complete.


• Requirement R5 requires the Transmission Owner and Transmission Operator develop and implement a documented security plan covering each identified facility within 120‐calendar days following completion of Requirement R2.

• The physical security plan is to include the following attributes: Resiliency or security measures designed collectively to deter, detect, delay, assess, communicate, and respond to potential physical threats and vulnerabilities identified during the evaluation conducted in Requirement R4.

Law enforcement contact and coordination information.

A timeline for executing the physical security enhancements and modifications specified in the physical security plan.

Provisions to evaluate evolving physical threats and their corresponding security measures.

Requirement R5

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(R5) Review evidence and verify the physical security plan(s) covers the Transmission stations/substations and primary controls identified in Requirements R1 and/or R2, and verify plan was developed within 120 calendar days following the completion of Requirement R2 and executed according to the timeline specified in the physical security plan(s). In addition, verify the plan includes the following attributes:

(R5 Part 5.1) Resiliency or security measures designed collectively to deter, detect, delay, assess, communicate, and respond to potential physical threats and vulnerabilities identified in the evaluation conducted in Requirement R4.

(R5 Part 5.2) Law enforcement contact and coordination information.

(R5 Part 5.3) A timeline for executing physical security enhancements and modifications specified in the physical security plan.

(R5 Part 5.4) Provisions to evaluate evolving physical threats, and their corresponding security measures in accordance with R5 Part 5.4

(R5) Verify implementation of physical security plan(s). See ‘Note to Auditor’ for details.

Note to Auditor: See above Note Concerning Third Party Verifications for important details regarding audit risk assessment and related rigor of audit procedures to be applied for this Requirement. Auditor should cross reference the Transmission stations/substations and primary control centers identified in the risk assessment performed under Requirement R1 to the evaluation prescribed in Requirement R4 and the security plan(s) prescribed in Requirement R5 to ensure the plan addresses vulnerabilities to physical attacks per the evaluation conducted in Requirement R4. Requirement R5 includes implementation of the security plan(s), which is not within the scope of the third party review described in Requirement R6. Auditors can gain reasonable assurance security plan(s) was/were implemented by determining if specific actions prescribed by the plan(s) have taken place within the timelines established by the plan(s). For example, if the plan calls for certain procedures to occur, then auditors could ask for evidence demonstrating the procedure has been implemented within the timeline established in the security plan. Also, if the plan calls for construction of a barrier, an auditor could verify evidence that such a barrier was constructed in accordance with the entity’s timeline. As auditors should obtain reasonable, not absolute, assurance


• Requirement R6 requires the Transmission Owner and Transmission Operator obtain a review of the threat evaluation (Requirement R4) and security plan (Requirement R5)

• Transmission Owner/Transmission Operator shall select an unaffiliated third party reviewer

• Reviewer may suggest revisions. Transmission Owner/Transmission Operator can either modify its evaluation or security plan(s) consistent with the recommendation or document its reasons for not modifying its evaluation or security plan(s).

• This requirement includes confidentiality provisions.

Requirement R6

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(R6) Review evidence and verify the physical security plan(s) and the Requirement R4 evaluation have been reviewed by an unaffiliated third party. Also, review evidence and verify the following:

(R6 Part 6.1) Reviewing party has the qualifications identified in Part 6.1.

(R6 Part 6.2) Review is dated within 90 calendar days of completion of the Requirement R5 security plan.

(R6 Part 6.3) Reviewing entity recommended changes to security plan(s) were made by entity or the reason(s) for not making the change(s) was/were documented within 60 calendar days of the completion of the unaffiliated third party review.

(R6 Part 6.4) Review non‐disclosure agreement (or other evidence) to verify procedures for protecting sensitive or confidential information between entity and third party were implemented.

Note to Auditor: The third party review may occur concurrent with or after the evaluation performed under Requirement R4 or the security plan develop under Requirement R5. See Guidelines and Technical Basis associated with the Standard for additional details related to qualifications of reviewing entities that may inform audited entities selection of a reviewing entity.


Confidentiality

• Physical Security Order, Paragraph 10:

• “…NERC should include in the Reliability Standards a procedure that will ensure confidential treatment of sensitive or confidential information but still allow for the Commission, NERC and the Regional Entities to review and inspect any information that is needed to ensure compliance with the Reliability Standards.”

• Addressed in Requirement R2, Part 2.4 and Requirement R6, Part 6.4.

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Confidentiality

• CIP‐014‐1, Section 1.4. Additional Compliance Information

• Confidentiality: To protect the confidentiality and sensitive nature of the evidence for demonstrating compliance with this standard, all evidence will be retained at the Transmission Owner’s and Transmission Operator’s facilities.


• Draft standard posted for 15‐day initial comment and 5‐day ballot April 9, 2014

• Industry webinars (3) during initial comment and ballot

• Standard received an 82% approval rating

• Based on comments received the SDT made only minor clarifying modifications

• Posted for 5‐day final ballot on May 1, 2014

• Final ballot outcome ???

• Next steps Board of Trustees adoption

Filing with FERC by June 5, 2014

Effort To-Date

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• The following slides contains specific requirements language.

• This language was developed and posted for a 5‐day final ballot on May 1, 2014.

CIP-014-1 Requirements


• R1. Each Transmission Owner shall perform an initial risk assessment and subsequent risk assessments of its Transmission stations and Transmission substations (existing and planned to be in service within 24 months) that meet the criteria specified in Applicability Section 4.1.1. The initial and subsequent risk assessments shall consist of a transmission analysis or transmission analyses designed to identify anythe Transmission station(s) and Transmission substation(s) that if rendered inoperable or damaged could result in widespread instability, uncontrolled separation, or Cascading within an Interconnection. [VRF: High; Time‐Horizon: Long‐term Planning]

Requirement R1

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1.1 Subsequent risk assessments shall be performed: At least once every 30 calendar months for a Transmission Owner that has identified in its previous risk assessment (as verified according to Requirement R2) one or more Transmission stations or Transmission substations that if rendered inoperable or damaged could result in widespread instability, uncontrolled separation, or Cascading within an Interconnection; or

At least once every 60 calendar months for a Transmission Owner that has not identified in its previous risk assessment (as verified according to Requirement R2) any Transmission stations or Transmission substations that if rendered inoperable or damaged could result in widespread instability, uncontrolled separation, or Cascading within an Interconnection.

Requirement R1


Requirement R1

1.2 The Transmission Owner shall identify the primary control center that operationally controls each Transmission station or Transmission substation identified in the Requirement R1 risk assessment.

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R2. Each Transmission Owner shall have an unaffiliated third party verify the risk assessment performed under Requirement R1. The verification may occur concurrent with or after the risk assessment performed under Requirement R1. [VRF: Medium; Time‐Horizon: Long‐term Planning]

2.1 Each Transmission Owner shall select an unaffiliated verifying entity that is either: A registered Planning Coordinator, Transmission Planner, or Reliability Coordinator; or

An entity that has transmission planning or analysis experience.

Requirement R2


2.2 The unaffiliated verifying entitythird party verfication shall either verify the Transmission Owner’s risk assessment performed under Requirement R1,or recommendwhich may include recommendations for the addition or deletion of a Transmission station(s) or Transmission substation(s). The Transmission Owner shall ensure the verification is completed within 90 calendar days following the completion of the Requirement R1 risk assessment.

2.3 If the unaffiliated verifying entity recommends that the Transmission Owner add a Transmission station(s) or Transmission substation(s) to, or remove a Transmission station(s) or Transmission substation(s) from, its identification under Requirement R1, the Transmission Owner shall either, within 60 calendar days of completion of the verification, for each recommended addition or removal of a Transmission station or Transmission substation: Modify its identification under Requirement R1 consistent with the recommendation; or

Document the technical basis for not modifying the identification in accordance with the recommendation.

Requirement R2

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Requirement R2

2.4 Each Transmission Owner shall implement procedures, such as the use of non‐disclosure agreements, for protecting sensitive or confidential information exchanged withmade available to the unaffiliated third party verifier and to protect or exempt sensitive or confidential information developed pursuant to this Reliability Standard from public disclosure. verifying entity.


Requirement R3

R3. For a primary control center(s) identified by the Transmission Owner according to Requirement R1, Part 1.2 and that a) operationally controls an identified Transmission station or Transmission substation verified according to Requirement R2 that, and b) is not under the operational control of the Transmission Owner,: the Transmission Owner shall, within seven calendar days following completion of Requirement R2, notify the Transmission Operator that has operational control of the primary control center of such identification and the date of completion of Requirement R2. [VRF: Lower; Time‐Horizon: Long‐term Planning]

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Requirement R3

3.1 If a Transmission station or Transmission substation previously identified under Requirement R1 and verified according to Requirement R2 is removed from the identification during a subsequent risk assessment performed according to Requirement R1 or a verification according to Requirement R2, then the Transmission Owner shall, within seven calendar days following the verification or the subsequent risk assessment, notify the Transmission Operator that has operational control of the primary control center of the removal.


Requirement R4

R4. Each Transmission Owner that owns or operatesidentified a Transmission station, Transmission substation, or a primary control center identified in Requirement R1 and verified according to Requirement R2, and each Transmission Operator notified by a Transmission Owner according to Requirement R3 that the Transmission Operator’s primary control center has operational control of an identified Transmission station or Transmission substation, shall conduct an evaluation of the potential threats and vulnerabilities of a physical attack to each of their respective Transmission station(s), Transmission substation(s), and primary control center(s) identified in Requirement R1 and verified according to Requirement R2. The evaluation shall consider the following: [VRF: Medium; Time‐Horizon: Operations Planning, Long‐term Planning]

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Requirement R4

4.1 Unique characteristics of the identified and verified Transmission station(s), Transmission substation(s), and primary control center(s);

4.2 Prior history orof attack on similar facilities taking into account the frequency, geographic proximity, and severity of past physical security related events; and

4.3 Intelligence or threat warnings received from sources such as law enforcement, the Electric Reliability Organization (ERO), the Electricity Sector Information Sharing and Analysis Center (ES‐ISAC), U.S. federal and/or Canadian governmental agencies, or their successors.


Requirement R5

R5. Each Transmission Owner that owns or has operational control ofidentified a Transmission station, Transmission substation, or primary control center identified in Requirement R1 and verified according to Requirement R2, and each Transmission Operator notified by a Transmission Owner according to Requirement R3 that the Transmission Operator’s primary control center has operational control of an identified Transmission station or Transmission substation, shall develop and implement a documented physical security plan(s) that covers their respective Transmission station(s), Transmission substation(s), and primary control center(s). The physical security plan(s) shall be developed within 120 calendar days following the completion of Requirement R2. and executed according to the timeline specified in the physical security plan(s). The physical security plan(s) shall include the following attributes: [VRF: High; Time‐Horizon: Long‐term Planning]

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Requirement R5

5.1 Resiliency or security measures designed collectively to deter, detect, delay, assess, communicate, and respond to potential physical threats and vulnerabilities based on the results ofidentified during the evaluation conducted in Requirement R4.

5.2 Law enforcement contact and coordination information.

5.3 A timeline for implementingexecuting the physical security enhancements and modifications specified in the physical security plan.

5.4 Provisions to evaluate evolving physical threats, and their corresponding security measures, to the Transmission station(s), Transmission substation(s), or primary control center(s).


Requirement R6

R6. Each Transmission Owner that owns or operatesidentified a Transmission station, Transmission substation, or primary control center identified in Requirement R1 and verified according to Requirement R2, and each Transmission Operator notified by a Transmission Owner according to Requirement R3 that the Transmission Operator’s primary control center has operational control of an identified Transmission station or Transmission substation, shall have an unaffiliated third party review the evaluation performed under Requirement R4 and the security plan(s) developed under Requirement R5. The review may occur concurrently with or after completion of the evaluation performed under Requirement R4 and the security plan development under Requirement R5. [VRF: Medium; Time‐Horizon: Long‐term Planning]

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Requirement R6

6.1 Each Transmission Owner and Transmission Operator shall select an unaffiliated third party reviewer from the following:

• 6.1.1 An entity or organization with electric industry physical security experience and whose review staff has at least one member who holds either a Certified Protection Professional (CPP) or Physical Security Professional (PSP) certification.

• 6.1.2 An entity or organization approved by the ERO.

• 6.1.3 A governmental agency with physical security expertise.

• 6.1.4 An entity or organization with demonstrated law enforcement, government, or military physical security expertise.


6.2 The Transmission Owner or Transmission Operator, respectively, shall ensure that the unaffiliated third party review is completed within 90 calendar days of completing the security plan(s) developed in Requirement R5. The unaffiliated third party review may, but is not required to, include recommended changes to the evaluation performed under Requirement R4 or the security plan(s) developed under Requirement R5.

6.3 If the unaffiliated reviewing entitythird party reviewer recommends changes to the evaluation performed under Requirement R4 or security plan(s) developed under Requirement R5, the Transmission Owner or Transmission Operator shall, within 60 calendar days of the completion of the unaffiliated third party review, for each recommendation: Modify its evaluation or security plan(s) consistent with the recommendation; or

Document the reason(s) for not modifying the evaluation or security plan(s) consistent with the recommendation.

Requirement R6

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Requirement R6

6.4 Each Transmission Owner and Transmission Operator shall implement procedures, such as the use of non‐disclosure agreements, for protecting sensitive or confidential information exchanged withmade available to the unaffiliated third party reviewerreviewing entity and to protect or exempt sensitive or confidential information developed pursuant to this Reliability Standard from public disclosure.

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Project 2014-03 UpdateTOP/IRO Reliability Standards NERC ORSMay 6, 2014


Agenda

• Background• SDT Roster• SDT Inputs• Issue Summary

• Impacted Standards

• Industry Role• Project Schedule• Questions

Presentation 5

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Background

• April 16, 2013 – NERC petition for approval of three revised TOP, four revised IRO standards

• November 21, 2013 ‐ FERC Notice of Proposed Rulemaking (NOPR) proposes to remand revised TOP and IRO standards

• December 20, 2013 – NERC motion to defer action on NOPR until January 31, 2015

• January 14, 2014 – FERC grants motion to defer action until January 15, 2015

• February 12, 2014 – Standards Committee appoints SDT for Project 2014‐03 Revisions to TOP/IRO Reliability Standards


SDT Roster

• Chair – Dave Souder, PJM

• Vice Chair – Andrew Pankratz, FP&L

• David Bueche, CenterPoint Energy

• Jim Case, Entergy

• Allen Klassen, Westar Energy

• Bruce Larsen, WE Energies

• Jason Marshall, ACES Power Marketing

• Bert Peters, Arizona Public Service Co.

• Robert Rhodes, SPP

• Eric Senkowicz, FRCC

• Kevin Sherd, MISO

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SDT Inputs

• Previous SDT Work

• FERC NOPR (November 21, 2013)

• Independent Experts Review Project

• Southwest Outage Recommendations

• Order 693 directives

• IRO Five Year Review Team

• SAR Comments

• Technical Conferences

• NERC OC IERP Gaps analysis


Issue Summary

• New Outage Coordination Standard

• SOL exceedance intent

• Real‐time Assessment every 30 minutes

• Incorporated “Operating Instruction” consistent with proposed COM‐002‐4

• Consolidation of standards: 5 existing TOP, 5 existing IRO, and 1 existing PER standard proposed for retirement

• Clean‐up of applicability: Transmission Operator/Balancing Authority responsibilities in TOP standards, Reliability Coordinator responsibilities in IRO standards

• Elimination of redundancy

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Impacted Standards

• Revised Standards:

TOP‐001‐3, TOP‐002‐4, TOP‐003‐3

IRO‐001‐4, IRO‐002‐4, IRO‐008‐2, IRO‐010‐2, IRO‐014‐3

PRC‐001‐3

• Retired Standards:

TOP‐004‐2, TOP‐005‐2a, TOP‐006‐3, TOP‐007‐0, TOP‐008‐1

IRO‐002‐4, IRO‐003‐2, IRO‐004‐2, IRO‐005‐3.1a, IRO‐015‐1, IRO‐016‐1

PER‐001‐1

• New Standard:

IRO‐017


Industry Role

• Thorough review of the many standards involved

There are many inter‐relationships here

• Specific comments

Suggested language changes

Technical rationales provided

Don’t duplicate comments and increase work for the SDT

• Participate in mid‐posting webinar to hear SDT intent and responses to questions

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Project Schedule

• 5/19 – 1st 45 day posting – combined comment and ballot

• 7/1 ‐ Comment period ends

• 8/6 ‐ 2nd 45 day posting – combined comment and ballot

• 9/19 ‐ Comment period ends

• 10/13 – Final 10 day ballot

• 11/12 ‐ Board approval

• 12/1 ‐ FERC filing


Website http://www.nerc.com/pa/Stand/Pages/Project‐2014‐03‐Revisions‐to‐TOP‐and‐IRO‐Standards.aspx

p-1 spp reliability ors 5 6 2014 final - nerc reliability... · 5/19/2014 2 fg 6009 cooper south...

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