FERC rendition of the electronically filed tariff records in Docket No.

Filing Data:

CID: C000038

Filing Title: Con Edison and O&R Transco Agreements Company Filing Identifier: 1170

Type of Filing Code:  10

Associated Filing Identifier:

Tariff Title: NYISO Agreements Tariff ID: 58

Payment Confirmation: N
Suspension Motion:

Tariff Record Data:

Record Content Description: Agreement No. 2288

Tariff Record Title: Tripartite NERC Cmplnc Agrmnt 2288, Con Edison, O&R, Transco Record Version Number: 0.0.0

Option Code: A

Tariff Record ID: 203

Tariff Record Collation Value: 8080800

Tariff Record Parent Identifier: 2

Proposed Date: 2016-05-27

Priority Order: 500

Record Change Type:  New
Record Content Type:  2
Associated Filing Identifier:

ATTACHMENT C

TRIPARTITE NERC COMPLIANCE AGREEMENT

Execution Copy

TRIPARTITE NERC COMPLIANCE AGREEMENT

THIS TRIPARTITE NERC COMPLIANCE AGREEMENT (as the same
may be amended in accordance with the terms hereof, this “Agreement”), dated as of May 24,
2016 (the “Effective Date”), is by and between CONSOLIDATED EDISON COMPANY OF
NEW YORK, INC., a New York corporation having its principal offices at 4 Irving Place, New
York, New York 10003 (“Con Edison”), ORANGE AND ROCKLAND UTILITIES, INC., a
New York corporation having its offices located at 1 Blue Hill Plaza, Pearl River, NY 10965
(“O&R”) and NEW YORK TRANSCO LLC, a New York limited liability company having its
principal offices at c/o Consolidated Edison Transmission, LLC, 4 Irving Place, New York, New
York 10003 (“Transco”; together with Con Edison and O&R,  the “Parties” and each, a
“Party”).

RECITALS

WHEREAS, on the date hereof Con Edison and Transco have entered into that
certain Indemnification and Reimbursement Agreement (the “Ramapo Agreement”), pursuant
to which (i) Con Edison has accepted responsibility as the registered Transmission Owner to
comply with all applicable reliability rules of North American Electric Reliability Corporation
(“NERC”) with respect to  certain attachment facilities and substation upgrade facilities
identified therein (the “Ramapo SUF”) and (ii) Transco has agreed to (a) indemnify Con Edison
from and against NERC assessed penalties and associated costs of defense resulting from any
failure of such compliance with respect to the Ramapo SUF, and (b) pay Con Edison   for all
operation and maintenance expenses allocable to the Ramapo SUF that are incurred by Con
Edison; and

WHEREAS, on the date hereof O&R and Transco have entered into that certain
Operations and Maintenance Agreement (the “O&M Agreement”), pursuant to which, among
other things, O&R has agreed to provide certain operation and maintenance services to Transco
with respect to the Transmission Facilities, Leased Site and Structural Improvements (each, as
defined therein) comprising all or part of the capital transmission project known as the “Second
Ramapo to Rock Tavern” project in exchange for payment therefore by Transco and, in
connection therewith, (i) O&R has accepted NERC compliance responsibility as the registered
Transmission Owner with respect to the Substation Upgrade Facilities (as defined therein)
(herein called the “Sugarloaf SUF”) and (i) Transco has (a) accepted NERC compliance

responsibility as the registered Transmission Owner with respect to the northern portion of the Feeder 76 transmission line running from the Rock Tavern substation to the Sugarloaf substation owned by O&R (the “Northern Tier of Feeder 76”) and (b) agreed to indemnify O&R from and against NERC assessed penalties and associated costs of defense resulting from any failure of such compliance with respect to the Sugarloaf SUF, and pay the operation and maintenance expenses allocable to the Sugarloaf SUF that are incurred by O&R; and

WHEREAS, the Parties now desire to enter into this Agreement to memorialize,
among all three Parties, (i) Transco’s acceptance of compliance responsibility as the registered

Transmission Owner under all applicable reliability rules of NERC with respect to the Northern
Tier of Feeder 76; (ii) O&R’s acceptance of compliance responsibility as the registered

Transmission Owner under all applicable reliability rules of NERC with respect to the Sugarloaf SUF and the southern portion of the Feeder 76 transmission line running from the Sugarloaf substation owned by O&R to the Ramapo substation owned by Con Edison (the “Southern Tier of Feeder 76”); and (iii) Con Edison’s acceptance of NERC compliance responsibility as the registered Transmission Owner with respect to the Ramapo SUF.

NOW, THEREFORE, in consideration of the mutual covenants and agreements specified in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties, intending to be legally bound, hereby agree as follows:

1.  Term and Expiration Date:  This Agreement shall be effective as of the Effective
Date and shall terminate on the earlier of (i) the date upon which the Parties agree in writing to
terminate it or (ii) the date upon which the Sugarloaf SUF and the Ramapo SUF are no longer
subject to the  O&M Agreement and Ramapo Agreement, respectively. This Agreement shall
continue in effect after termination to the extent necessary to complete corrective mitigating
actions identified in any compliance monitoring process. The protections for Confidential
Information under Section 7 of this Agreement shall survive the termination of this Agreement.

2.  Transco’s Assumption of NERC Compliance Responsibility with Respect to the Northern Tier of Feeder 76.  Transco shall be solely responsible for complying, and hereby expressly agrees to assume sole responsibility to comply, with all NERC Standards applicable to the Northern Tier of Feeder 76. In furtherance of the foregoing, Transco, as it relates to the Northern Tier of Feeder 76, represents and warrants to, and covenants and agrees with, O&R and Con Edison that Transco has, on or prior to the date hereof, registered, and will at all times during the Term maintain such registration, as the Transmission Owner and will not de-register as the Transmission Owner, with NERC of the Northern Tier of Feeder 76.

3.  O&R’s Assumption of NERC Compliance Responsibility with respect to the
Sugarloaf SUF and the Southern Tier of Feeder 76. O&R shall be solely responsible for
complying, and hereby expressly agrees to assume sole responsibility to comply, with all NERC
Standards applicable to the Sugarloaf SUF and the Southern Tier of Feeder 76. In furtherance of
the foregoing, O&R, as it relates to the Sugarloaf SUF and the Southern Tier of Feeder 76,
represents and warrants to, and covenants and agrees with, Transco and Con Edison that O&R
will register prior to the energization of these assets, and will at all times during the Term
maintain  such  registration,  as  the  Transmission  Owner  and  will  not  de-register  as  the
Transmission Owner, with NERC of the Sugarloaf SUF and the Southern Tier of Feeder 76.
O&R further represents and warrants to and covenants and agrees with, Transco and Con Edison
that on the in-service date O&R will be in compliance with FAC-003-3 Vegetation Management
requirements with respect to the Northern Tier of Feeder 76, Southern Tier of Feeder 76, Leased
Site and Structural Improvements.

4.  Con Edison’s Assumption of NERC Compliance Responsibility with Respect to
the Ramapo SUF.  Con Edison shall be solely responsible for complying, and hereby expressly
agrees to assume sole responsibility to comply, with all NERC Standards applicable to the
Ramapo SUF. In furtherance of the foregoing, Con Edison, as it relates to the Ramapo SUF,

represents and warrants to, and covenants and agrees with, O&R and Transco that Con Edison has, on or prior to the date hereof, registered, and will at all times during the Term maintain such registration, as the Transmission Owner and will not de-register as the Transmission Owner, with NERC of the Ramapo SUF.  Con Edison further agrees to provide Transco, on Feeder 76’s inservice date, with the methodology used for initial rating calculations to ensure Feeder 76 is in compliance with NERC Standard FAC-008-3.

5.  Compliance Responsibility Matrix (Transmission Owner Function). The Parties have developed and agreed to the Compliance Responsibility Matrix (“CRM”), attached as Exhibit A. To address changes to NERC requirements affecting the Parties’ compliance responsibilities under this Agreement, the Parties will use best efforts to amend the CRM in a timely manner to address the new or modified reliability standard under NERC, and not delay such review and revision(s) in a manner that negatively impacts the ability of a Party to demonstrate compliance with NERC. The Parties shall collaboratively review the CRM when requested by one Party on written notice (which may be via email) to the other Parties, in order to address changes to NERC requirements.

6. Cooperation.

(a) The Parties agree to share information if necessary to support NERC compliance

in accordance with the CRM. Such information shall be provided in the timeframe necessary for a timely response to NERC.

(b)     In the event Transco receives a notice of possible violation (an “NPV”) from

NPCC associated with the Northern Tier of Feeder 76 or if Transco identifies a possible violation
associated with the Northern Tier of Feeder 76 for which it is self-reporting to NPCC, which
carries the possibility of financial penalties, Transco shall notify O&R and Con Edison of such
NPV in writing (which may be via email) as soon as practicable. O&R and Con Edison may, in
their sole discretion, participate in any investigation conducted by Transco to determine the
cause of the NPV.

(c)  In the event O&R receives a NPV from NPCC associated with the Sugarloaf SUF
or Southern Tier of Feeder 76 or if O&R identifies a possible violation associated with the
Sugarloaf SUF or Southern Tier of Feeder 76 for which it is self-reporting to NPCC, which
carries the possibility of financial penalties, O&R shall notify Transco and Con Edison of such
NPV in writing (which may be via email) as soon as practicable. Transco and Con Edison may,
in their sole discretion, participate in any investigation conducted by O&R to determine the
cause of the NPV.

(d)  In the event any Con Edison receives a NPV from NPCC associated with the Ramapo SUF or if Con Edison identifies a possible violation associated with the Ramapo SUF for which it is self-reporting to NPCC, which carries the possibility of financial penalties, Con Edison shall notify Transco and O&R of such NPV in writing (which may be via email) as soon as practicable. Transco and O&R may, in their sole discretion, participate in any investigation conducted by Con Edison to determine the cause of the NPV.  Indemnification.   This Agreement does not affect or modify in any way Transco’s obligation to indemnify Con Edison and O&R pursuant to the terms of the Ramapo Agreement and O&M Agreement, respectively, which obligations Transco hereby expressly affirms.

8. Confidentiality. The information obtained pursuant to this Agreement shall not be

disclosed to third parties except as agreed by the Parties and shall be maintained by the receiving
Party as confidential information. This includes any and all information (whether written, digital,
photos, diagrams, or in any other form) transmitted to the Party relating to the Northern Tier of
Feeder 76, Sugarloaf SUF, Southern Tier of Feeder 76 and Ramapo SUF, but does not include
information that is publicly available or otherwise developed, known or learned by a Party
without any obligation of confidentiality. The Parties shall only use the information for the
purpose of executing roles and responsibilities under this Agreement, except as expressly
authorized by the Party that provided the information. Each Party agrees to protect and preserve
the confidential and proprietary nature of all information it receives under this Agreement and to
use the same care and discretion to avoid disclosure of such information with respect to its own
confidential information. Each Party shall hold the information obtained in the strictest
confidence and not disclose any such information to any persons not previously authorized by
the other Party. Each Party shall immediately notify the other Party first verbally then to follow
up in writing anytime such information has been lost/misplaced or compromised. In the event a
Party is required by subpoena, court order or other similar process to disclose information
obtained from the other Party, it shall (unless prohibited from doing so by law or by court order)
provide the other Party with immediate written notice and documentation thereof, so that such
Party, at its sole cost, may seek a protective order or other appropriately remedy. Where
confidential information is required to demonstrate compliance with or to execute requirements
of the applicable NERC Reliability Standards, New York State Reliability Council Reliability
Rules, NPCC Directories, and NYISO manuals and procedures, the Parties agree that the
information may be provided to a regulator (FERC, NERC, and NPCC) or to the NYISO
following written notice to the Party who designated the information as confidential.  If
confidential information is submitted to FERC, NERC, NPCC, or NYISO for those compliance
purposes, the Party submitting such information to FERC, NERC, NPCC, or NYISO shall label
it as confidential and request confidential treatment for that information under any applicable
laws, regulations, tariff provisions, or other rules.  Upon the termination of this Agreement, or
upon the request of another Party, the Party to whom the information was provided must
immediately, at the other Party’s option: return the confidential information that was supplied to
it under this Agreement, or destroy the confidential information. Thereafter, the Party will certify
to the other Parties that all of the confidential information was returned, destroyed and deleted.

8.  Notices. Any notice given under this Agreement will be in writing and delivered
by personal service, by certified or registered first class mail, return receipt requested, by
nationally recognized overnight courier, or by facsimile or email with a copy, in the case of
facsimile or email, by first class mail, to the addresses specified on Exhibit B.  Either Party may
change the addresses provided on Exhibit B by notifying the other Party in the manner provided
above.  In the case of personal delivery, certified or registered first class mail, or nationally
recognized overnight courier, such transmittal will be deemed to have been received by the
recipient party on the date of such delivery. In the case of delivery via facsimile or electronic
mail, the transmittal shall be deemed to have been received on the date of transmission by
facsimile or electronic mail. Any notice received on a day that is not a Business Day, or after
5:00 p.m. (New York City time) on a Business Day, shall be deemed to be received on the next
following Business Day.

9.  Governing Law.  This Agreement shall be governed by and construed and

enforced in accordance with the internal laws of the State of New York, without giving effect to any choice of law rules or provisions that would cause the application of the laws of any jurisdiction other than the State of New York and without regard to any rule requiring construction against the Party drafting this Agreement.

10.  Waiver of Trial by Jury; Jurisdiction.  The Parties hereby waive trial by jury in
any action, proceeding or counterclaim brought by either of them against the other on any matter
arising out or related to this Agreement, and irrevocably submit to the jurisdiction of the courts
of the United States or of the State of New York located in the City and County of New York in
connection therewith.  Each Party waives any objection to venue in the State of New York.

11.  Assignments.  No Party may assign its rights or obligations under this Agreement
without the prior written consent of the other Parties hereto, which consent shall not be
unreasonably withheld, delayed or conditioned, except that the Parties may assign its rights or
obligations hereunder to a purchaser of all or substantially all of its assets who agrees in writing
to assume and be bound by the provisions of this Agreement, provided, however, that in the case
of an assignment by Transco, the proposed assignee is: (i) a reputable entity having a net worth
computed in accordance with generally accepted accounting principles which evidences, in Con
Edison’s and O&R’s reasonable discretion, the assignee’s financial ability to meet its obligations
hereunder, and (ii) not entitled, directly or indirectly, to diplomatic or sovereign immunity and
shall be subject to the service of process in, and the jurisdiction of the courts of, New York State,
and (iii) is qualified to become and  becomes a tenant under the Lease.

12.  Headings.  The descriptive headings used in this Agreement are for convenience of reference only and do not constitute part of this Agreement.

13.  Amendments; No Waiver.  This Agreement may not be amended, nor shall any waiver be effective, except by an instrument in writing signed by the Parties (or, in the case of a waiver, the Party against whom the waiver is sought to be effective). No course of dealing, or failure or delay by a Party in exercising any right provided for herein will be deemed a waiver of such right or any subsequent right hereunder.

14.  Entire Agreement.  This Agreement, together with the other documents and agreements referenced herein, constitute the entire agreement between the Parties concerning the subject matter hereof and supersede any and all prior agreements, written or oral, with respect to such subject matter.

15.  Severability. If any provision hereof is held by a court of competent jurisdiction to
be invalid or unenforceable, in whole or in part, then such determination shall not affect the
validity of the remaining portions hereof, which other portions shall continue in full force and
effect.

16.  No Third Party Beneficiaries. This Agreement is for the sole benefit of the Parties and their successors and permitted assigns and is not intended to and will not confer any rights or benefits to any other Person.

17.  Successors and Assigns.  The agreements, terms, covenants and conditions herein
shall be binding upon, and inure to the benefit of, the Parties and their respective successors and

permitted assigns.

18.  Counterparts.  This Agreement may be executed in one or more counterparts (including by facsimile or electronic transmission), each of which shall be an original and all of which, taken together, shall constitute one and the same instrument.

19.  Relationship of the Parties. This Agreement shall not be deemed to create any

partnership, agency, joint venture or trust, or to authorize any Party to act as agent, servant or employee of the other. The Parties are independent contractors. No Party shall have the power to bind the other without its express written consent.

Signature Page Follows

EXHIBIT A

COMPLIANCE MATRIX

7/19/2016

Con Edison - ORU - Transco NERC Compliance Matrix: Feeder 76 Legend:

x = has compliance responsibility

None = entity has no compliance responsibility; compliance maintained by other entity or entities N/A = requirement is not applicable to entity's asset(s)

Require Con Edison Transco ORU

Standard ment Text of Requirement

Number SS Eqpt - Ramapo SUF Feeder 76 North Feeder 76 - South SS Eqpt - Sugarloaf Transformer - Sugarloaf

Each Responsible Entity shall implement a process that considers each of the following assets for purposes of parts 1.1 through 1.3:
 i.Control Centers and backup Control Centers;

ii.Transmission stations and substations; iii.Generation resources;

iv.Systems and facilities critical to system restoration,  including
Blackstart Resources and Cranking Paths and initial switching
requirements;

CIP-002-5.1 R1.

v.Special Protection Systems that support the reliable operation of the Bulk Electric System; and

vi.For Distribution Providers, Protection Systems specified in Applicability section

1.1 Identify each of the high impact BES Cyber Systems, if any, at each asset

1.2 identify each of the medium impact BES Cyber Systems, if any, at each asset; and

1.3 Identify each asset that contains a low impact BES Cyber System,
if any

x

N/A

N/A

x

x

The Responsible Entity shall:

2.1 Review the identifications in Requirement R1 and its parts (and
update them if there are changes identified) at least once every 15

CIP-002-5.1 R2.

calendar months, even if it has no identified items in Requirement R1,

2.2 Have its CIP Senior Manager or delegate approve the
identifications required by Requirement R1 at least once every 15
calendar months, even if it has no  identified items in Requirement R1.

x

N/A

N/A

x

x

Each Responsible Entity, for its high impact and medium impact BES
Cyber Systems, shall review and obtain CIP Senior Manager approval
at least once every 15 calendar months for one or more documented
cyber security policies that collectively address the following topics:

1.1 Personnel & training (CIP-004);

1.2 Electronic Security Perimeters (CIP-005) including Interactive Remote Access;

CIP-003-5 R1.

1.3 Physical security of BES Cyber Systems (CIP-006);

1.4 System security management (CIP-007);

1.5 Incident reporting and response planning (CIP-008);

1.6 Recovery plans for BES Cyber Systems (CIP-009);

1.7 Configuration change management and vulnerability assessments (CIP-010);

1.8 Information protection (CIP-011); and

1.9 Declaring and responding to CIP Exceptional Circumstances.

x

N/A

N/A

x

x

Each Responsible Entity for its assets identified in CIP-002-5,

Requirement R1, Part R1.3, shall implement, in a manner that

identifies, assesses, and corrects deficiencies, one or more

documented cyber security policies that collectively address the

following topics, and review and obtain CIP Senior Manager approval

CIP-003-5 R2.

CIP-003-5 R3.

for those policies at least once every 15 calendar months:

2.1 Cyber security awareness;

2.2 Physical security controls;

2.3 Electronic access controls for external routable protocol connections and Dial-up Connectivity; and

2.4 Incident response to a Cyber Security Incident.

Each Responsible Entity shall identify a CIP Senior Manager by name and document any change within 30 calendar days of the change.

x

x

N/A

N/A

N/A

N/A

x

x

x

x

The Responsible Entity shall implement, in a manner that identifies,
assesses, and corrects deficiencies, a documented process to
delegate authority, unless no delegations are used. Where allowed by
the CIP Standards, the CIP Senior Manager may delegate authority
for specific actions to a delegate or delegates. These delegations shall

CIP-003-5 R4.

be documented, including the name or title of the delegate, the
specific actions delegated, and the date of the delegation; approved by the CIP Senior Manager; and updated within 30 days of any change to the delegation. Delegation changes do not need to be reinstated with a change to the delegator.

x

N/A

N/A

x

x

Each Responsible Entity shall implement one or more documented

CIP-004-5.1 R1.

processes that collectively include each of the applicable requirement parts in CIP‐004‐5 Table R1 - Security Awareness Program.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies, assesses, and corrects deficiencies, a cyber security training

CIP-004-5.1 R2.

program(s) appropriate to individual roles, functions, or responsibilities that collectively includes each of the applicable requirement parts in CIP‐004‐5 Table R2 - Cyber Security Training Program.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies, assesses, and corrects deficiencies, one or more documented

CIP-004-5.1 R3.

personnel risk assessment programs to attain and retain authorized
electronic or authorized unescorted physical access to BES Cyber
Systems that collectively include each of the applicable requirement
parts in CIP‐004‐5 Table R3 - Personnel Risk Assessment Program.

x

N/A

N/A

x

x

1 of 11

7/19/2016

Each Responsible Entity shall implement, in a manner that identifies,
assesses, and corrects deficiencies, one or more documented access

CIP-004-5.1 R4.

management programs that collectively include each of the applicable requirement parts in CIP‐004‐5 Table R4 - Access Management

Program.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-004-5.1 R5.

assesses, and corrects deficiencies, one or more documented access revocation programs that collectively include each of the applicable

requirement parts in CIP‐004‐5 Table R5 - Access Revocation.

x

N/A

N/A

x

x

Each Responsible Entity shall implement one or more documented

CIP-005-5 R1.

processes that collectively include each of the applicable requirement parts in CIP-005-5 Table R1 - Electronic Security Perimeter.

x

N/A

N/A

x

x

Each Responsible Entity allowing Interactive Remote Access to BES
Cyber Systems shall implement one or more documented processes

CIP-005-5 R2.

that collectively include the applicable requirement parts, where technically feasible, in CIP-005-5 Table R2 - Interactive Remote Access Management.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-006-5 R1.

assesses, and corrects deficiencies, one or more documented
physical security plans that collectively include all of the applicable
requirement parts in CIP-006-5 Table R1 - Physical Security Plan.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-006-5 R2.

assesses, and corrects deficiencies, one or more documented visitor control programs that include each of the applicable requirement parts in CIP-006-5 Table R2 - Visitor Control Program.

x

N/A

N/A

x

x

Each Responsible Entity shall implement one or more documented

CIP-006-5 R3.

Physical Access Control System maintenance and testing programs that collectively include each of the applicable requirement parts in CIP-006-5 Table R3 - Maintenance and Testing Program.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-007-5 R1.

assesses, and corrects deficiencies, one or more documented processes that collectively include each of the applicable requirement parts in CIP-007-5 Table R1 - Ports and Services.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-007-5 R2.

assesses, and corrects deficiencies, one or more documented processes that collectively include each of the applicable requirement parts in CIP-007-5 Table R2 - Security Patch Management.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-007-5 R3.

assesses, and corrects deficiencies, one or more documented processes that collectively include each of the applicable requirement parts in CIP-007-5 Table R3 - Malicious Code Prevention.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-007-5 R4.

assesses, and corrects deficiencies, one or more documented processes that collectively include each of the applicable requirement parts in CIP-007-5 Table R4 - Security Event Monitoring.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-007-5 R5.

assesses, and corrects deficiencies, one or more documented processes that collectively include each of the applicable requirement parts in CIP-007-5 Table R5 - System Access Controls.

x

N/A

N/A

x

x

Each Responsible Entity shall document one or more Cyber Security

CIP-008-5 R1.

Incident response plan(s) that collectively include each of the applicable requirement parts in CIP-008-5 Table R1 - Cyber Security Incident Response Plan Specifications.

x

N/A

N/A

x

x

Each Responsible Entity shall implement each of its documented

CIP-008-5 R2.

CIP-008-5 R3.

Cyber Security Incident response plans to collectively include each of the applicable requirement parts in CIP-008-5 Table R2 - Cyber

Security Incident Response Plan Implementation and Testing.

Each Responsible Entity shall maintain each of its Cyber Security Incident response plans according to each of the applicable

requirement parts in CIP-008-5 Table R3 - Cyber Security Incident Response Plan Review, Update, and Communication.

x

x

N/A

N/A

N/A

N/A

x

x

x

x

Each Responsible Entity shall have one or more documented

CIP-009-5 R1.

recovery plans that collectively include each of the applicable requirement parts in CIP-009-5 Table R1 - Recovery Plan Specifications.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-009-5 R2.

assesses, and corrects deficiencies, its documented recovery plan(s) to collectively include each of the applicable requirement parts in CIP-
009-5 Table R2 - Recovery Plan Implementation and Testing.

x

N/A

N/A

x

x

Each Responsible Entity shall maintain each of its recovery plans in

CIP-009-5 R3.

accordance with each of the applicable requirement parts in CIP-009-

5 Table R3 - Recovery Plan Review, Update and Communication.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies,

CIP-010-1 R1.

assesses, and corrects deficiencies, one or more documented
processes that collectively include each of the applicable requirement
parts in CIP‐010‐1 Table R1 - Configuration Change Management.

x

N/A

N/A

x

x

2 of 11

7/19/2016

Each Responsible Entity shall implement, in a manner that identifies,

CIP-010-1 R2.

assesses, and corrects deficiencies, one or more documented processes that collectively include each of the applicable requirement parts in CIP‐010‐1 Table R2 - Configuration Monitoring.

x

N/A

N/A

x

x

Each Responsible Entity shall implement one or more documented

CIP-010-1 R3.

processes that collectively include each of the applicable requirement parts in CIP‐010‐1 Table R3- Vulnerability Assessments.

x

N/A

N/A

x

x

Each Responsible Entity shall implement, in a manner that identifies, assesses, and corrects deficiencies, one or

CIP-011-1 R1.

more documented information protection program(s) that collectively includes each of the applicable requirement parts in CIP‐ 011‐1 Table R1 - Information Protection.

x

N/A

N/A

x

x

Each Responsible Entity shall implement one or more documented

CIP-011-1 R2.

processes that collectively include the applicable requirement parts in CIP‐011‐1 Table R2 - BES Cyber Asset Reuse and Disposal.

x

N/A

N/A

x

x

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

CIP-014-2 R1

4.1.1. The initial and subsequent risk assessments shall consist of a
transmission analysis or transmission analyses designed to identify
the Transmission station(s) and Transmission substation(s) that if

rendered inoperable or damaged could result in instability, uncontrolled separation, or Cascading within an Interconnection.

x

N/A

N/A

x

x

Each Transmission Owner shall have an unaffiliated third party verify

CIP-014-2 R2

the risk assessment performed under Requirement R1. The verification may occur concurrent with or after the risk assessment performed under Requirement R1.

x

N/A

N/A

x

x

For a primary control center(s) identified by the Transmission Owner
according to Requirement R1, Part 1.2 that a) operationally controls
an identified Transmission station or Transmission substation verified
according to Requirement R2, and b) is not under the operational

CIP-014-2 R3

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.

N/A

N/A

N/A

x

x

Each Transmission Owner that identified a Transmission station,

Transmission substation, or a primary control center in Requirement
R1 and verified according to Requirement R2, and each Transmission
Operator notified by a Transmission Owner according to Requirement

CIP-014-2 R4

R3, 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.

x

N/A

N/A

x

x

Each Transmission Owner that identified a Transmission station,

Transmission substation, or primary control center in Requirement R1
and verified according to Requirement R2, and each Transmission
Operator notified by a Transmission Owner according to Requirement

CIP-014-2 R5

R3, 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).

x

N/A

N/A

x

x

Each Transmission Owner that identified a Transmission station,

Transmission substation, or primary control center in Requirement R1
and verified according to Requirement R2, and each Transmission
Operator notified by a Transmission Owner according to Requirement

CIP-014-2 R6.

R3, 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.

x

N/A

N/A

x

x

Each Responsible Entity shall have an event reporting Operating Plan in accordance with EOP-004-2 Attachment 1 that includes the

EOP-004-2 R1.

protocol(s) for reporting to the Electric Reliability Organization and other organizations (e.g., the Regional Entity, company personnel, the Responsible Entity’s Reliability Coordinator, law enforcement, or
governmental authority).

x

x

x

x

x

Each Responsible Entity shall report events per their Operating Plan
within 24 hours of recognition of meeting an event type threshold for

EOP-004-2 R2. reporting or by the end of the next business day if the event occurs on x x x x x

a weekend (which is recognized to be 4 PM local time on Friday to 8 AM Monday local time).

Each Responsible Entity shall validate all contact information

EOP-004-2 R3. contained in the Operating Plan pursuant to Requirement R1 each x x x x x

calendar year.

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Each Transmission Operator, each applicable Transmission Owner,
and each applicable Distribution Provider shall provide a minimum of

EOP-005-2 R11

two hours of System restoration training every two calendar years to their field switching personnel identified as performingunique tasks associated with the Transmission Operator’s restoration plan that are outside of their normal tasks.

x

x

x

x

x

Each Transmission Owner shall document Facility interconnection

requirements, update them as needed, and make them available upon request. Each Transmission Owner’s Facility interconnection

FAC-001-2 R1. requirements shall address interconnection requirements for: x x x x x

1.1. generation Facilities;

1.2. transmission Facilities; and

1.3. end-user Facilities.

Each Transmission Owner shall address the following items in its Facility interconnection requirements:

FAC-001-2 R3.

R3.1.1. Procedures for coordinated joint studies of new facilities and their impacts on the interconnected transmission systems.

R3.1.2. Procedures for notification of new or modified facilities to others (those responsible for the reliability of the interconnected transmission systems) as soon as feasible.

x

x

x

x

x

Each Transmission Owner, each Distribution Provider, and each LoadServing Entity seeking to interconnect new transmission Facilities or electricity end-user Facilities, or to materially modify existing

FAC-002-2 R3.

interconnections of transmission Facilities or electricity end-user Facilities, shall coordinate and cooperate on studies with its

Transmission Planner or Planning Coordinator, including but not
limited to the provision of data as described in R1, Parts 1.1-1.4

N/A

x

x

x

x

Each Transmission Owner shall coordinate and cooperate with its
Transmission Planner or Planning Coordinator on studies regarding

FAC-002-2 R4.

requested new or materially modified interconnections to its Facilities, including but not limited to the provision of data as described in R1, Parts 1.1-1.4

N/A

x

x

x

x

Each applicable Transmission Owner and applicable Generator Owner
shall manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) which are either an element of an IROL, or an
element of a Major WECC Transfer Path; operating within their Rating
and all Rated Electrical Operating Conditions of the types shown
below:

1. An encroachment into the MVCD as shown in FAC-003-Table 2,

FAC-003-3 R1

observed in Real-time, absent a Sustained Outage,5

2. An encroachment due to a fall-in from inside the ROW that caused a vegetation related Sustained Outage,6

3. An encroachment due to the blowing together of applicable lines and vegetation located inside the ROW that caused a vegetation-
related Sustained Outage7,

4. An encroachment due to vegetation growth into the MVCD that caused a vegetation-related Sustained Outage.8

None

x

x

N/A

N/A

Each applicable Transmission Owner and applicable Generator Owner
shall manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) which are not either an element of an IROL, or an
element of a Major WECC Transfer Path; operating within its Rating
and all Rated Electrical Operating Conditions of the types shown
below9 [Violation Risk Factor: High] [Time Horizon: Real-time]:

1. An encroachment into the MVCD, observed in Real-time, absent a

FAC-003-3 R2

Sustained Outage,

2. An encroachment due to a fall-in from inside the ROW that caused a vegetation related Sustained Outage,11

3. An encroachment due to blowing together of applicable lines and vegetation located inside the ROW that caused a vegetation-related Sustained Outage,12

4. An encroachment due to vegetation growth into the line MVCD that caused a vegetation-related Sustained Outage13

None

x

x

N/A

N/A

Each applicable Transmission Owner and applicable Generator Owner
shall have documented maintenance strategies or procedures or
processes or specifications it uses to prevent the encroachment of
vegetation into the MVCD of its applicable lines that accounts for the

FAC-003-3 R3

following:

3.1 Movement of applicable line conductors under their Rating and all Rated Electrical Operating Conditions;

3.2 Inter-relationships between vegetation growth rates, vegetation control methods, and inspection frequency.

None

x

x

N/A

N/A

Each applicable Transmission Owner and applicable Generator
Owner, without any intentional time delay, shall notify the control
center holding switching authority for the associated applicable line

FAC-003-3 R4

when the applicable Transmission Owner and applicable Generator
Owner has confirmed the existence of a vegetation condition that is
likely to

cause a Fault at any moment

None

x

x

N/A

N/A

W hen a applicable Transmission Owner and applicable Generator
Owner is constrained from performing vegetation work on an
applicable line operating within its Rating and all Rated Electrical

FAC-003-3 R5

Operating Conditions, and the constraint may lead to a vegetation encroachment into the MVCD prior to the implementation of the next annual work plan, then the applicable Transmission Owner or

applicable Generator Owner shall take corrective action to ensure continued vegetation management to prevent encroachments.

None

x

x

N/A

N/A

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Each applicable Transmission Owner and applicable Generator Owner shall perform a Vegetation Inspection of 100% of its applicable

FAC-003-3 R6.

transmission lines (measured in units of choice - circuit, pole line, line miles or kilometers, etc.) at least once per calendar year and with no more than 18 calendar months between inspections on the same

ROW.

None

x

x

N/A

N/A

Each applicable Transmission Owner and applicable Generator Owner shall complete 100% of its annual vegetation work plan of applicable lines to ensure no vegetation encroachments occur within the MVCD. Modifications to the work plan in response to

changing conditions or to findings from vegetation inspections may be
made (provided they do not allow encroachment of vegetation into the
MVCD) and must be documented. The percent completed calculation
is based on the number of units actually completed divided by the
number of units in the final amended plan (measured in units of choice

- circuit, pole line, line miles or kilometers, etc.) Examples of reasons

FAC-003-3 R7

for modification to annual plan may include:

1. Change in expected growth rate/ environmental factors

2.  Circumstances that are beyond the control of an applicable Transmission Owner orapplicable Generator Owner

3.  Rescheduling work between growing seasons

4.  Crew or contractor availability/ Mutual assistance agreements

5.  Identified unanticipated high priority work

6.  Weather conditions/Accessibility

7. Permitting delays

8.  Land ownership changes/Change in land use by the landowner

9.  Emerging technologies

None

x

x

N/A

N/A

Each Transmission Owner shall have a documented methodology for
determining Facility Ratings (Facility Ratings methodology) of its solely

FAC-008-3 R3.

FAC-008-3 R4.

FAC-008-3 R5.

FAC-008-3 R6.

FAC-008-3 R8.

IRO-010-1a R3.

and jointly owned Facilities (except for those generating unit Facilities addressed in R1 and R2) that contains all of the following: [See

standard for methodology requirements]

Each Transmission Owner shall make its Facility Ratings methodology and each Generator Owner shall each make its documentation for

determining its Facility Ratings and its Facility Ratings methodology available for inspection and technical review by those Reliability

Coordinators, Transmission Operators, Transmission Planners and
Planning Coordinators that have responsibility for the area in which the
associated Facilities are located, within 21 calendar days of receipt of

a request

If a Reliability Coordinator, Transmission Operator, Transmission
Planner or Planning Coordinator provides documented comments on
its technical review of a Transmission Owner’s Facility Ratings
methodology or Generator Owner’s documentation for determining its
Facility Ratings and its Facility Rating methodology, the Transmission
Owner or Generator Owner shall provide a response to that
commenting entity within 45 calendar days of receipt of those
comments.  The response shall indicate whether a change will be
made to the Facility Ratings methodology and, if no change will be
made to that Facility Ratings methodology  the reason why

Each Transmission Owner and Generator Owner shall have Facility Ratings for its solely and jointly owned Facilities that are consistent with the associated Facility Ratings methodology or documentation for determining its Facility Ratings.

Each Transmission Owner (and each Generator Owner subject to
Requirement R2) shall provide requested information as specified
below (for its solely and jointly owned Facilities that are existing
Facilities, new Facilities, modifications to existing Facilities and re-

ratings of existing Facilities) to its associated Reliability Coordinator(s), Planning Coordinator(s), Transmission Planner(s), Transmission

Owner(s) and Transmission Operator(s): [See standard for requirements of providing requested information ]

Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability relationship.

None

None

None

None

None

None

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

x

The Transmission Owners, Transmission Planners, Generator

Owners, and Resource Planners  (specified in the data requirements
and reporting procedures of MOD-011-0_R1) shall provide appropriate

MOD-010-0 R1.

equipment characteristics, system data, and existing and future Interchange Schedules in compliance with its respective

Interconnection Regional steady-state modeling and simulation data requirements and reporting procedures as defined in Reliability

Standard MOD-011-0_R 1.

None

x

x

x

x

The Transmission Owners, Transmission Planners, Generator

Owners, and Resource Planners  (specified in the data requirements
and reporting procedures of MOD-011-0_R1) shall provide this steady-

MOD-010-0 R2.

state modeling and simulation data to the Regional Reliability Organizations, NERC, and those entities specified within Reliability Standard MOD-011-0_R 1. If no schedule exists, then these entities shall provide the data on request (30 calendar days).

None

x

x

x

x

The Transmission Owners, Transmission Planners, Generator

Owners, and Resource Planners (specified in the data requirements

and reporting procedures of MOD-013-0_R1) shall provide appropriate

MOD-012-0 R1.

equipment characteristics and system data in compliance with the
respective Interconnection-wide Regional dynamics system modeling

and simulation data requirements and reporting procedures as defined in Reliability Standard MOD-013-0_R1.

N/A

N/A

x

x

x

The Transmission Owners, Transmission Planners, Generator

Owners, and Resource Planners (specified in the data requirements
and reporting procedures of MOD-013-0_R4) shall provide dynamics

MOD-012-0 R2.

system modeling and simulation data to its Regional Reliability
Organization(s), NERC, and those entities specified within the

applicable reporting procedures identified in Reliability Standard MOD-
013-0_R 1.  If no schedule exists, then these entities shall provide

data on request (30 calendar days).

N/A

N/A

x

x

x

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Each Balancing Authority, Generator Owner, Load Serving Entity,
Resource Planner, Transmission Owner, and Transmission Service
Provider shall provide steady-state, dynamics, and short circuit
modeling data to its Transmission Planner(s) and Planning

MOD-032-1 R2

Coordinator(s) according to the data requirements and reporting
procedures developed by its Planning Coordinator and Transmission
Planner in Requirement R1. For data that has not changed since the
last submission, a written confirmation that the data has not changed
is sufficient.

None

x

x

x

x

Upon receipt of written notification from its Planning Coordinator or
Transmission Planner regarding technical concerns with the data
submitted under Requirement R2, including the technical basis or
reason for the technical concerns, each notified Balancing Authority,
Generator Owner, Load Serving Entity, Resource Planner,
Transmission Owner, or Transmission Service Provider shall respond

MOD-032-1 R3

to the notifying Planning Coordinator or Transmission Planner as follows:

3.1. Provide either updated data or an explanation with a technical basis for maintaining the current data;

3.2. Provide the response within 90 calendar days of receipt, unless a longer time period is agreed upon by the notifying Planning

Coordinator or Transmission Planner.

None

x

x

x

x

The Nuclear Plant Generator Operator and the applicable

Transmission Entities shall have in effect one or more Agreements1

NUC-001-3 R2

that include mutually agreed to NPIRs and document how the Nuclear Plant Generator Operator and the applicable Transmission Entities

shall address and implement these NPIRs.

N/A

N/A

N/A

N/A

N/A

Per the Agreements developed in accordance with this standard, the

NUC-001-3 R3

applicable Transmission Entities shall incorporate the NPIRs into their
planning analyses of the electric system and shall communicate the
results of these analyses to the Nuclear Plant Generator Operator.

N/A

N/A

N/A

N/A

N/A

Per the Agreements developed in accordance with this standard, the applicable Transmission Entities shall:

4.1. Incorporate the NPIRs into their operating analyses of the electric

NUC-001-3 R4

system.

4.2. Operate the electric system to meet the NPIRs.

4.3. Inform the Nuclear Plant Generator Operator when the ability to
assess the operation of the electric system affecting NPIRs is lost.

N/A

N/A

N/A

N/A

N/A

Per the Agreements developed in accordance with this standard, the

NUC-001-3 R6.

applicable Transmission Entities and the Nuclear Plant Generator Operator shall coordinate outages and maintenance activities which affect the NPIRs.

N/A

N/A

N/A

N/A

N/A

Per the Agreements developed in accordance with this standard, the Nuclear Plant Generator Operator shall inform the applicable

NUC-001-3 R7.

Transmission Entities of actual or proposed changes to nuclear plant design (e.g., protective relay setpoints), configuration, operations,

limits, or capabilities that may impact the ability of the electric system to meet the NPIRs.

N/A

N/A

N/A

N/A

N/A

Per the Agreements developed in accordance with this standard, the
applicable Transmission Entities shall inform the Nuclear Plant

NUC-001-3 R8.

Generator Operator of actual or proposed changes to electric system design (e.g., protective relay setpoints), configuration, operations,

limits, or capabilities that may impact the ability of the electric system to meet the NPIRs.

N/A

N/A

N/A

N/A

N/A

The Nuclear Plant Generator Operator and the applicable

Transmission Entities shall include the following elements in aggregate within the Agreement(s) identified in R2.

1.  Where multiple Agreements with a single Transmission Entity are
put into effect, the R9 elements must be addressed in aggregate
within the Agreements; however, each Agreement does not have to
contain each element. The Nuclear Plant Generator Operator and the
Transmission Entity are responsible for ensuring all the R9 elements
are addressed in aggregate within the Agreements.

NUC-001-3 R9

2.  Where Agreements with multiple Transmission Entities are
required, the Nuclear Plant Generator Operator is responsible for

ensuring all the R9 elements are addressed in aggregate within the
Agreements with the Transmission Entities. The Agreements with
each Transmission Entity do not have to contain each element;

however, the Agreements with the multiple Transmission Entities, in the aggregate, must address all R9 elements. For each Agreement(s), the Nuclear Plant Generator Operator and the Transmission Entity are responsible to ensure the Agreement(s) contain(s) the

elements of R9 applicable to that Transmission Entity.

N/A

N/A

N/A

N/A

N/A

Each Transmission Owner and Generator Owner shall provide

Sequence of Event (SOE) recording capability by installing Sequence
of Event recorders or as part of another device, such as a Supervisory

PRC-002-NPCC-01 R1.

Control And Data Acquisition (SCADA) Remote Terminal Unit (RTU), a generator plant Digital (or Distributed) Control System (DCS) or part of Fault recording equipment. This capability shall: [See standard for requirements of SOE recording capability ]

x

None

None

x

x

Each Transmission Owner shall provide Fault recording capability for

PRC-002-NPCC-01 R2.

the following Elements at facilities where Fault recording equipment is
required to be installed as per R3: [See standard for list of elements ]

x

None

None

x

x

Each Transmission Owner shall have Fault recording capability that

PRC-002-NPCC-01 R3.

determines the Current Zero Time for loss of Bulk Electric System (BES) transmission Elements.

x

None

None

x

x

Each Transmission Owner and Generator Owner shall record for

PRC-002-NPCC-01 R5.

Faults, sufficient electrical quantities for each monitored Element to determine the following: [See standard for list ]

x

None

None

x

x

Each Transmission Owner and Generator Owner shall provide Fault

PRC-002-NPCC-01 R6.

recording with the following capabilities: [See standard for list of capabilities ]

x

None

None

x

x

6 of 11

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Each Transmission Owner and Generator Owner that receives a

request from the Reliability Coordinator to install a DDR shall acquire

PRC-002-NPCC-01 R13.

PRC-002-NPCC-01 R14.

and install the DDR in accordance with  R12.  Reliability Coordinators, Transmission Owners, and Generator Owners shall mutually agree on an implementation schedule

Each Transmission Owner and Generator Owner shall establish a maintenance and testing program for stand alone DME (equipment whose only purpose is disturbance monitoring) that includes: [See standard for list of inclusions ]

x

x

None

None

None

None

x

x

x

x

Each Reliability Coordinator, Transmission Owner and Generator

Owner shall share data within 30 days upon request.  Each Reliability

PRC-002-NPCC-01 R15.

Coordinator, Transmission Owner, and Generator Owner shall provide
recorded disturbance data from DMEs within 30 days of receipt of the
request in each of the following cases: [See standard for the two cases ]

x

None

None

x

x

Each Reliability Coordinator, Transmission Owner and Generator

PRC-002-NPCC-01 R16.

Owner shall submit the data files conforming to the following format requirements: [See standard for format requirements ]

x

None

None

x

x

Each Reliability Coordinator, Transmission Owner and Generator

PRC-002-NPCC-01 R17.

Owner shall maintain,  record and provide to the Regional Entity (RE), upon request, the following data on the DMEs installed to meet this standard: [See standard for types of data ]

x

None

None

x

x

The Transmission Owner and any Distribution Provider that owns a
transmission Protection System shall each analyze its transmission

PRC-004-2.1(i)a R1.

Protection System Misoperations and shall develop and implement a Corrective Action Plan to avoid future Misoperations of a similar nature according to the Regional Entity’s procedures

x

None

None

x

x

The Transmission Owner, any Distribution Provider that owns a

transmission Protection System, and the Generator Owner shall each
provide to its Regional Entity, documentation of its Misoperations
analyses and Corrective Action Plans according to the Regional

PRC-004-2.1(i)a R3.

Entity’s procedures.

• For Misoperations occurring on the Protection Systems of individual
dispersed power producing resources identified under Inclusion I4 of
the BES definition where the Misoperations affected an aggregate

nameplate rating of less than or equal to 75 MVA of BES facilities, this requirement does not apply

x

None

None

x

x

Each Transmission Owner, Generator Owner, and Distribution

PRC-005-2(i) R1.

Provider shall establish a Protection System Maintenance Program (PSMP) for its Protection Systems identified in Section 4.2. The PSMP shall:

x

None

N/A

x

x

Identify which maintenance method (time-based, performance-based
per PRC-005 Attachment A, or a combination) is used to address

PRC-005-2(i) R1.1.

each Protection System Component Type. All batteries associated
with the station dc supply Component Type of a Protection System
shall be included in a time-based program as described in Table 1-4
and Table 3.

x

None

N/A

x

x

Include the applicable monitored Component attributes applied to each
Protection System Component Type consistent with the maintenance

PRC-005-2(i) R1.2.

intervals specified in Tables 1-1 through 1-5, Table 2, and Table 3 where monitoring is used to extend the maintenance intervals beyond those specified for unmonitored Protection System Components

x

None

N/A

x

x

Each Transmission Owner, Generator Owner, and Distribution

PRC-005-2(i) R2.

Provider that uses performance-based maintenance intervals in its PSMP shall follow the procedure established in PRC-005 Attachment A to establish and maintain its performance-based intervals.

x

None

N/A

x

x

7 of 11

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Each Transmission Owner, Generator Owner, and Distribution
Provider that utilizes time-based maintenance program(s) shall

PRC-005-2(i) R3.

maintain its Protection System Components that are included within the time-based maintenance program in accordance with the minimum maintenance activities and maximum maintenance intervals

prescribed within Tables 1-1 through 1-5, Table 2, and Table 3.

x

None

N/A

x

x

Each Transmission Owner, Generator Owner, and Distribution

Provider that utilizes performance-based maintenance program(s) in

PRC-005-2(i) R4.

accordance with Requirement R2 shall implement and follow its PSMP for its Protection System Components that are included within the

performance-based program(s).

x

None

N/A

x

x

Each Transmission Owner, Generator Owner, and Distribution

PRC-005-2(i) R5.

Provider shall demonstrate efforts to correct identified Unresolved Maintenance Issues

x

None

N/A

x

x

Each Distribution Provider and Transmission Owner in the Eastern
Interconnectionportion of NPCC shall implement an automatic UFLS
program reflecting normal operating conditions excluding outages for
its Facilities based on frequency thresholds, total nominal operating
time and amounts specified in Attachment C, Tables 1 through 3, or

PRC-006-NPCC-01 R4

shall collectively implement by mutual agreement with one or more
Distribution Providers and Transmission Owners within the same
island identified in Requirement R1 and acting as a single entity,
provide an aggregated automatic UFLS program that sheds their

coincident peak aggregated net Load, based on frequency thresholds, total nominal operating time and amounts specified in Attachment C, Tables 1 through 3.

N/A

None

N/A

x

x

Each Distribution Provider or Transmission Owner that must arm its
load to trip on underfrequency in order to meet its requirements as
specified and by doing so exceeds the tolerances and/or deviates from
the number of stages and frequency set points of the UFLS program
as specified in the tables contained in Requirement R4 above, as
applicable depending on its total peak net Load shall:

5.1 Inform its Planning Coordinator of the need to exceed the stated tolerances or the number of stages as shown in UFLS Attachment C, Table 1 if applicable and

5.2 Provide its Planning Coordinator with a technical study that

PRC-006-NPCC-01 R5

demonstrates that the Distribution Providers or Transmission Owners specific deviations from the requirements of UFLS Attachment C,

Table 1 will not have a

significant adverse impact on the bulk power system.

5.3 Inform its Planning Coordinator of the need to exceed the stated tolerances of UFLS Attachment C, Table 2 or Table 3, and in the case of Attachment C, Table 2 only, the need to deviate from providing two stages of UFLS, if applicable, and

5.4 Provide its Planning Coordinator with an analysis demonstrating that no alternative load shedding solution is available that would allow the Distribution Provider or Transmission Owner to comply with UFLS Attachment C Table 2 or Attachment C Table 3.

N/A

None

N/A

x

x

Each Distribution Provider and Transmission Owner in the Québec Interconnection portion of NPCC shall implement an automatic UFLS program for its Facilities based on the frequency thresholds, slopes, total nominal operating time and amounts

PRC-006-NPCC-01 R6.

specified in Attachment C, Table 4 or shall collectively implement by mutual agreement with one or more Distribution Providers and

Transmission Owners within the same island, identified in
Requirement R1, an aggregated automatic UFLS program that sheds
Load based on the frequency thresholds, slopes, total nominal
operating time and amounts specified in Attachment C, Table 4.

N/A

None

N/A

x

x

Each Distribution Provider and Transmission Owner shall set each
underfrequency relay that is part of its region’s UFLS program with

PRC-006-NPCC-01 R7

the following minimum time delay:

7.1 Eastern Interconnection - 100 ms

7.2 Québec Interconnection - 200 ms

N/A

None

N/A

x

x

Each Distribution Provider and Transmission Owner shall implement

PRC-006-NPCC-01 R10

the inhibit threshold settings based on the notification provided by the Planning Coordinator in accordance with Requirement R9.

N/A

None

N/A

x

x

Each Distribution Provider and Transmission Owner shall develop and

PRC-006-NPCC-01 R11

submit an implementation plan within 90 days of the request from the Planning Coordinator for approval by the Planning Coordinator in

accordance with R9.

N/A

None

N/A

x

x

8 of 11

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Each Transmission Owner and Distribution Provider shall annually
provide documentation, with no more than 15 months between
updates, to its Planning Coordinator of the actual net Load that would

PRC-006-NPCC-01 R12

have been shed by the UFLS relays at each UFLS stage coincident with their integrated hourly peak net Load during the previous year, as determined by measuring actual metered Load through the switches that would be opened by the UFLS relays.

N/A

None

N/A

x

x

Each Generator Owner, Distribution Provider or Transmission Owner
within the Planning Coordinator area of ISO-NE or the New York ISO

PRC-006-NPCC-01 R18

shall apply the criteria described in Attachment B to determine the compensatory load shedding that is required in Requirement R16.3 for generating units in its respective NPCC area.

N/A

None

N/A

x

x

Each Distribution Provider, Transmission Owner and Generator

PRC-006-NPCC-01 R22

Owner shall implement the load distribution changes based on the notification provided by the Planning Coordinator in accordance with Requirement R21.

N/A

None

N/A

x

x

Each Distribution Provider, Transmission Owner and Generator

PRC-006-NPCC-01 R22

Owner shall develop and submit an implementation plan within 90 days of the request from the Planning Coordinator for approval by the Planning Coordinator in accordance with Requirement R21.

N/A

None

N/A

x

x

The Transmission Owner and Distribution Provider with a UFLS
program (as required by its Regional Reliability Organization) shall

PRC-008-0 R1

have a UFLS equipment maintenance and testing program in place.
This UFLS equipment maintenance and testing program shall include
UFLS equipment identification, the schedule for UFLS equipment

testing, and the schedule for UFLS equipment maintenance.

N/A

None

N/A

x

x

The Transmission Owner and Distribution Provider with a UFLS
program (as required by its Regional Reliability Organization) shall

PRC-008-0 R2

implement its UFLS equipment maintenance and testing program and shall provide UFLS maintenance and testing program results to its

Regional Reliability Organization and NERC on request (within 30 calendar days).

N/A

None

N/A

x

x

The Load-Serving Entity, Transmission Owner, Transmission

Operator, and Distribution Provider that owns or operates a UVLS
program shall periodically (at least every five years or as required by
changes in system conditions) conduct and document an assessment
of the effectiveness of the UVLS program. This assessment shall be
conducted with the associated Transmission Planner(s) and Planning
Authority(ies).

PRC-010-0 R1

PRC-011-0 R1

R1.1. This assessment shall include, but is not limited to:
R1.1.1. Coordination of the UVLS programs with other protection and control systems in the Region and with other Regional Reliability Organizations, as appropriate.

R1.1.2. Simulations that demonstrate that the UVLS programs performance is consistent with Reliability Standards TPL-001-0, TPL-
002-0, TPL-003-0 and TPL-004-0.

R1.1.3. A review of the voltage set points and timing.

The Transmission Owner and Distribution Provider that owns a UVLS system shall have a UVLS equipment maintenance and testing

program in place. This program shall include:

R1.1. The UVLS system identification which shall include but is not limited to:

R1.1.1. Relays.

R1.1.2. Instrument transformers.

R1.1.3. Communications systems, where appropriate. R1.1.4. Batteries.

R1.2. Documentation of maintenance and testing intervals and their
basis.

R1.3. Summary of testing procedure.
R1.4. Schedule for system testing.

R1.5. Schedule for system maintenance. R1.6. Date last tested/maintained.

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

The Transmission Owner and Distribution Provider that owns a UVLS system shall provide documentation of its UVLS equipment

PRC-011-0 R2

maintenance and testing program and the implementation of that
UVLS equipment maintenance and testing program to its Regional
Reliability Organization and NERC on request (within 30 calendar
days).

N/A

N/A

N/A

N/A

N/A

The Transmission Owner, Generator Owner, and Distribution Provider

PRC-015-0 R1

that owns an SPS shall maintain a list of and provide data for existing
and proposed SPSs as specified in Reliability Standard PRC-013-0_R
1.

N/A

N/A

N/A

N/A

N/A

The Transmission Owner, Generator Owner, and Distribution Provider
that owns an SPS shall have evidence it reviewed new or functionally

PRC-015-0 R2

modified SPSs in accordance with the Regional Reliability
Organization’s procedures as defined in Reliability Standard PRC-012-
0_R1 prior to being placed in service.

N/A

N/A

N/A

N/A

N/A

The Transmission Owner, Generator Owner, and Distribution Provider
that owns an SPS shall provide documentation of SPS data and the

PRC-015-0 R3

results of studies that show compliance of new or functionally modified SPSs with NERC Reliability Standards and Regional Reliability

Organization criteria to affected Regional Reliability Organizations and NERC on request (within 30 calendar days).

N/A

N/A

N/A

N/A

N/A

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7/19/2016

The Transmission Owner, Generator Owner, and Distribution Provider

PRC-016-0.1 R1

that owns an SPS shall analyze its SPS operations and maintain a
record of all misoperations in accordance with the Regional SPS
review procedure specified in Reliability Standard PRC-012-0_R1

N/A

N/A

N/A

N/A

N/A

The Transmission Owner, Generator Owner, and Distribution Provider

PRC-016-0.1 R2

that owns an SPS shall take corrective actions to avoid future misoperations.

N/A

N/A

N/A

N/A

N/A

The Transmission Owner, Generator Owner, and Distribution Provider

PRC-016-0.1 R3

that owns an SPS shall provide documentation of the misoperation analyses and the corrective action plans to its Regional Reliability Organization and NERC on request (within 90 calendar days).

N/A

N/A

N/A

N/A

N/A

The Transmission Owner, Generator Owner, and Distribution Provider
that owns an SPS shall have a system maintenance and testing
program(s) in place. The program(s) shall include:
R1.1. SPS identification shall include but is not limited to:
R1.1.1. Relays.

R1.1.2. Instrument transformers.

PRC-017-0 R1

R1.1.3. Communications systems, where appropriate. R1.1.4. Batteries.

R1.2. Documentation of maintenance and testing intervals and their
basis.

R1.3. Summary of testing procedure.
R1.4. Schedule for system testing.

R1.5. Schedule for system maintenance. R1.6. Date last tested/maintained.

N/A

N/A

N/A

N/A

N/A

The Transmission Owner, Generator Owner, and Distribution Provider

PRC-017-0 R2

that owns an SPS shall provide documentation of the program and its implementation to the appropriate Regional Reliability Organizations and NERC on request (within 30 calendar days).

N/A

N/A

N/A

N/A

N/A

Each Transmission Owner and Generator Owner required to install

DMEs by its Regional Reliability Organization (reliability standard PRC002 Requirements 1-3) shall have DMEs installed that meet the

PRC-018-1 R1.

following requirements:

R1.1. Internal Clocks in DME devices shall be synchronized to within

2 milliseconds or less of Universal Coordinated Time scale (UTC). R1.2. Recorded data from each Disturbance shall be retrievable for ten calendar days.

x

None

x

x

x

The Transmission Owner and Generator Owner shall each install

PRC-018-1 R2.

DMEs in accordance with its Regional Reliability Organization’s
installation requirements (reliability standard PRC-002 Requirements 1 through 3).

x

None

x

x

x

The Transmission Owner and Generator Owner shall each maintain,
and report to its Regional Reliability Organization on request, the
following data on the DMEs installed to meet that region’s installation
requirements (reliability standard PRC-002 Requirements1.1, 2.1 and

3.1):

R3.1. Type of DME (sequence of event recorder, fault recorder, or dynamic disturbance recorder).

PRC-018-1 R3.

R3.2. Make and model of equipment. R3.3. Installation location.

R3.4. Operational status.
R3.5. Date last tested.

R3.6. Monitored elements, such as transmission circuit, bus section,
etc.

R3.7. Monitored devices, such as circuit breaker, disconnect status, alarms, etc.

R3.8. Monitored electrical quantities, such as voltage, current, etc.

x

None

x

x

x

The Transmission Owner and Generator Owner shall each provide

PRC-018-1 R4.

Disturbance data (recorded by DMEs) in accordance with its Regional Reliability Organization’s requirements (reliability standard PRC-002 Requirement 4).

x

None

x

x

x

The Transmission Owner and Generator Owner shall each archive all

PRC-018-1 R5.

data recorded by DMEs for Regional Reliability Organization-identified events for at least three years.

x

None

x

x

x

Each Transmission Owner and Generator Owner that is required by
its Regional Reliability Organization to have DMEs shall have a

PRC-018-1 R6.

maintenance and testing program for those DMEs that includes: R6.1. Maintenance and testing intervals and their basis.

R6.2 Summary of maintenance and testing procedures.

x

None

x

x

x

Each Transmission Owner and Distribution Provider that owns a
UVLS program to mitigate the risk of voltage collapse or voltage
instability in the BES shall annually update its UVLS data to support
the Regional UVLS program database. The following data shall be
provided to the Regional Reliability Organization for each installed
UVLS system:

R1.1. Size and location of customer load, or percent of connected

PRC-021-1 R1

load, to be interrupted.

R1.2. Corresponding voltage set points and overall scheme clearing
times.

R1.3. Time delay from initiation to trip signal. R1.4. Breaker operating times.

R1.5. Any other schemes that are part of or impact the UVLS
programs such as related generation protection, islanding schemes,
automatic load restoration schemes, UFLS and Special Protection
Systems.

N/A

N/A

N/A

N/A

N/A

Each Transmission Owner and Distribution Provider that owns a

PRC-021-1 R2

UVLS program shall provide its UVLS program data to the Regional Reliability Organization within 30 calendar days of a request.

N/A

N/A

N/A

N/A

N/A

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7/19/2016

Each Transmission Operator, Load-Serving Entity, and Distribution
Provider that operates a UVLS program to mitigate the risk of voltage
collapse or voltage instability in the BES shall analyze and document
all UVLS operations and Misoperations. The analysis shall include:
R1.1. A description of the event including initiating conditions.

PRC-022-1 R1

R1.2. A review of the UVLS set points and tripping times.
R1.3. A simulation of the event, if deemed appropriate by the Regional Reliability Organization. For most events, analysis of sequence of events may be sufficient and dynamic simulations may not be needed. R1.4. A summary of the findings.

R1.5. For any Misoperation, a Corrective Action Plan to avoid future Misoperations of a similar nature.

N/A

N/A

N/A

N/A

N/A

Each Transmission Owner, Generator Owner, and Distribution

Provider shall use any one of the following criteria (Requirement R1,
criteria 1 through 13) for any specific circuit terminal to prevent its

PRC-023-3 R1

phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the BES for all fault conditions.  Each Transmission Owner, Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees.

x

None

None

x

x

Each Transmission Owner, Generator Owner, and Distribution

Provider shall set its out-of-step blocking elements to allow tripping of

PRC-023-3 R2

phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per Requirement R1.

x

None

None

x

x

Each Transmission Owner, Generator Owner, and Distribution

Provider that uses a circuit capability with the practical limitations

described in Requirement R1, criterion  7, 8, 9, 12, or 13 shall use the

PRC-023-3 R3

calculated circuit capability as the Facility Rating of the circuit and
shall obtain the agreement of the Planning Coordinator, Transmission
Operator, and Reliability Coordinator with the calculated circuit
capability.

x

None

None

x