Utilities Commission Act...10 (ii) However, when NCLL is utilized under footnote 12 within the Near-Term 11 Transmission Planning Horizon to address BES performance requirements, 12

British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 www.bchydro.com

Fred James

Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407 [email protected]

May 3, 2017 Mr. Patrick Wruck Commission Secretary and Manager Regulatory Support British Columbia Utilities Commission Sixth Floor – 900 Howe Street Vancouver, BC V6Z 2N3 Dear Mr. Wruck: RE: British Columbia Utilities Commission (BCUC or Commission)

British Columbia Hydro and Power Authority (BC Hydro) Mandatory Reliability Standards (MRS) TPL-001-4 Assessment Report (the Report)

BC Hydro writes to the Commission to provide its Report dated May 2017 pursuant to section 125.2(3) of the Utilities Commission Act. BC Hydro is providing an electronic copy of the Report to registered entities in the British Columbia (B.C.) MRS program.

The Report presents the reliability impacts, suitability, standard applicability and potential costs of adopting the TPL-001-4 reliability standard and five new NERC Glossary Terms intended for TPL-001-4 (TPL-001-4 Terms) for the Bulk Electric System in B.C.

The TPL-001-4 reliability standard and the TPL-001-4 Terms were originally assessed in MRS Assessment Report No. 8, filed with the Commission on May 15, 2015. In its assessment, BC Hydro recommended holding the TPL-001-4 reliability standard and the TPL-001-4 Terms in abeyance to allow time for BC Hydro to complete a full assessment. Commission Order No. R-38-15 to MRS Assessment Report No. 8 held adoption of the TPL-001-4 reliability standard and the TPL-001-4 Terms in abeyance pending reassessment. The Report is the reassessment of the TPL-001-4 reliability standard and the five new NERC Glossary Terms, dated as at November 28, 2016, that are required to be adopted in connection with the TPL-001-4 reliability standard. In the Report, BC Hydro recommends that, with the exception of Requirement 7, the TPL-001-4 reliability standard, and TPL-001-4 Terms are suitable for adoption in B.C. Requirement 7 of the TPL-001-4 reliability standard is recommended to be held in abeyance until the Planning Coordinator matter as it pertains to B.C. is resolved.

BC Hydro has included a proposed process for the Commission’s adoption of the TPL-001-4 reliability standard and the TPL-001-4 Terms in section 3.2 of the Report.

B-1

mailto:[email protected]

markhuds

BCH MRS TPL-001-4

May 3, 2017 Mr. Patrick Wruck Commission Secretary and Manager Regulatory Support British Columbia Utilities Commission Mandatory Reliability Standards (MRS) TPL-001-4 Assessment Report (the Report) Page 2 of 2

For further information, please contact Geoff Higgins at 604-623-4121 or by email at [email protected].

Yours sincerely,

Fred James Chief Regulatory Officer st/tn

Enclosure Copy to: B.C. MRS Program Registered Entities.


BC Hydro Mandatory Reliability Standard

TPL-001-4 Assessment Report

May 2017

May 2017

BC Hydro Mandatory Reliability Standard TPL-001-4 Assessment Report

Page i

Table of Contents

1 Introduction ........................................................................................................ 1

1.1 Purpose of Report ..................................................................................... 1

1.2 Contents of the Report .............................................................................. 1

2 Special Considerations ....................................................................................... 2

2.1 Reliability Standards with Reliability Related Requirements for Planning Authority (PA)/Planning Coordinator (PC) .................................. 2

3 Report Summary ................................................................................................ 3

3.1 Draft Order ................................................................................................ 7

3.2 Proposed Process ..................................................................................... 8

4 Standards Assessment Process used in the Report .......................................... 9

4.1 Identification of the Revised Standard for Review ..................................... 9

4.2 Consultation .............................................................................................. 9

5 Assessment of Individual Standards ................................................................ 11

5.1 Analytical Approach to Assessment of Reliability Impact, Suitability, Cost of Adoption and Applicability ........................................................... 12

5.1.1 Analytical Approach in Assessing Adverse Reliability Impacts ..................................................................................... 12

5.1.2 Analytical Approach for the Suitability Assessment .................. 13

5.1.3 Analytical Approach for the Cost Assessment .......................... 14

5.1.4 Analytical Approach for the Application of the Reliability Standards ................................................................................. 14

5.2 Initial Screening of the Revised Standard for Adverse Reliability Impacts and Suitability ............................................................................ 14

5.3 Summary of Final Assessment of the Revised Standard ........................ 16

6 NERC Glossary of Terms ................................................................................. 19

6.1 NERC Glossary Terms Assessed by BC Hydro ...................................... 19

6.2 Initial Screening of the TPL-001-4 Terms and Definitions for Adverse Reliability Impacts and Suitability ............................................................ 20

6.3 Summary of Final Assessment of the NERC Glossary Terms Assessed in the Report ........................................................................... 23

7 Conclusions ...................................................................................................... 25

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List of Tables

Table 1 B.C. MRS Program Registered Entity List .......................................... 9

Table 2 Initial Screening of Revised Standards for Adverse Reliability Impact and Suitability ....................................................................... 16

Table 3 Final Assessment Summary of the Revised Standard ..................... 17

Table 4 Initial Screening of TPL-001-4 Terms for Adverse Reliability Impact and Suitability ....................................................................... 22

Table 5 Final Assessment Summary of NERC Glossary Terms ................... 24

Appendices

Appendix A Reliability Standards Assessed by BC Hydro

Appendix B-1 BC Hydro Feedback Survey Forms

Appendix B-2 Instructions for Registered Entities

Appendix B-3 External Stakeholder Feedback

Appendix C Draft Order

May 2017


Page 1

1 Introduction 1

1.1 Purpose of Report 2

Pursuant to the requirements of section 125.2(3) of the Utilities Commission Act 3

(UCA), British Columbia Hydro and Power Authority (BC Hydro) provides this 4

Mandatory Reliability Standard (MRS) TPL-001-4 Assessment Report (the Report), 5

pertaining to the bulk electric system (BES) in British Columbia (B.C.), to the British 6

Columbia Utilities Commission (BCUC or Commission) for consideration regarding 7

the reliability impacts, suitability, potential costs and standard applicability of 8

adopting the TPL-001-4 reliability standard (the Revised Standard), as well as 9

adopting five new defined terms (the TPL-001-4 Terms) from the North American 10

Electric Reliability Corporation (NERC) Glossary of Terms (NERC Glossary) dated 11

November 28, 2016. 12

1.2 Contents of the Report 13

The Report is organized as follows: 14

Section 2 outlines special considerations BC Hydro raises for the Commission’s 15

consideration. 16

Section 3 summarizes the Report findings, provides an outline of the Draft Order and 17

recommends a proposed process. 18

Section 4 explains BC Hydro’s assessment process. 19

Section 5 summarizes BC Hydro’s approach to assessing the Revised Standard, 20

and provides the results of that assessment in the case of the Revised Standard. 21

Section 6 summarizes the results of the assessment of the TPL-001-4 Terms 22

considered using the approach as described in section 5. 23

Section 7 provides BC Hydro’s conclusions. 24

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2 Special Considerations 1

BC Hydro raises the following special considerations for this Report: 2

2.1 Reliability Standards with Reliability Related Requirements for 3

Planning Authority (PA)/Planning Coordinator (PC) 4

In the Reasons for Decision for Order No. R-41-13 (page 20), the Commission found 5

that the issue in relation to the extent of the PA/PC operations/footprint in B.C. was 6

beyond the scope of the MRS Assessment Report No. 6 review process and 7

indicated that a separate process would be established to consider the PA/PC 8

matter as it pertains to B.C. The Commission Order Nos. R 32-14, R 38-15, and 9

R-32-16 addressing the reliability standards in MRS Assessment Report Nos. 7, 8, 10

and 9, were consistent with this approach for reliability standards that reference the 11

PC function. At the time of this filing, the PC matter as it pertains to B.C. is 12

unresolved. 13

In this Report, the Revised Standard contains requirements that apply to the PC 14

function. The Revised Standard is a new reliability standard which revises, 15

consolidates, and replaces existing reliability standards TPL-001-0.1, TPL-002-0b, 16

TPL-003-0b, and TPL-004-0a which are all adopted and effective in B.C. 17

Requirement 7 in particular of the Revised Standard calls for the PC function in 18

conjunction with Transmission Planners in their PC area, to identify individual and 19

joint responsibilities for performing required studies as part of Planning 20

Assessments. The remaining requirements of the Revised Standard however, are 21

not solely dependent on the PC function and apply independently to the 22

Transmission Planner function also. 23

Therefore, BC Hydro recommends that Requirement 7 of the Revised Standard be 24

ordered by the Commission to be held in abeyance and be of no force or effect in 25

B.C. until the PC matter as it pertains to B.C. is resolved. As for the remaining 26

Revised Standard requirements, BC Hydro does not see any adverse reliability risk 27

at this time preventing a recommendation for adoption. 28

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Once the PC function and footprints are defined in B.C., a reassessment of all 1

applicable reliability standards referencing the PC will go through the assessment 2

process in B.C. 3

3 Report Summary 4

The Revised Standard and the TPL-001-4 Terms recommended for adoption were 5

adopted by FERC during BC Hydro’s annual assessment period of 6

December 1, 2013 to November 30, 2014 (2014 Assessment Period). The Revised 7

Standard and the TPL-001-4 Terms were originally assessed in MRS Assessment 8

Report No. 8, filed with the Commission on May 15, 2015. In its assessment, 9

BC Hydro recommended holding the Revised Standard and TPL-001-4 Terms in 10

abeyance to allow time for BC Hydro to further assess the suitability of adopting the 11

Revised Standard and TPL-001-4 Terms in B.C. Commission Order No. R-38-15 to 12

MRS Assessment Report No. 8 held adoption of the Revised Standard and the 13

TPL-001-4 Terms in abeyance pending reassessment. Consistent with the approach 14

used to assess reliability standards in previous MRS assessment reports, BC Hydro 15

is filing a reliability standard specific assessment report for the Revised Standard 16

and the TPL-001-4 Terms. 17

The Revised Standard for Transmission System Planning Performance 18

Requirements consolidates four previously adopted transmission planning reliability 19

standards (TPL-001-0.1, TPL-002-0b, TPL-003-0b, and TPL-004-0a) into one 20

reliability standard which includes significant process revisions and now limits a 21

responsible entity’s (Transmission Planner or Planning Coordinator) use of Non 22

Consequential Load Loss (NCLL) 1 to meet performance requirements that would 23

otherwise be acceptable under the currently adopted reliability standards. 24

The currently adopted reliability standard TPL-002-0b (Table 1) sets out the 25

conditions where load shedding is and is not allowable and includes footnote ‘b’, 26

1 NCLL is defined as Non Interruptible Load loss that does not include: (1) Consequential Load Loss, (2) the

response of voltage sensitive Load, or (3) Load that is disconnected from the System by end user equipment.

May 2017


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which permits the use of load shedding as a planning solution for single contingency 1

events. The Revised Standard has a new Table 1 that does not allow load shedding 2

in some conditions that would otherwise be acceptable under the currently adopted 3

reliability standards and includes a more restrictive footnote ‘12’, which replaces 4

footnote ‘b’; footnote ‘12’ is set out as follows: 5

(i) An objective of the planning process is to minimize the likelihood and 6

magnitude of NCLL following planning events. In limited circumstances, NCLL 7

may be needed throughout the planning horizon to ensure that BES 8

performance requirements are met. 9

(ii) However, when NCLL is utilized under footnote 12 within the Near-Term 10

Transmission Planning Horizon to address BES performance requirements, 11

such interruption is limited to circumstances where the NCLL meets the 12

conditions shown in Attachment 1 of the Revised Standard (Attachment 1). 13

(iii) In no case can the planned NCLL under footnote 12 exceed 75 MW for US 14

registered entities. The amount of planned NCLL for a non-US Registered 15

Entity should be implemented in a manner that is consistent with, or under the 16

direction of, the applicable governmental authority or its agency in the non-US 17

jurisdiction. 18

Attachment 1 - Stakeholder Process 19

The Stakeholder Process, outlined in Attachment 1, includes the information that is 20

to be made available to stakeholders that attend meetings organized by the B.C. 21

registered entity planning to use NCLL under footnote ‘12’ as an element of a 22

Corrective Action Plan in the Near-Term Transmission Planning Horizon2 of the 23

Planning Assessment. Adoption of the Stakeholder Process as drafted within 24

Attachment 1 allows the flexibility for each responsible entity to develop their 25

process, subject to five requirements: 26

2 See NERC Glossary for definitions.

May 2017


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1. Meetings must be open to affected stakeholders including applicable regulatory 1

authorities; 2

2. Notice must be provided in advance of meetings to affected stakeholders 3

including applicable regulatory authorities which includes an agenda that 4

contains the date, time, and location for meetings, specific location(s) of NCLL 5

per footnote ‘12’ of the Revised Standard, and provisions for a stakeholder 6

comment period; 7

3. Purpose and scope of NCLL under footnote 12 must be made available 8

including the specific information for inclusion under Section II of Attachment 1; 9

4. A procedure for stakeholders to submit written questions or concerns and to 10

receive corresponding written responses; and 11

5. A dispute resolution process for any questions or concerns raised by 12

stakeholder written submissions that are not resolved to the stakeholder’s 13

satisfaction. 14

Attachment 1 - Instances for which Regulatory Review of NCLL under 15

Footnote 12 is required 16

Attachment 1 also outlines two instances for which Regulatory review of the use of 17

NCLL is required before NCLL under footnote ‘12’ is allowed as an element of a 18

Corrective Action Plan in Year One of the Planning Assessment: 19

1. Specific circumstances where the voltage level of the Contingency is greater 20

than 300 kV; and 21

2. The planned NCLL is greater than or equal to 25 MW. 22

Planned NCLL in B.C. 23

The Revised Standard, under footnote ‘12’, sets a limit of 75 MW of planned NCLL 24

for US registered entities. BC Hydro is not a US registered entity, and it follows that 25

May 2017


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if the Revised Standard is adopted as proposed, the 75 MW hard-cap on the use of 1

NCLL will not be applicable to BC Hydro. 2

Footnote ‘12’ further states that the amount of planned NCLL in B.C. should be 3

implemented in a manner that is consistent with, or under the direction of, the 4

applicable governmental authority or its agency in the non-US jurisdiction. 5

Consistent with footnote ‘12’ of the Revised Standard and Attachment 1 therein, 6

information regarding the planned use and the amount of NCLL will be provided to 7

the Commission as part of the Stakeholder Process and any Regulatory Review. In 8

this regard, the Commission will be informed of the planned use of NCLL in B.C., so 9

that it can direct its implementation, as required, on a case-by-case basis. 10

Dispute Resolution 11

As noted above, Attachment 1 sets out the requirements that must make up the 12

Stakeholder Process including a dispute resolution process for any question or 13

concern raised that is not resolved to the stakeholder’s satisfaction when registered 14

entities are planning to use NCLL. The Commission will be informed of the planned 15

use and amount of NCLL as well as any stakeholder questions and concerns as part 16

of the Stakeholder Process, and this puts it in a good position to resolve any 17

disputes between stakeholders and the responsible entity that is planning to use 18

NCLL. It is BC Hydro’s view that the Commission should be the final decision maker 19

in a dispute between stakeholders as to whether NCLL is an appropriate planning 20

element in light of the potential alternatives. This would be consistent with the 21

Commission’s ability to object to the use of NCLL under certain conditions as part of 22

a Regulatory Review contemplated in Attachment 1. 23

BC Hydro’s Adoption Recommendation 24

BC Hydro recommends that the Revised Standard and the TPL-001-4 Terms will 25

preserve or enhance the reliability of the BES in B.C., and thus are in the public 26

interest and suitable for adoption in B.C. with the exception of Requirement 7 due to 27

the PC matter as it pertains to B.C. BC Hydro is recommending the adoption of the 28

May 2017


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Revised Standard and the TPL-001-4 Terms assessed in the Report with the 1

exception of TPL-001-4, Requirement 7, which is recommended to be held in 2

abeyance until the PC matter as it pertains to B.C. is resolved. 3

BC Hydro has assessed its estimated incremental one-time and ongoing annual 4

costs of achieving and maintaining compliance with the adoption of the Revised 5

Standard and the TPL-001-4 Terms as mandatory in B.C. BC Hydro’s responses are 6

reproduced in full in Appendix B-1 of the Report. Consistent with the approach taken 7

in previous MRS assessment reports, BC Hydro has also sought input from B.C. 8

MRS registered entities regarding their estimated incremental one-time and annual 9

ongoing costs associated with achieving and maintaining compliance with 10

the Revised Standard and with using the TPL-001-4 Terms. 11

A complete list of the registered entities with whom BC Hydro consulted is provided 12

in Table 1, section 4.2 of the Report. A detailed breakdown of the estimated 13

incremental one-time and ongoing costs reported by BC Hydro and the registered 14

entities is provided in Table 3, section 5.3 and Table 5, section 6.3 of the Report. 15

Registered entities’ responses are reproduced in full in Appendix B-3 of the Report. 16

On the basis of BC Hydro’s own assessment and the responses received from those 17

registered entities providing cost estimates, BC Hydro estimates that the cumulative 18

cost for B.C. registered entities to achieve and maintain compliance with the Revised 19

Standard and the TPL-001-04 Terms being recommended for adoption in B.C. will 20

be at least $496,000 with respect to one-time costs, and at least $43,000 on an 21

annual ongoing basis. With respect to the costs considered herein, BC Hydro is of 22

the view that these expenditures are necessary to conduct planning assessments 23

per the new requirements, and to develop and implement a stakeholder consultation 24

process regarding the potential use of NCLL. 25

3.1 Draft Order 26

The Draft Order attached to the Report as Appendix C, includes the following draft 27

attachments: 28

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Attachment A – Shows that the TPL-001-0.1, TPL-002-0b, TPL-003-0b, and 1

TPL-004-0a - reliability standards will be superseded by the Revised Standard 2

upon adoption. Attachment A also lists the TPL-001-4 Terms to be adopted in 3

B.C. The table within Attachment A includes the recommended effective dates 4

for the Revised Standard and the TPL-001-4 Terms; 5

Attachment B – Provides a list of all of the reliability standards that would be in 6

force in B.C., should the Commission adopt the Revised Standard and those 7

reliability standards held in abeyance. The table also provides the Commission 8

Order under which each of the reliability standards was adopted and under 9

which the effective date for each of the reliability standards was set; 10

Attachment C - Provides a list of the TPL-001-4 Terms and their definitions that 11

would be in force in B.C., should the Commission adopt the Revised Standard 12

and the TPL-001-4 Terms; and 13

Attachment D - For ease of reference, BC Hydro is including Table 1 in 14

Attachment D which lists all of the B.C. specific exceptions to the NERC 15

Glossary terms, starting from MRS Assessment Report No. 6.3 16

3.2 Proposed Process 17

This is a MRS specific assessment report to be submitted to the Commission. The 18

Commission is obligated by section 125.2(5) of the UCA to make the Report publicly 19

available and to consider any comments it receives in respect of the Report. 20

To make the Report publicly available, BC Hydro will publish a notice of the Report 21

on its public website and send a letter of notification to all B.C. MRS registered 22

entities. MRS registered entities with whom BC Hydro originally consulted in 23

connection with the preparation of the Report, are listed in Table 1, section 4.2. 24

3 Refer to Table 2 in Attachment D: All Commission Orders prior to Order No. R-41-13 for MRS Assessment

Report No. 6 adopted the entire NERC Glossary effective as of the date of the Order.

May 2017


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BC Hydro will respond to any comments on the Report. The Commission would then 1

determine whether all the issues raised in the comment process have been dealt 2

with to its satisfaction. If so, no further process would be required. If not, then a 3

written process could be established to deal with any outstanding issues. Upon 4

completion of the process, the Commission would determine whether the Revised 5

Standard and the TPL-001-4 Terms should be adopted in B.C. 6

4 Standards Assessment Process used in the Report 7

4.1 Identification of the Revised Standard for Review 8

Commission Order No. R-38-15 to MRS Assessment Report No. 8 held adoption of 9

the Revised Standard and the TPL-001-4 Terms in abeyance pending 10

reassessment. Consistent with the approach used to assess reliability standards in 11

previous MRS assessment reports, BC Hydro is filing a reliability standard specific 12

assessment report for the Revised Standard and the TPL-001-4 Terms. 13

The Revised Standard was FERC approved with an Order effective on 14

December 23, 2013 (within the 2014 Assessment Period) and superseded the 15

TPL-001-0.1, TPL-002-0b, TPL-003-0b, and TPL-004-0a reliability standards 16

effective January 1, 2016 in the U.S.4 Appendix A of the Report includes clean and 17

red-lined copies of the Revised Standard in comparison with the TPL-001-0.1 18

reliability standard adopted in B.C. 19

4.2 Consultation 20

BC Hydro consulted with the B.C. MRS registered entities listed below in Table 1. 21

Table 1 B.C. MRS Program Registered Entity List 22

Registered Entities Registered Entities (Continued)

Bear Mountain Wind Limited Partnership Meikle Wind Limited Partnership

British Columbia Hydro and Power Authority Northwood Pulp Mill

4 Docket No. RM12-1-000 and RM13-9-000; Order 786; Issue Date: October 17, 2013; Publication Date:

October 23, 2013; Effective date: December 23, 2013.

May 2017


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Registered Entities Registered Entities (Continued)

Cape Scott Wind LP Powerex Corp.

Capital Power Limited Partnership Prince George Pulp & Paper Mill

Cariboo Pulp & Paper Company Quesnel River Pulp and Paper

Catalyst Paper ‐ Crofton Division Rio Tinto Alcan

Catalyst Paper ‐ Port Alberni Division Shell Energy North America (Canada) Inc.

Catalyst Paper ‐ Powell River Division Shell Energy North America (U.S.) L.P.

Coast Mountain Hydro Limited Partnership Teck Metals Ltd.

Dokie General Partnership Toba Montrose General Partnership

FortisBC Inc. Tolko Industries Limited

Howe Sound Pulp & Paper Corporation TransAlta Energy Marketing Corp

Innergex Renewable Energy Inc. TransCanada Energy Sales Ltd.

Intercontinental Pulp Mill V.I. Power Limited Partnership

Jimmie Creek Limited Partnership WESCUP

Lehigh Cement

Each registered entity on the list, with the exception of Meikle Wind Limited 1

Partnership, was issued an email package on December 19, 2016 advising that 2

37 reliability standards (including the Revised Standard) and 39 NERC Glossary 3

terms (including the five TPL-001-4 Terms) would be assessed and that the 4

assessment was due to be filed on May 1, 2017 with the Commission. Meikle Wind 5

Limited Partnership was issued an email package on February 7, 2017 when 6

BC Hydro was made aware of their registration to the B.C. MRS Program on 7

February 3, 2017 under Commission Order No. R-41-16. The email package 8

contained instructions and a link to the BC Hydro Reliability internet website where 9

two survey forms (one for reliability standards and another for NERC Glossary 10

terms) were provided for completion by entities (refer to Appendix B). Entities were 11

asked to complete and return the survey forms to BC Hydro by end of day 12

February 28, 2017. A follow-up email was sent on January 6, 2017 correcting some 13

minor updates to the email package sent on December 19, 2016. On January 13, 14

2017, BC Hydro held an informational session via teleconference for all registered 15

entities in B.C. A reminder notice was also sent to each registered entity on 16

January 31, 2017. On February 15, 2017, an email was sent to FortisBC Inc. 17

May 2017


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correcting a minor error in a note pertaining to TPL-001-4 Requirement 3 and it’s 1

applicability to the Transmission Planner function. This email was sent to FortisBC 2

Inc. as they, aside from BC Hydro, are the only other Transmission Planner 3

registered in the B.C. MRS program. On February 23, 2017, an extension notice was 4

sent to all registered entities requesting survey forms to be returned to BC Hydro by 5

end of day March 6, 2017. 6

The entities were asked to provide information for each reliability standard 7

and NERC Glossary term as follows: 8

(a) Indicate whether there were either no changes to the entity’s processes, or 9

state the high-level incremental activities or new activities needed to be 10

completed in order to become compliant; 11

(b) For each incremental or new activity, indicate associated estimated costs in 12

dollar amounts, and identify the assumptions used in developing estimates. The 13

following costs were to be considered: 14

Activities where a one-time capital cost will incur; and 15

Activities where there are ongoing annual costs associated with compliance. 16

(c) Include an assessment of the amount of time reasonably required to come into 17

compliance with the reliability standard and NERC Glossary term once adopted 18

by the Commission. The time should be reflective of any incremental or new 19

activities identified. 20

Including BC Hydro, a total of 31 registered entities were contacted. BC Hydro’s 21

responses to the Revised Standard and TPL-001-4 Terms are attached in full in 22

Appendix B-1 and registered entities’ responses are attached in full in Appendix B-3. 23

5 Assessment of Individual Standards 24

BC Hydro has assessed the Revised Standard against the criteria stipulated by 25

legislation in B.C. (section 125.2(3) of the UCA). 26

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Section 5.1 summarizes BC Hydro’s approach to addressing these criteria; 1

Section 5.2 provides a description of the Revised Standard and an explanation 2

of the reliability and suitability issues along with BC Hydro’s conclusions; and 3

Section 5.3 addresses the cost assessment and summarizes BC Hydro’s final 4

assessment of the Revised Standard. 5

5.1 Analytical Approach to Assessment of Reliability Impact, 6

Suitability, Cost of Adoption and Applicability 7

The analytical approach taken to evaluate the reliability standards against the 8

legislated assessment criteria has not changed from that used in previous MRS 9

assessment reports. Given the amendments to the UCA in October 2015, BC Hydro 10

has assessed the Application of the Revised Standard as described in section 5.1.4 11

of this Report. Compliance-related provisions included in the reliability standards are 12

not applicable to the meaning of “reliability standards” defined in section 125.2 of the 13

UCA. As a result, BC Hydro does not assess these compliance-related provisions in 14

the Report. To indicate that BC Hydro does not assess this part of the reliability 15

standards, the compliance-related provisions have been struck-through in the clean 16

and redline versions of the Revised Standard included in Appendix A of the Report. 17

Nevertheless, BC Hydro recognizes that the compliance-related provisions may be 18

adopted by the Commission. 19

In addition, BC Hydro is of the opinion that the effective dates stated in the Revised 20

Standard are likewise not applicable. Accordingly, a strike-through of section A.5 – 21

Effective Date – is included in the clean and redlined versions of the Revised 22

Standard included in Appendix A of the Report. 23

5.1.1 Analytical Approach in Assessing Adverse Reliability Impacts 24

BC Hydro has used the same approach in assessing adverse reliability impacts that 25

was used in prior MRS assessment reports. This approach relies on a determination 26

that those reliability standards that have either: (i) performance requirements that 27

May 2017


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are not currently employed in B.C., or (ii) requirements as stringent as, or more 1

stringent, than requirements or practices currently employed in B.C. that will, by 2

definition, have neutral or positive impacts on the reliability of the BES in B.C. 3

Consequently, BC Hydro’s approach is to identify performance requirements 4

associated with new, or revisions to, reliability standards that are less stringent than 5

the existing reliability standards already adopted in B.C., or practices otherwise 6

mandated in utility tariffs or business practices approved or endorsed by the 7

Commission. 8

5.1.2 Analytical Approach for the Suitability Assessment 9

The Report uses the same criteria to assess the suitability of a reliability standard 10

that were developed for the previous MRS assessment reports. The two criteria 11

used for this analysis are set out below: 12

(a) "Administrative Suitability" means that the requirements in the reliability 13

standard are fit and appropriate for implementation in light of the policy and 14

regulatory framework in B.C. The requirements can be implemented without 15

requiring the ongoing involvement of NERC, the U.S. Government, or other 16

extra‐jurisdictional entities in such a manner as would impair the operation and 17

enforcement of the requirement in B.C. If one or more of the requirements in 18

the reliability standard incorporate by reference reliability standards not yet 19

adopted in other jurisdictions, the remaining requirements in the reliability 20

standard can still be implemented presently in B.C. without giving effect to the 21

particular requirement(s) containing the cross reference; and 22

(b) "Technical Suitability" means that the requirements in the reliability standard 23

are fit and appropriate for implementation in B.C., taking into consideration the 24

unique geographical, structural, design, and functional aspects of the B.C. BES 25

and the assets that support the reliable operation of this system. 26

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5.1.3 Analytical Approach for the Cost Assessment 1

BC Hydro’s approach to assess the potential costs of the Revised Standard in the 2

Report is consistent with the approach used to assess reliability standards in 3

previous MRS assessment reports. The objective is to provide an estimate of the 4

costs of adopting reliability standards in B.C. sufficient to inform the Commission’s 5

public interest assessment. Accordingly, only the costs that B.C. entities will 6

potentially incur in order to achieve and maintain full compliance with the Revised 7

Standard were assessed. Any costs associated with B.C. entities attaining or 8

maintaining compliance with pre-existing reliability standards in B.C. were excluded. 9

5.1.4 Analytical Approach for the Application of the Reliability Standards 10

Pursuant to the obligations contained in paragraph 125.2(3)(c.1) of the UCA, 11

BC Hydro’s approach to assess the application of the Revised Standard to persons 12

or persons in respect of specified equipment in the Report is consistent with the 13

approach used to review reliability standards in previous MRS assessment reports. 14

BC Hydro assesses the Applicability section contained in the Introduction of the 15

Revised Standard at Section A.4, to ensure consistency with the functional 16

registration categories contained in the B.C. MRS program, as contained in the MRS 17

Rules of Procedure in B.C. BC Hydro considers this approach to satisfy the new 18

obligations contained in paragraph 125.2(3)(c.1) of the UCA. 19

Any issues regarding the applicability of reliability standards to particular entities can 20

be addressed in the context of the Commission’s registration and compliance 21

regime. 22

5.2 Initial Screening of the Revised Standard for Adverse 23

Reliability Impacts and Suitability 24

In terms of the assessment of the Revised Standard against the reliability and 25

suitability criteria, BC Hydro first performed an initial screening of the Revised 26

Standard against the criteria described in section 5.1 of the Report to identify issues 27

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for further examination. This initial screening does not purport to be BC Hydro’s final 1

assessment of the Revised Standard. 2

The results of BC Hydro’s initial screening of the Revised Standards for potential 3

issues regarding adverse reliability impacts and suitability are summarized below in 4

Table 2, which includes: 5

The “Standard” column, which identifies the Revised Standards assessed; 6

The “Changed from Commission Approved Standard” column, which identifies 7

whether the Revised Standard is a revision to a reliability standard already 8

adopted by the Commission; 9

The “Adverse Impact” column, which identifies potential issues relating to 10

adverse reliability impact; 11

The “Suitability Issues” columns, which identify potential suitability issues 12

related to the Revised Standards: 13

Requires NERC Approval/Participation: Identifies a potential Technical or 14

Administrative Suitability issue as related to continued reliance on approvals 15

by NERC and/or participation by NERC in order to implement the 16

requirements of a given reliability standard; 17

Requires Provisions of Information to NERC or the Western Electricity 18

Coordinating Council (WECC): Identifies a potential Technical or 19

Administrative Suitability issue with a Revised Standard that requires 20

ongoing reporting of information to NERC or WECC (i.e., lack of clarity on 21

reporting instructions, references to undefined processes or reporting tools, 22

etc.); 23

Refers to Standard not yet FERC Approved: Identifies a potential Technical 24

or Administrative Suitability issue with a Revised Standard as it contains one 25

or more references to other reliability standards that have not yet been 26

approved by FERC in the U.S., and thereby not assessed for adoption in 27

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B.C., which would affect the ability to implement one or more requirements 1

of the Revised Standard; and 2

Other Suitability Issues: Identifies whether there are any other Administrative 3

Suitability, Technical Suitability or reliability standard Applicability issues identified, 4

apart from the categories already defined, that would affect the ability to implement 5

the requirements of the Revised Standard. 6

Table 2 Initial Screening of Revised Standards for 7

Adverse Reliability Impact and Suitability 8

Standard Changed from

Commission Approved

Standard

Adverse Impact

Suitability Issues

Requires NERC Approval/ Participation

Requires Provisions of Information to NERC or WECC

Refers to Standard not yet FERC Approved

Other Suitability/

Applicability Issues

To NERC

To WECC

TPL-001-4 Yes No No Yes2 No No Yes1

1 Revised Standards contain reliability related requirements for the PA/PC function. Please refer to section 2.1. 9

2 Revised Standard TPL-001-4, Attachment 1 references submitting information to the ERO. In the U.S. the ERO is NERC; however 10

there is no ERO in B.C. Similar ERO reporting requirements exist within the BCUC adopted and effective reliability standards, for 11

which B.C. entities have not been required to report events to NERC. 12

5.3 Summary of Final Assessment of the Revised Standard 13

BC Hydro’s final assessment of the Revised Standard, based on internal and 14

external responses from B.C. registered entities is summarized below in Table 3, 15

which includes: 16

BC Hydro’s final assessment as to whether the adoption of the Revised 17

Standard will give rise to adverse reliability consequences; 18

BC Hydro’s final assessment as to the suitability of the Revised Standard, 19

based on the criteria described in section 5.1.2; 20

BC Hydro’s and registered entities’ estimated incremental one time and 21

ongoing annual costs to achieve and maintain compliance associated with the 22

Revised Standards; and 23

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BC Hydro’s recommended effective dates, based on comments made by 1

registered entities who responded to the stakeholder survey, for the Revised 2

Standard. BC Hydro recommends that these recommended effective dates be 3

adopted by the Commission to replace section A.5 Effective Date in the 4

Revised Standard. For informational purposes only feedback that does not align 5

with BC Hydro’s recommended effective dates are listed under ‘Feedback 6

Exceptions’ where applicable. 7

Table 3 Final Assessment Summary of the 8

Revised Standard 9

Standard Adverse Reliability

Consequences

Suitability Issues

One-time Cost ($)

Ongoing Cost ($/year)

Recommended Effective Date

TPL-001-04 None reported. R7: Yes; further clarification is requested of the standard from the BCUC regarding PC footprints and entities responsible.1

BC Hydro –

R1: $10,000 total for 100 man hours of time; equipment spares availability need to be dove tailed with power flow base cases and contingency lists. The short circuit study equipment models are to be included in existing TPL assessment planning models.

R2: $56,000 total for eight transmission planners over two weeks; study methodologies needs to be re written to take in to account the new requirements of

a) Sensitivity studies

b) equipment spares availability related analysis

c) short circuit studies and analysis of results

d) options of alternatives to reinforcements detailed in the standard.

BC Hydro –

R2: $28,000 total; about one more week in increase of studies required for about eight transmission planners (280 man hours). This incremental increase in TPL assessment activity is due to the additional TPL-001-4 requirements.

R4: Unknown at this time; to come out of future planning studies.

R7: To be determined. Unable to be assessed at this time.1

Fortis BC –

R1-R6, R8: $15,000 - $20,000; new short circuit analyses will be

BC Hydro’s Consolidated Recommendations:

R1: First day of first calendar quarter, two years after BCUC adoption.

R2-R6, R8: First day of first calendar quarter, three years after BCUC adoption.

For 84 calendar months beginning the first day of the first calendar quarter following BCUC approval, Corrective Action Plans applying to the following categories of Contingencies and events identified in TPL-001-4, Table 1 are allowed to include Non-Consequential Load Loss and curtailment of Firm Transmission Service (in accordance with Requirement R2, Part 2.7.3.) that would not otherwise be permitted by the requirements of TPL-001-4:

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Standard Adverse Reliability

Consequences

Suitability Issues

One-time Cost ($)

Ongoing Cost ($/year)


R4: $400,000 total due to the estimated use of NCLL on approximately four occasions costing ~ $100,000 each for the stakeholder process; if the TPL assessments identify there is a need to shed non-consequential load , then the use of NCLL will need to be reviewed through an open and transparent stakeholder process.


Fortis BC –

R1-R6, R8: $30,000-$50,000 total; studies using short circuit models with any planned generation and transmission facilities in service which could impact the study area will need to be developed and maintained. Minor modifications to the annual Fortis BC planning study will be required.

required annually. - P1-2 (for controlled interruption of electric supply to local network customers connected to or supplied by the Faulted element)

- P1-3 (for controlled interruption of electric supply to local network customers connected to or supplied by the Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5

- P4-1 through P4-5 (above 300 kV)

- P5 (above 300 kV)


Feedback Exceptions:

Fortis BC –

R1-R6, R8: 24 months to 36 months after BCUC approval.

1 Revised Standards contain reliability related requirements for the PA/PC function. Please refer to section 2.1. 1

BC Hydro’s assessment is that the Revised Standard will either maintain or promote 2

the reliability of the BES in B.C. 3

BC Hydro’s final assessment as to the application of the Revised Standard is to 4

recommend that section A.4 Applicability in the Revised Standard be adopted by the 5

Commission. 6

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6 NERC Glossary of Terms 1

This section outlines the TPL-001-4 Terms assessed in the Report and the results of 2

the assessment. 3

Section 6.1 provides a description of each assessed TPL-001-4 Term; 4

Section 6.2 describes the results of the initial screening of the TPL-001-4 Terms 5

and definitions for adverse reliability impacts and suitability; and 6

Section 6.3 summarizes the results of the assessment of the TPL-001-4 Terms 7

along with BC Hydro’s conclusions. 8

The Revised Standard assessed by BC Hydro in this Report is based on the defined 9

terms contained in the NERC Glossary dated November 28, 2016 that are intended 10

for the Revised Standard. Accordingly, BC Hydro has included the TPL-001-4 Terms 11

and their definitions in Attachment C to Appendix C (Draft Order) of the Report. The 12

TPL-001-4 Terms are integral to the Revised Standard, and should be adopted by 13

the Commission in conjunction with the Revised Standard assessed in the Report in 14

order to achieve and maintain consistency with NERC reliability standards going 15

forward. 16

6.1 NERC Glossary Terms Assessed by BC Hydro 17

As provided in Attachment C to Appendix C (Draft Order) of the Report, the NERC 18

Glossary contains five TPL-001-4 Terms that are intended for the Revised Standard 19

and have been adopted by NERC and approved by FERC on October 17, 2013, 20

within the 2014 Assessment Period. 21

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6.2 Initial Screening of the TPL-001-4 Terms and Definitions for 1

Adverse Reliability Impacts and Suitability 2

BC Hydro applies a similar analytical approach to the assessment of the reliability 3

impact, suitability and cost of adoption of the TPL-001-4 Terms as is described in 4

section 5.1 of the Report for the assessment of the Revised Standard. The results of 5

BC Hydro’s initial screening of the TPL-001-4 Terms for potential issues regarding 6

adverse reliability impacts and suitability are summarized below in Table 4, which 7

includes: 8

The “NERC Glossary Term” column identifies the TPL-001-4 Terms; 9

The “Changed from Commission Approved Term and Definition” column, which 10

identifies whether the TPL-001-4 Term and/or its definition is a revision to a 11

Commission adopted NERC Glossary term and/or its definition, or whether it is 12

being retired; 13

The “Adverse Impact” column, which identifies potential issues relating to 14

adverse reliability impact; and 15

The “Suitability Issues” columns, which identify potential suitability issues 16

related to TPL-001-4 Terms superseding Commission approved NERC 17

Glossary terms: 18

Requires NERC Approval/Participation: Identifies a potential Administrative 19

or Technical Suitability issue as related to continued reliance on approvals 20

by NERC and/or participation in NERC in order to implement the definition of 21

a TPL-001-4 Term; 22

Requires Provisions of Information to NERC or WECC: Identifies a potential 23

Administrative or Technical Suitability issue with a TPL-001-4 Term and its 24

definition that requires ongoing reporting of information to NERC or WECC 25

(i.e., lack of clarity on reporting instructions, references to undefined 26

processes or reporting tools, etc.); 27

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Refers to Standard, Term, or Definition not yet FERC Approved: Identifies a 1

potential Technical or Administrative Suitability issue with a TPL-001-4 Term 2

and/or its definition as it contains one or more references to reliability 3

standards or other NERC Glossary terms and associated definitions that 4

have not yet been approved by FERC in the U.S., and thereby not assessed 5

for adoption in B.C. This would affect the ability to implement the TPL-001-4 6

Term and its definition; and 7

Other Suitability Issues: Identifies whether there are any other 8

Administrative or Technical Suitability issues identified, apart from the 9

categories already defined, that would affect the ability to implement 10

the TPL-001-4 Term and its definition. 11

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Table 4 Initial Screening of TPL-001-4 Terms for Adverse Reliability Impact and 1

Suitability 2

NERC Glossary Term Changed from Commission

Approved Term and Definition

Adverse Impact

Suitability Issues

Requires NERC Approval/ Participation

Requires Provisions of Information to NERC or WECC

Refers to Term or Definition not yet FERC Approved

Other Suitability Issues

To NERC To WECC

Bus-tie Breaker New None No No No No None

Consequential Load Loss New None No No No No None

Long-Term Transmission Planning Horizon

New None No No No No None

Non-Consequential Load Loss New None No No No No None

Planning Assessment New None No No No No None

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6.3 Summary of Final Assessment of the NERC Glossary Terms 1

Assessed in the Report 2

BC Hydro’s final assessment of the five TPL-001-4 Terms based on survey 3

responses from registered entities is summarized below in Table 5, which includes: 4

BC Hydro’s final assessment as to whether the adoption of the TPL-001-4 5

Terms will give rise to adverse reliability consequences; 6

BC Hydro’s final assessment as to the suitability of the TPL-001-4 Terms, 7

based on the criteria described in section 5.1; 8

The estimated incremental one-time and ongoing annual costs to achieve and 9

maintain compliance with the reliability standards that make reference to 10

the TPL-001-4 Terms as reported by BC Hydro; and 11

BC Hydro’s recommended effective dates, based on comments made by 12

registered entities who responded to the stakeholder survey, for the TPL-001-4 13

Terms. BC Hydro recommends that these recommended effective dates be 14

adopted by the Commission.15

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Table 5 Final Assessment Summary of NERC Glossary Terms 1

NERC Glossary Term

Adverse Reliability Consequences

Suitability Issues

One-time Cost

($)

Ongoing Cost

($/year)


Bus-tie Breaker None None

Included as part of TPL-001-4 reliability standard implementation costs


Coincide with earliest TPL-001-4 effective date in B.C.

Consequential Load Loss

None None Included as part of TPL-001-4 reliability standard implementation costs







Non-Consequential Load Loss



BC Hydro’s Consolidated Recommendation: Coincide with earliest TPL-001-4 effective date in B.C.

Feedback Exceptions: Northwood Pulp Mill – Immediately after BCUC adoption.

Planning Assessment




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BC Hydro’s assessment is that all of the assessed TPL-001-4 Terms will either 1

maintain or promote the reliability of the BES in B.C. Based on the assessment 2

above, the minimum total costs required to adopt these five TPL-001-4 Terms have 3

been incorporated as part of the estimated costs for the implementation of the 4

Revised Standard in section 5.3 of the Report. 5

7 Conclusions 6

BC Hydro has assessed the Revised Standard adopted by FERC in the U.S. during 7

the 2014 Assessment Period. BC Hydro has concluded that the Revised Standard 8

will preserve or enhance the reliability of the BES in B.C., and thus will serve the 9

public interest and is suitable for adoption in B.C. with the exception of TPL-001-4, 10

Requirement 7, which is recommended to be held in abeyance until the PC matter 11

as it pertains to B.C. is resolved. BC Hydro recommends that the Revised Standard, 12

be adopted by the Commission and should have effective dates that are based on 13

the recommended effective dates included in Table 3, section 5.3 and Attachment A 14

to Appendix C (Draft Order) of the Report. 15

BC Hydro has assessed the five TPL-001-4 Terms adopted by FERC in the U.S. 16

during the 2014 Assessment Period. BC Hydro has concluded that the five 17

TPL-001-4 Terms in the NERC Glossary dated November 28, 2016 be adopted by 18

the Commission. The TPL-001-4 Terms assessed in the Report will preserve or 19

enhance the reliability of the BES in B.C., and thus will serve the public interest and 20

are suitable for adoption in B.C. The TPL-001-4 Terms and their definitions are 21

included in Attachment C to Appendix C (Draft Order) of the Report. BC Hydro 22

recommends that these five TPL-001-4 Terms be adopted by the Commission and 23

should have effective dates that are based on the recommended effective dates 24

included in Table 5, section 6.3 and Attachment A to Appendix C (Draft Order) of the 25

Report. 26

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Regarding the replacement of the Commission approved reliability standards 1

TPL-001-0.1, TPL-002-0b, TPL-003-0b, and TPL-004-0a being superseded by 2

the Revised Standard, BC Hydro recommends that, to avoid duplication, these 3

currently approved reliability standards be ordered to remain in effect until the 4

effective dates of the superseding Revised Standard. 5


Appendix A

Reliability Standards Assessed by BC Hydro

Clean

Standard TPL-001-4 — Transmission System Planning Performance Requirements

1

A. Introduction 1. Title: Transmission System Planning Performance Requirements

2. Number: TPL-001-4

3. Purpose: Establish Transmission system planning performance requirements within the planning horizon to develop a Bulk Electric System (BES) that will operate reliably over a broad spectrum of System conditions and following a wide range of probable Contingencies.

4. Applicability:

4.1. Functional Entity

4.1.1. Planning Coordinator.

4.1.2. Transmission Planner.

5. Effective Date: Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first calendar quarter, 12 months after applicable regulatory approval. In those jurisdictions where regulatory approval is not required, Requirements R1 and R7 become effective on the first day of the first calendar quarter, 12 months after Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.

Except as indicated below, Requirements R2 through R6 and Requirement R8 shall become effective on the first day of the first calendar quarter, 24 months after applicable regulatory approval. In those jurisdictions where regulatory approval is not required, all requirements, except as noted below, go into effect on the first day of the first calendar quarter, 24 months after Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.

For 84 calendar months beginning the first day of the first calendar quarter following applicable regulatory approval, or in those jurisdictions where regulatory approval is not required on the first day of the first calendar quarter 84 months after Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities, Corrective Action Plans applying to the following categories of Contingencies and events identified in TPL-001-4, Table 1 are allowed to include Non-Consequential Load Loss and curtailment of Firm Transmission Service (in accordance with Requirement R2, Part 2.7.3.) that would not otherwise be permitted by the requirements of TPL-001-4:

P1-2 (for controlled interruption of electric supply to local network customers connected to or supplied by the Faulted element)

P1-3 (for controlled interruption of electric supply to local network customers connected to or supplied by the Faulted element)

P2-1 P2-2 (above 300 kV) P2-3 (above 300 kV) P3-1 through P3-5 P4-1 through P4-5 (above 300 kV) P5 (above 300 kV)


2

B. Requirements R1. Each Transmission Planner and Planning Coordinator shall maintain System models within its

respective area for performing the studies needed to complete its Planning Assessment. The models shall use data consistent with that provided in accordance with the MOD-010 and MOD-012 standards, supplemented by other sources as needed, including items represented in the Corrective Action Plan, and shall represent projected System conditions. This establishes Category P0 as the normal System condition in Table 1. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

1.1. System models shall represent:

1.1.1. Existing Facilities

1.1.2. Known outage(s) of generation or Transmission Facility(ies) with a duration of at least six months.

1.1.3. New planned Facilities and changes to existing Facilities

1.1.4. Real and reactive Load forecasts

1.1.5. Known commitments for Firm Transmission Service and Interchange

1.1.6. Resources (supply or demand side) required for Load

R2. Each Transmission Planner and Planning Coordinator shall prepare an annual Planning Assessment of its portion of the BES. This Planning Assessment shall use current or qualified past studies (as indicated in Requirement R2, Part 2.6), document assumptions, and document summarized results of the steady state analyses, short circuit analyses, and Stability analyses. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]

2.1. For the Planning Assessment, the Near-Term Transmission Planning Horizon portion of the steady state analysis shall be assessed annually and be supported by current annual studies or qualified past studies as indicated in Requirement R2, Part 2.6. Qualifying studies need to include the following conditions:

2.1.1. System peak Load for either Year One or year two, and for year five.

2.1.2. System Off-Peak Load for one of the five years.

2.1.3. P1 events in Table 1, with known outages modeled as in Requirement R1, Part 1.1.2, under those System peak or Off-Peak conditions when known outages are scheduled.

2.1.4. For each of the studies described in Requirement R2, Parts 2.1.1 and 2.1.2, sensitivity case(s) shall be utilized to demonstrate the impact of changes to the basic assumptions used in the model. To accomplish this, the sensitivity analysis in the Planning Assessment must vary one or more of the following conditions by a sufficient amount to stress the System within a range of credible conditions that demonstrate a measurable change in System response :

• Real and reactive forecasted Load. • Expected transfers. • Expected in service dates of new or modified Transmission Facilities. • Reactive resource capability. • Generation additions, retirements, or other dispatch scenarios.


3

• Controllable Loads and Demand Side Management. • Duration or timing of known Transmission outages.

2.1.5. When an entity’s spare equipment strategy could result in the unavailability of major Transmission equipment that has a lead time of one year or more (such as a transformer), the impact of this possible unavailability on System performance shall be studied. The studies shall be performed for the P0, P1, and P2 categories identified in Table 1 with the conditions that the System is expected to experience during the possible unavailability of the long lead time equipment.

2.2. For the Planning Assessment, the Long-Term Transmission Planning Horizon portion of the steady state analysis shall be assessed annually and be supported by the following annual current study, supplemented with qualified past studies as indicated in Requirement R2, Part 2.6:

2.2.1. A current study assessing expected System peak Load conditions for one of the years in the Long-Term Transmission Planning Horizon and the rationale for why that year was selected.

2.3. The short circuit analysis portion of the Planning Assessment shall be conducted annually addressing the Near-Term Transmission Planning Horizon and can be supported by current or past studies as qualified in Requirement R2, Part 2.6. The analysis shall be used to determine whether circuit breakers have interrupting capability for Faults that they will be expected to interrupt using the System short circuit model with any planned generation and Transmission Facilities in service which could impact the study area.

2.4. For the Planning Assessment, the Near-Term Transmission Planning Horizon portion of the Stability analysis shall be assessed annually and be supported by current or past studies as qualified in Requirement R2, Part2.6. The following studies are required:

2.4.1. System peak Load for one of the five years. System peak Load levels shall include a Load model which represents the expected dynamic behavior of Loads that could impact the study area, considering the behavior of induction motor Loads. An aggregate System Load model which represents the overall dynamic behavior of the Load is acceptable.


2.4.3. For each of the studies described in Requirement R2, Parts 2.4.1 and 2.4.2, sensitivity case(s) shall be utilized to demonstrate the impact of changes to the basic assumptions used in the model. To accomplish this, the sensitivity analysis in the Planning Assessment must vary one or more of the following conditions by a sufficient amount to stress the System within a range of credible conditions that demonstrate a measurable change in performance:

• Load level, Load forecast, or dynamic Load model assumptions. • Expected transfers. • Expected in service dates of new or modified Transmission Facilities. • Reactive resource capability. • Generation additions, retirements, or other dispatch scenarios.


4

2.5. For the Planning Assessment, the Long-Term Transmission Planning Horizon portion of the Stability analysis shall be assessed to address the impact of proposed material generation additions or changes in that timeframe and be supported by current or past studies as qualified in Requirement R2, Part2.6 and shall include documentation to support the technical rationale for determining material changes.

2.6. Past studies may be used to support the Planning Assessment if they meet the following requirements:

2.6.1. For steady state, short circuit, or Stability analysis: the study shall be five calendar years old or less, unless a technical rationale can be provided to demonstrate that the results of an older study are still valid.

2.6.2. For steady state, short circuit, or Stability analysis: no material changes have occurred to the System represented in the study. Documentation to support the technical rationale for determining material changes shall be included.

2.7. For planning events shown in Table 1, when the analysis indicates an inability of the System to meet the performance requirements in Table 1, the Planning Assessment shall include Corrective Action Plan(s) addressing how the performance requirements will be met. Revisions to the Corrective Action Plan(s) are allowed in subsequent Planning Assessments but the planned System shall continue to meet the performance requirements in Table 1. Corrective Action Plan(s) do not need to be developed solely to meet the performance requirements for a single sensitivity case analyzed in accordance with Requirements R2, Parts 2.1.4 and 2.4.3. The Corrective Action Plan(s) shall:

2.7.1. List System deficiencies and the associated actions needed to achieve required System performance. Examples of such actions include:

• Installation, modification, retirement, or removal of Transmission and generation Facilities and any associated equipment.

• Installation, modification, or removal of Protection Systems or Special Protection Systems

• Installation or modification of automatic generation tripping as a response to a single or multiple Contingency to mitigate Stability performance violations.

• Installation or modification of manual and automatic generation runback/tripping as a response to a single or multiple Contingency to mitigate steady state performance violations.

• Use of Operating Procedures specifying how long they will be needed as part of the Corrective Action Plan.

• Use of rate applications, DSM, new technologies, or other initiatives.

2.7.2. Include actions to resolve performance deficiencies identified in multiple sensitivity studies or provide a rationale for why actions were not necessary.

2.7.3. If situations arise that are beyond the control of the Transmission Planner or Planning Coordinator that prevent the implementation of a Corrective Action Plan in the required timeframe, then the Transmission Planner or Planning Coordinator is permitted to utilize Non-Consequential Load Loss and curtailment of Firm Transmission Service to correct the situation that would normally not be permitted in Table 1, provided that the Transmission Planner


5

or Planning Coordinator documents that they are taking actions to resolve the situation. The Transmission Planner or Planning Coordinator shall document the situation causing the problem, alternatives evaluated, and the use of Non-Consequential Load Loss or curtailment of Firm Transmission Service.

2.7.4. Be reviewed in subsequent annual Planning Assessments for continued validity and implementation status of identified System Facilities and Operating Procedures.

2.8. For short circuit analysis, if the short circuit current interrupting duty on circuit breakers determined in Requirement R2, Part 2.3 exceeds their Equipment Rating, the Planning Assessment shall include a Corrective Action Plan to address the Equipment Rating violations. The Corrective Action Plan shall:

2.8.1. List System deficiencies and the associated actions needed to achieve required System performance.

2.8.2. Be reviewed in subsequent annual Planning Assessments for continued validity and implementation status of identified System Facilities and Operating Procedures.

R3. For the steady state portion of the Planning Assessment, each Transmission Planner and Planning Coordinator shall perform studies for the Near-Term and Long-Term Transmission Planning Horizons in Requirement R2, Parts 2.1, and 2.2. The studies shall be based on computer simulation models using data provided in Requirement R1. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

3.1. Studies shall be performed for planning events to determine whether the BES meets the performance requirements in Table 1 based on the Contingency list created in Requirement R3, Part 3.4.

3.2. Studies shall be performed to assess the impact of the extreme events which are identified by the list created in Requirement R3, Part 3.5.

3.3. Contingency analyses for Requirement R3, Parts 3.1 & 3.2 shall:

3.3.1. Simulate the removal of all elements that the Protection System and other automatic controls are expected to disconnect for each Contingency without operator intervention. The analyses shall include the impact of subsequent:

3.3.1.1. Tripping of generators where simulations show generator bus voltages or high side of the generation step up (GSU) voltages are less than known or assumed minimum generator steady state or ride through voltage limitations. Include in the assessment any assumptions made.

3.3.1.2. Tripping of Transmission elements where relay loadability limits are exceeded.

3.3.2. Simulate the expected automatic operation of existing and planned devices designed to provide steady state control of electrical system quantities when such devices impact the study area. These devices may include equipment such as phase-shifting transformers, load tap changing transformers, and switched capacitors and inductors.

3.4. Those planning events in Table 1, that are expected to produce more severe System impacts on its portion of the BES, shall be identified and a list of those Contingencies


6

to be evaluated for System performance in Requirement R3, Part 3.1 created. The rationale for those Contingencies selected for evaluation shall be available as supporting information.

3.4.1. The Planning Coordinator and Transmission Planner shall coordinate with adjacent Planning Coordinators and Transmission Planners to ensure that Contingencies on adjacent Systems which may impact their Systems are included in the Contingency list.

3.5. Those extreme events in Table 1 that are expected to produce more severe System impacts shall be identified and a list created of those events to be evaluated in Requirement R3, Part 3.2. The rationale for those Contingencies selected for evaluation shall be available as supporting information. If the analysis concludes there is Cascading caused by the occurrence of extreme events, an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) shall be conducted.

R4. For the Stability portion of the Planning Assessment, as described in Requirement R2, Parts 2.4 and 2.5, each Transmission Planner and Planning Coordinator shall perform the Contingency analyses listed in Table 1. The studies shall be based on computer simulation models using data provided in Requirement R1. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

4.1. Studies shall be performed for planning events to determine whether the BES meets the performance requirements in Table 1 based on the Contingency list created in Requirement R4, Part 4.4.

4.1.1. For planning event P1: No generating unit shall pull out of synchronism. A generator being disconnected from the System by fault clearing action or by a Special Protection System is not considered pulling out of synchronism.

4.1.2. For planning events P2 through P7: When a generator pulls out of synchronism in the simulations, the resulting apparent impedance swings shall not result in the tripping of any Transmission system elements other than the generating unit and its directly connected Facilities.

4.1.3. For planning events P1 through P7: Power oscillations shall exhibit acceptable damping as established by the Planning Coordinator and Transmission Planner.

4.2. Studies shall be performed to assess the impact of the extreme events which are identified by the list created in Requirement R4, Part 4.5.

4.3. Contingency analyses for Requirement R4, Parts 4.1 and 4.2 shall :

4.3.1. Simulate the removal of all elements that the Protection System and other automatic controls are expected to disconnect for each Contingency without operator intervention. The analyses shall include the impact of subsequent:

4.3.1.1. Successful high speed (less than one second) reclosing and unsuccessful high speed reclosing into a Fault where high speed reclosing is utilized.

4.3.1.2. Tripping of generators where simulations show generator bus voltages or high side of the GSU voltages are less than known or assumed generator low voltage ride through capability. Include in the assessment any assumptions made.


7

4.3.1.3. Tripping of Transmission lines and transformers where transient swings cause Protection System operation based on generic or actual relay models.

4.3.2. Simulate the expected automatic operation of existing and planned devices designed to provide dynamic control of electrical system quantities when such devices impact the study area. These devices may include equipment such as generation exciter control and power system stabilizers, static var compensators, power flow controllers, and DC Transmission controllers.

4.4. Those planning events in Table 1 that are expected to produce more severe System impacts on its portion of the BES, shall be identified, and a list created of those Contingencies to be evaluated in Requirement R4, Part 4.1. The rationale for those Contingencies selected for evaluation shall be available as supporting information.

4.4.1. Each Planning Coordinator and Transmission Planner shall coordinate with adjacent Planning Coordinators and Transmission Planners to ensure that Contingencies on adjacent Systems which may impact their Systems are included in the Contingency list.

4.5. Those extreme events in Table 1 that are expected to produce more severe System impacts shall be identified and a list created of those events to be evaluated in Requirement R4, Part 4.2. The rationale for those Contingencies selected for evaluation shall be available as supporting information. If the analysis concludes there is Cascading caused by the occurrence of extreme events, an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences of the event(s) shall be conducted.

R5. Each Transmission Planner and Planning Coordinator shall have criteria for acceptable System steady state voltage limits, post-Contingency voltage deviations, and the transient voltage response for its System. For transient voltage response, the criteria shall at a minimum, specify a low voltage level and a maximum length of time that transient voltages may remain below that level. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

R6. Each Transmission Planner and Planning Coordinator shall define and document, within their Planning Assessment, the criteria or methodology used in the analysis to identify System instability for conditions such as Cascading, voltage instability, or uncontrolled islanding. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

R7. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall determine and identify each entity’s individual and joint responsibilities for performing the required studies for the Planning Assessment. [Violation Risk Factor: Low] [Time Horizon: Long-term Planning]

R8. Each Planning Coordinator and Transmission Planner shall distribute its Planning Assessment results to adjacent Planning Coordinators and adjacent Transmission Planners within 90 calendar days of completing its Planning Assessment, and to any functional entity that has a reliability related need and submits a written request for the information within 30 days of such a request. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

8.1. If a recipient of the Planning Assessment results provides documented comments on the results, the respective Planning Coordinator or Transmission Planner shall provide a documented response to that recipient within 90 calendar days of receipt of those comments.

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

8

Tabl

e 1

– St

eady

Sta

te &

Sta

bilit

y Pe

rfor

man

ce P

lann

ing

Even

ts

Stea

dy S

tate

& S

tabi

lity:

a

. T

he

Syste

m s

ha

ll re

ma

in s

tab

le.

Ca

sca

din

g a

nd u

nco

ntr

olle

d isla

ndin

g s

ha

ll n

ot o

ccu

r.

b.

Co

nse

qu

en

tia

l L

oad

Loss a

s w

ell

as g

en

era

tion

loss is a

cce

pta

ble

as a

co

nse

qu

en

ce

of a

ny e

ve

nt

exclu

din

g P

0.

c.

Sim

ula

te th

e r

em

ova

l o

f a

ll e

lem

en

ts t

ha

t P

rote

ctio

n S

yste

ms a

nd

oth

er

co

ntr

ols

are

exp

ecte

d t

o a

uto

ma

tically

dis

co

nne

ct fo

r e

ach

eve

nt.

d.

Sim

ula

te N

orm

al C

lea

rin

g u

nle

ss o

the

rwis

e s

pecifie

d.

e.

Pla

nn

ed

Syste

m a

dju

stm

en

ts s

uch

as T

ran

sm

issio

n c

on

fig

ura

tio

n c

ha

ng

es a

nd

re

-dis

pa

tch o

f g

en

era

tio

n a

re a

llow

ed

if

such

ad

justm

en

ts a

re e

xe

cu

tab

le w

ith

in t

he

tim

e

du

ratio

n a

pp

licab

le to

th

e F

acili

ty R

atin

gs.

Ste

ady

Stat

e O

nly:

f.

Ap

plic

able

Fa

cili

ty R

atin

gs s

hall

not

be

exce

ed

ed

.

g.

Syste

m s

tead

y s

tate

vo

ltag

es a

nd

po

st-

Con

ting

ency v

olta

ge

de

via

tion

s s

hall

be

with

in a

ccep

tab

le lim

its a

s e

sta

blis

hed

by th

e P

lan

nin

g C

oo

rdin

ato

r a

nd

th

e T

ran

sm

issio

n

Pla

nn

er.

h.

Pla

nn

ing

eve

nt

P0

is a

pplic

ab

le t

o s

tead

y s

tate

only

.

i.

Th

e re

sp

onse

of

vo

lta

ge

se

nsitiv

e L

oad

th

at

is d

isco

nne

cte

d fro

m th

e S

yste

m b

y e

nd

-use

r e

qu

ipm

en

t associa

ted

with

an

eve

nt

sha

ll n

ot b

e u

sed

to

me

et

ste

ad

y s

tate

p

erf

orm

ance

req

uire

men

ts.

Stab

ility

Onl

y:

j.

Tra

nsie

nt vo

lta

ge

resp

onse

sha

ll be

with

in a

cce

pta

ble

lim

its e

sta

blis

hed

by t

he P

lann

ing

Co

ord

ina

tor

an

d th

e T

ransm

issio

n P

lan

ne

r.

Cat

egor

y In

itial

Con

ditio

n Ev

ent 1

Fa

ult T

ype

2 B

ES L

evel

3 In

terr

uptio

n of

Firm

Tr

ansm

issi

on

Serv

ice

Allo

wed

4 N

on-C

onse

quen

tial

Load

Los

s A

llow

ed

P0

No

Co

nting

ency

No

rma

l S

yste

m

No

ne

N/A

E

HV

, H

V

No

N

o

P1

Sin

gle

C

on

tin

ge

ncy

No

rma

l S

yste

m

Lo

ss o

f o

ne

of

the

follo

win

g:

1.

Ge

ne

rato

r

2.

Tra

nsm

issio

n C

ircuit

3.

Tra

nsfo

rme

r 5

4.

Sh

un

t D

evic

e 6

3Ø

E

HV

, H

V

No

9

No

12

5.

Sin

gle

Po

le o

f a

DC

lin

e

SL

G

P2

Sin

gle

C

on

tin

ge

ncy

No

rma

l S

yste

m

1.

Op

en

ing o

f a

lin

e s

ection

w/o

a f

ault 7

N

/A

EH

V,

HV

N

o9

No

12

2.

Bu

s S

ection

Fau

lt

SL

G

EH

V

No

9

No

HV

Y

es

Ye

s

3.

Inte

rnal B

rea

ke

r F

ault 8

(no

n-B

us-t

ie B

reake

r)

SL

G

EH

V

No

9

No

HV

Y

es

Ye

s

4.

Inte

rnal B

rea

ke

r F

ault (

Bus-t

ie B

rea

ke

r) 8

S

LG

E

HV

, H

V

Ye

s

Ye

s

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

9

Cat

egor

y In

itial

Con

ditio

n

Even

t 1 Fa

ult T

ype

2 B

ES L

evel

3 In

terr

uptio

n of

Firm

Tr

ansm

issi

on

Serv

ice

Allo

wed

4 N

on-C

onse

quen

tial

Load

Los

s A

llow

ed

P3

Mu

ltip

le

Co

ntin

ge

ncy

Lo

ss o

f g

en

era

tor

un

it

follo

we

d b

y S

yste

m

ad

justm

en

ts9

Lo

ss o

f o

ne

of

the

follo

win

g:

1.

Ge

ne

rato

r

2.

Tra

nsm

issio

n C

ircuit

3.

Tra

nsfo

rme

r 5

4.

Sh

un

t D

evic

e 6

3Ø

E

HV

, H

V

No

9

No

12

5.

Sin

gle

po

le o

f a

DC

lin

e

SL

G

P4

Mu

ltip

le

Co

ntin

ge

ncy

(Fau

lt pl

us s

tuck

br

eake

r10)

No

rma

l S

yste

m

Lo

ss o

f m

ultip

le e

lem

en

ts c

ause

d b

y a

stu

ck

bre

ake

r 1

0(n

on

-Bus-t

ie B

reake

r) a

ttem

ptin

g to

cle

ar

a F

au

lt o

n o

ne

of

the

fo

llow

ing

:

1.

Ge

ne

rato

r

2.

Tra

nsm

issio

n C

ircuit

3.

Tra

nsfo

rme

r 5

4.

Sh

un

t D

evic

e 6

5.

Bu

s S

ection

SL

G

EH

V

No

9

No

HV

Y

es

Ye

s

6.

Lo

ss o

f m

ultip

le e

lem

en

ts c

ause

d b

y a

stu

ck b

rea

ke

r10 (

Bu

s-t

ie B

rea

ke

r)

att

em

pting

to c

lea

r a F

ault o

n th

e

asso

cia

ted b

us

SL

G

EH

V,

HV

Y

es

Ye

s

P5

Mu

ltip

le

Co

ntin

ge

ncy

(Fau

lt pl

us re

lay

failu

re to

op

erat

e)

No

rma

l S

yste

m

De

laye

d F

au

lt C

lea

rin

g d

ue

to

th

e f

ailu

re o

f a

n

on

-re

du

nda

nt

rela

y1

3 p

rote

ctin

g t

he F

aulte

d

ele

me

nt

to o

pe

rate

as d

esig

ned

, fo

r o

ne

of

the

follo

win

g:

1.

Ge

ne

rato

r

2.

Tra

nsm

issio

n C

ircuit

3.

Tra

nsfo

rme

r 5

4.

Sh

un

t D

evic

e 6

5.

Bu

s S

ection

SL

G

EH

V

No

9

No

HV

Y

es

Ye

s

P6

Mu

ltip

le

Co

ntin

ge

ncy

(Tw

o ov

erla

ppin

g si

ngle

s)

Lo

ss o

f o

ne

of

the

fo

llow

ing

fo

llow

ed

by

Syste

m a

dju

stm

en

ts.9

1.

Tra

nsm

issio

n C

ircuit

2.

Tra

nsfo

rme

r 5

3.

Sh

un

t D

evic

e6

4.

Sin

gle

pole

of a

DC

lin

e

Lo

ss o

f o

ne

of

the

follo

win

g:

1.

Tra

nsm

issio

n C

ircuit

2.

Tra

nsfo

rme

r 5

3.

Sh

un

t D

evic

e 6

3Ø

E

HV

, H

V

Ye

s

Ye

s

4.

Sin

gle

po

le o

f a

DC

lin

e

SL

G

EH

V,

HV

Y

es

Ye

s

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

10

Cat

egor

y In

itial

Con

ditio

n

Even

t 1 Fa

ult T

ype

2 B

ES L

evel

3 In

terr

uptio

n of

Firm

Tr

ansm

issi

on

Serv

ice

Allo

wed

4 N

on-C

onse

quen

tial

Load

Los

s A

llow

ed

P7

Mu

ltip

le

Co

ntin

ge

ncy

(Com

mon

S

truct

ure)

No

rma

l S

yste

m

Th

e lo

ss o

f:

1. A

ny t

wo

ad

jacen

t (v

ert

ica

lly o

r h

ori

zo

nta

lly)

cir

cuits o

n c

om

mo

n

str

uctu

re 1

1

2. L

oss o

f a

bip

ola

r D

C lin

e

SL

G

EH

V,

HV

Y

es

Ye

s

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

11

Ta

ble

1 –

Stea

dy S

tate

& S

tabi

lity

Perf

orm

ance

Ext

rem

e Ev

ents

Stea

dy S

tate

& S

tabi

lity

For

all

extr

em

e e

ve

nts

evalu

ate

d:

a.

Sim

ula

te t

he r

em

oval of

all

ele

ments

that

Pro

tectio

n S

yste

ms a

nd a

uto

matic c

ontr

ols

are

expecte

d to d

iscon

nect fo

r each C

on

tinge

ncy.

b.

Sim

ula

te N

orm

al C

learing

unle

ss o

therw

ise

specifie

d.

Stea

dy S

tate

1.

Loss o

f a s

ing

le g

en

era

tor,

Tra

nsm

issio

n C

ircu

it, sin

gle

pole

of

a D

C

Lin

e, shu

nt d

evic

e, or

transfo

rmer

forc

ed o

ut of

serv

ice

follo

wed b

y

anoth

er

sin

gle

ge

nera

tor,

Tra

nsm

issio

n C

ircu

it, sin

gle

pole

of

a

diffe

rent D

C L

ine

, shun

t de

vic

e,

or

transfo

rmer

forc

ed o

ut of

serv

ice

prior

to S

yste

m a

dju

stm

ents

.

2.

Local are

a e

vents

aff

ecting t

he T

ransm

issio

n S

yste

m s

uch a

s:

a.

Loss o

f a to

wer

line w

ith

thre

e o

r m

ore

circuits.1

1

b.

Loss o

f all

Tra

nsm

issio

n lin

es o

n a

com

mon R

ight-

of-

Way

11.

c.

Loss o

f a s

witchin

g s

tatio

n o

r substa

tion (

loss o

f one v

olta

ge

level plu

s tra

nsfo

rmers

).

d.

Loss o

f all

gen

era

ting u

nits a

t a g

en

era

ting s

tatio

n.

e.

Loss o

f a larg

e L

oad o

r m

ajo

r Loa

d c

ente

r.

3.

Wid

e a

rea e

ve

nts

aff

ecting t

he T

ransm

issio

n S

yste

m b

ased o

n

Syste

m topo

log

y s

uch a

s:

a.

Loss o

f tw

o g

enera

tin

g s

tations r

esultin

g f

rom

conditio

ns s

uch

as:

i.

Loss o

f a larg

e g

as p

ipelin

e into

a r

egio

n o

r m

ultip

le

regio

ns that

ha

ve

sig

nific

an

t gas-f

ired g

enera

tio

n.

ii.

Loss o

f th

e u

se o

f a larg

e b

od

y o

f w

ate

r as t

he c

oolin

g

sourc

e f

or

genera

tio

n.

iii.

Wild

fire

s.

iv.

Se

vere

weath

er,

e.g

., h

urr

icanes, to

rnado

es, etc

.

v.

A s

uccessfu

l cyber

att

ack.

vi.

Shutd

ow

n o

f a n

ucle

ar

po

wer

pla

nt(

s)

and

rela

ted

facili

ties f

or

a d

ay o

r m

ore

for

com

mon c

auses s

uch

as p

roble

ms w

ith s

imila

rly d

esig

ned p

lants

.

b.

Oth

er

events

based

up

on o

pera

ting e

xperi

ence t

hat m

ay

result in w

ide

are

a d

istu

rba

nces.

Stab

ility

1.

With a

n initia

l cond

itio

n o

f a

sin

gle

genera

tor,

Tra

nsm

issio

n c

ircu

it,

sin

gle

pole

of

a D

C lin

e, sh

unt d

evic

e,

or

transfo

rmer

forc

ed o

ut

of

serv

ice,

app

ly a

3Ø

fault o

n a

noth

er

sin

gle

genera

tor,

Tra

nsm

issio

n

circuit, sin

gle

pole

of

a d

iffe

rent D

C lin

e, sh

unt

de

vic

e,

or

transfo

rmer

prior

to S

yste

m a

dju

stm

ents

.

2.

Local or

wid

e a

rea e

vents

aff

ecting th

e T

ransm

issio

n S

yste

m s

uch a

s:

a.

3Ø

fault o

n g

enera

tor

with s

tuck b

reaker1

0 o

r a r

ela

y f

ailu

re1

3

resultin

g in D

ela

ye

d F

ault C

leari

ng

.

b.

3Ø

fault o

n T

ransm

issio

n c

ircuit w

ith s

tuck b

reaker1

0 o

r a r

ela

y

failu

re1

3 r

esultin

g in

De

laye

d F

au

lt C

leari

ng.

c.

3Ø

fault o

n tra

nsfo

rmer

with s

tuck b

reaker1

0 o

r a r

ela

y f

ailu

re1

3

resultin

g in D

ela

ye

d F

ault C

leari

ng

.

d.

3Ø

fault o

n b

us s

ection

with s

tuck b

reaker1

0 o

r a r

ela

y f

ailu

re1

3

resultin

g in D

ela

ye

d F

ault C

leari

ng

.

e.

3Ø

inte

rna

l bre

aker

fault.

f.

Oth

er

events

based

up

on o

pera

ting e

xperi

ence, such

as

consid

era

tio

n o

f in

itia

ting e

ven

ts that

experi

ence s

ugg

ests

ma

y

result in w

ide

are

a d

istu

rba

nces

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

12

Tabl

e 1

– St

eady

Sta

te &

Sta

bilit

y Pe

rfor

man

ce F

ootn

otes

(P

lann

ing

Even

ts a

nd E

xtre

me

Even

ts)

1.

If the e

vent

an

aly

ze

d in

vo

lves B

ES

ele

ments

at m

ultip

le S

yste

m v

oltage le

ve

ls, th

e lo

west S

yste

m v

oltag

e le

ve

l of

the e

lem

ent(

s)

rem

oved f

or

the a

na

lyze

d

eve

nt d

ete

rmin

es the s

tate

d p

erf

orm

ance c

rite

ria r

eg

ard

ing a

llow

ances f

or

inte

rru

ptio

ns o

f F

irm

Tra

nsm

issio

n S

erv

ice a

nd N

on-C

onseq

uential Loa

d L

oss.

2.

Unle

ss s

pecifie

d o

therw

ise,

sim

ula

te N

orm

al C

learin

g o

f fa

ults. S

ingle

lin

e to

gro

und (

SLG

) or

thre

e-p

hase (

3Ø

) are

the f

au

lt t

yp

es that

must be e

valu

ate

d in

Sta

bili

ty s

imula

tions f

or

the e

ve

nt d

escribed

. A

3Ø

or

a d

ou

ble

lin

e t

o g

roun

d f

ault s

tud

y in

dic

ating

the

crite

ria a

re b

ein

g m

et is

suff

icie

nt e

vid

ence t

hat

a S

LG

conditio

n w

ould

als

o m

eet th

e c

rite

ria.

3.

Bulk

Ele

ctr

ic S

yste

m (

BE

S)

leve

l re

fere

nces inclu

de e

xtr

a-h

igh v

oltage

(E

HV

) F

acili

ties d

efined a

s g

rea

ter

tha

n 3

00kV

and h

igh v

oltag

e (

HV

) F

acili

ties d

efined

as the 3

00kV

an

d lo

wer

vo

ltage S

yste

ms. T

he d

esig

natio

n o

f E

HV

and H

V is u

se

d to d

istingu

ish b

etw

een s

tate

d p

erf

orm

ance c

rite

ria

allo

wa

nces f

or

inte

rru

ption o

f F

irm

Tra

nsm

issio

n S

erv

ice a

nd N

on-C

on

sequen

tia

l L

oa

d L

oss.

4.

Curt

ailm

ent of

Cond

itio

na

l F

irm

Tra

nsm

issio

n S

erv

ice is a

llow

ed w

hen t

he

cond

itio

ns a

nd/o

r e

ve

nts

be

ing s

tudie

d f

orm

ed the b

asis

for

the C

ond

itio

na

l F

irm

T

ransm

issio

n S

erv

ice.

5.

For

non-g

enera

tor

ste

p u

p t

ransfo

rmer

outa

ge e

ve

nts

, th

e r

efe

rence v

oltag

e, as u

sed in f

ootn

ote

1,

applie

s t

o t

he lo

w-s

ide w

ind

ing

(exclu

din

g tert

iary

w

ind

ings).

F

or

ge

nera

tor

and G

en

era

tor

Ste

p U

p tra

nsfo

rmer

outa

ge e

ven

ts, th

e r

efe

rence v

olta

ge a

pp

lies t

o the

BE

S c

onnecte

d v

olta

ge (

hig

h-s

ide o

f th

e

Genera

tor

Ste

p U

p tra

nsfo

rmer)

. R

equir

em

ents

wh

ich a

re a

pplic

ab

le t

o tra

nsfo

rmers

als

o a

pp

ly t

o v

ari

ab

le f

reque

ncy tra

nsfo

rmers

and p

hase s

hifting

transfo

rmers

.

6.

Requ

irem

ents

wh

ich a

re a

pplic

able

to s

hunt

de

vic

es a

lso a

pp

ly t

o F

AC

TS

de

vic

es that

are

con

necte

d to g

rou

nd.

7.

Openin

g o

ne e

nd

of

a lin

e s

ection

withou

t a f

au

lt o

n a

norm

ally

ne

twork

ed T

ransm

issio

n c

ircuit s

uch th

at th

e lin

e is p

ossib

ly s

erv

ing L

oa

d r

adia

l fr

om

a s

ingle

sourc

e p

oin

t.

8.

An inte

rnal bre

aker

fault m

eans a

bre

aker

faili

ng inte

rnally

, th

us c

reating a

Syste

m fault w

hic

h m

ust be c

leare

d b

y p

rote

ction o

n b

oth

sid

es o

f th

e b

reaker.

9.

An o

bje

ctive o

f th

e p

lannin

g p

rocess s

hou

ld b

e t

o m

inim

ize t

he lik

elih

oo

d a

nd m

agnitude

of

inte

rruption o

f F

irm

Tra

nsm

issio

n S

erv

ice f

ollo

win

g C

onting

ency

eve

nts

. C

urt

ailm

ent of

Firm

Tra

nsm

issio

n S

erv

ice is a

llow

ed b

oth

as a

Syste

m a

dju

stm

ent (a

s id

entified in t

he c

olu

mn e

ntitled

‘In

itia

l C

ond

itio

n’) a

nd

a

corr

ective a

ctio

n w

hen a

chie

ve

d t

hro

ug

h t

he a

ppro

pri

ate

re-d

isp

atc

h o

f re

sourc

es o

blig

ate

d t

o r

e-d

ispatc

h,

wh

ere

it ca

n b

e d

em

onstr

ate

d t

hat

Facili

ties,

inte

rnal an

d e

xte

rnal to

the T

ransm

issio

n P

lan

ner’s p

lannin

g r

egio

n, re

main

with

in a

pp

licab

le F

acili

ty R

atin

gs a

nd t

he r

e-d

ispatc

h d

oes n

ot re

sult in

an

y N

on-

Conseq

uentia

l L

oad

Loss. W

here

lim

ited o

ptio

ns f

or

re-d

ispatc

h e

xis

t, s

ensitiv

itie

s a

ssocia

ted w

ith t

he a

va

ilab

ility

of

those r

eso

urc

es s

ho

uld

be c

onsid

ere

d.

10.

A s

tuck b

reaker

means that fo

r a g

ang-o

pera

ted b

reaker,

all

thre

e p

hases o

f th

e b

reaker

have r

em

ain

ed c

losed. F

or

an ind

epe

nde

nt p

ole

op

era

ted (

IPO

) or

an inde

pen

de

nt p

ole

trip

pin

g (

IPT

) bre

aker,

only

on

e p

ole

is a

ssum

ed to r

em

ain

clo

sed. A

stu

ck b

reaker

results in

De

layed F

au

lt C

leari

ng.

11.

Exclu

des c

ircuits th

at share

a c

om

mon s

tructu

re (

Pla

nnin

g e

ven

t P

7,

Extr

em

e e

vent ste

ad

y s

tate

2a)

or

com

mon R

ight-

of-

Wa

y (

Extr

em

e e

vent,

ste

ad

y s

tate

2b)

for

1 m

ile o

r le

ss.

12.

An o

bje

ctive o

f th

e p

lan

nin

g p

rocess is to m

inim

ize t

he lik

elih

ood a

nd m

agnitud

e o

f N

on-C

onse

que

ntial Loa

d L

oss f

ollo

win

g p

lan

nin

g e

vents

. In

lim

ited

circum

sta

nces,

Non-C

onse

quen

tia

l L

oad

Loss m

ay b

e n

eed

ed t

hro

ugho

ut th

e p

lan

nin

g h

ori

zon t

o e

nsure

th

at

BE

S p

erf

orm

ance r

equirem

ents

are

met.

H

ow

ever,

when

Non-C

onse

quen

tia

l L

oad

Loss is u

tiliz

ed u

nder

footn

ote

12 w

ith

in t

he N

ear-

Term

Tra

nsm

issio

n P

lan

nin

g H

ori

zon t

o a

ddre

ss B

ES

perf

orm

ance r

equirem

ents

, such inte

rruption is lim

ited t

o c

ircum

sta

nces w

here

the

Non-C

onsequ

entia

l Lo

ad L

oss m

eets

the c

on

ditio

ns s

ho

wn in A

ttachm

ent

1. In n

o c

ase

can t

he p

lan

ned N

on-C

onsequ

entia

l L

oad L

oss u

nder

footn

ote

12

exceed 7

5 M

W for

US

regis

tere

d e

ntities.

The a

mount

of

pla

nned N

on-

Conseq

uentia

l L

oad

Loss f

or

a n

on-U

S R

eg

iste

red E

ntity

shou

ld b

e im

ple

mente

d in a

manner

that

is c

onsis

tent

with,

or

und

er

the d

irection o

f, th

e a

pplic

ab

le

govern

menta

l a

uth

ority

or

its a

gency in th

e n

on-U

S juri

sdic

tio

n.

13.

App

lies to t

he f

ollo

win

g r

ela

y f

unctio

ns o

r ty

pes:

pilo

t (#

85),

dis

tance (

#21),

diffe

rentia

l (#

87),

curr

ent (#

50,

51,

and 6

7),

voltag

e (

#2

7 &

59),

direction

al (#

32,

&

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

13

Tabl

e 1

– St

eady

Sta

te &

Sta

bilit

y Pe

rfor

man

ce F

ootn

otes

(P

lann

ing

Even

ts a

nd E

xtre

me

Even

ts)

67),

an

d tri

pp

ing (

#86,

& 9

4).


Attachment 1

I. Stakeholder Process

During each Planning Assessment before the use of Non-Consequential Load Loss under footnote 12 is allowed as an element of a Corrective Action Plan in the Near-Term Transmission Planning Horizon of the Planning Assessment, the Transmission Planner or Planning Coordinator shall ensure that the utilization of footnote 12 is reviewed through an open and transparent stakeholder process. The responsible entity can utilize an existing process or develop a new process. .The process must include the following:

1. Meetings must be open to affected stakeholders including applicable regulatory authorities or governing bodies responsible for retail electric service issues

2. Notice must be provided in advance of meetings to affected stakeholders including applicable regulatory authorities or governing bodies responsible for retail electric service issues and include an agenda with:

a. Date, time, and location for the meeting b. Specific location(s) of the planned Non-Consequential Load Loss under footnote

12 c. Provisions for a stakeholder comment period

3. Information regarding the intended purpose and scope of the proposed Non-Consequential Load Loss under footnote 12 (as shown in Section II below) must be made available to meeting participants

4. A procedure for stakeholders to submit written questions or concerns and to receive written responses to the submitted questions and concerns

5. A dispute resolution process for any question or concern raised in #4 above that is not resolved to the stakeholder’s satisfaction

An entity does not have to repeat the stakeholder process for a specific application of footnote 12 utilization with respect to subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific application.

II. Information for Inclusion in Item #3 of the Stakeholder Process

The responsible entity shall document the planned use of Non-Consequential Load Loss under footnote 12 which must include the following:

1. Conditions under which Non-Consequential Load Loss under footnote 12 would be necessary:

a. System Load level and estimated annual hours of exposure at or above that Load level

b. Applicable Contingencies and the Facilities outside their applicable rating due to that Contingency

2. Amount of Non-Consequential Load Loss with: a. The estimated number and type of customers affected


b. An explanation of the effect of the use of Non-Consequential Load Loss under footnote 12 on the health, safety, and welfare of the community

3. Estimated frequency of Non-Consequential Load Loss under footnote 12 based on historical performance

4. Expected duration of Non-Consequential Load Loss under footnote 12 based on historical performance

5. Future plans to alleviate the need for Non-Consequential Load Loss under footnote 12 6. Verification that TPL Reliability Standards performance requirements will be met

following the application of footnote 12 7. Alternatives to Non-Consequential Load Loss considered and the rationale for not

selecting those alternatives under footnote 12 8. Assessment of potential overlapping uses of footnote 12 including overlaps with adjacent

Transmission Planners and Planning Coordinators

III. Instances for which Regulatory Review of Non-Consequential Load Loss under Footnote 12 is Required

Before a Non-Consequential Load Loss under footnote 12 is allowed as an element of a Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must ensure that the applicable regulatory authorities or governing bodies responsible for retail electric service issues do not object to the use of Non-Consequential Load Loss under footnote 12 if either:

1. The voltage level of the Contingency is greater than 300 kV a. If the Contingency analyzed involves BES Elements at multiple System voltage

levels, the lowest System voltage level of the element(s) removed for the analyzed Contingency determines the stated performance criteria regarding allowances for Non-Consequential Load Loss under footnote 12, or

b. For a non-generator step up transformer outage Contingency, the 300 kV limit applies to the low-side winding (excluding tertiary windings). For a generator or generator step up transformer outage Contingency, the 300 kV limit applies to the BES connected voltage (high-side of the Generator Step Up transformer)

2. The planned Non-Consequential Load Loss under footnote 12 is greater than or equal to 25 MW

Once assurance has been received that the applicable regulatory authorities or governing bodies responsible for retail electric service issues do not object to the use of Non-Consequential Load Loss under footnote 12, the Planning Coordinator or Transmission Planner must submit the information outlined in items II.1 through II.8 above to the ERO for a determination of whether there are any Adverse Reliability Impacts caused by the request to utilize footnote 12 for Non-Consequential Load Loss.


C. Measures M1. Each Transmission Planner and Planning Coordinator shall provide evidence, in electronic or

hard copy format, that it is maintaining System models within their respective area, using data consistent with MOD-010 and MOD-012, including items represented in the Corrective Action Plan, representing projected System conditions, and that the models represent the required information in accordance with Requirement R1.

M2. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as electronic or hard copies of its annual Planning Assessment, that it has prepared an annual Planning Assessment of its portion of the BES in accordance with Requirement R2.

M3. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as electronic or hard copies of the studies utilized in preparing the Planning Assessment, in accordance with Requirement R3.

M4. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as electronic or hard copies of the studies utilized in preparing the Planning Assessment in accordance with Requirement R4.

M5. Each Transmission Planner and Planning Coordinator shall provide dated evidence such as electronic or hard copies of the documentation specifying the criteria for acceptable System steady state voltage limits, post-Contingency voltage deviations, and the transient voltage response for its System in accordance with Requirement R5.

M6. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as electronic or hard copies of documentation specifying the criteria or methodology used in the analysis to identify System instability for conditions such as Cascading, voltage instability, or uncontrolled islanding that was utilized in preparing the Planning Assessment in accordance with Requirement R6.

M7. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall provide dated documentation on roles and responsibilities, such as meeting minutes, agreements, and e-mail correspondence that identifies that agreement has been reached on individual and joint responsibilities for performing the required studies and Assessments in accordance with Requirement R7.

M8. Each Planning Coordinator and Transmission Planner shall provide evidence, such as email notices, documentation of updated web pages, postal receipts showing recipient and date; or a demonstration of a public posting, that it has distributed its Planning Assessment results to adjacent Planning Coordinators and adjacent Transmission Planners within 90 days of having completed its Planning Assessment, and to any functional entity who has indicated a reliability need within 30 days of a written request and that the Planning Coordinator or Transmission Planner has provided a documented response to comments received on Planning Assessment results within 90 calendar days of receipt of those comments in accordance with Requirement R8.

D. Compliance 1. Compliance Monitoring Process

1.1 Compliance Enforcement Authority Regional Entity

1.2 Compliance Monitoring Period and Reset Timeframe Not applicable.


1.3 Compliance Monitoring and Enforcement Processes: Compliance Audits

Self-Certifications

Spot Checking

Compliance Violation Investigations

Self-Reporting

Complaints

1.4 Data Retention The Transmission Planner and Planning Coordinator shall each retain data or evidence to show compliance as identified unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation:

• The models utilized in the current in-force Planning Assessment and one previous Planning Assessment in accordance with Requirement R1 and Measure M1.

• The Planning Assessments performed since the last compliance audit in accordance with Requirement R2 and Measure M2.

• The studies performed in support of its Planning Assessments since the last compliance audit in accordance with Requirement R3 and Measure M3.

• The studies performed in support of its Planning Assessments since the last compliance audit in accordance with Requirement R4 and Measure M4.

• The documentation specifying the criteria for acceptable System steady state

voltage limits, post-Contingency voltage deviations, and transient voltage

response since the last compliance audit in accordance with Requirement R5 and Measure M5.

• The documentation specifying the criteria or methodology utilized in the analysis to identify System instability for conditions such as Cascading, voltage instability, or uncontrolled islanding in support of its Planning Assessments since the last compliance audit in accordance with Requirement R6 and Measure M6.

• The current, in force documentation for the agreement(s) on roles and responsibilities, as well as documentation for the agreements in force since the last compliance audit, in accordance with Requirement R7 and Measure M7.

The Planning Coordinator shall retain data or evidence to show compliance as identified unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation:

• Three calendar years of the notifications employed in accordance with Requirement R8 and Measure M8.

If a Transmission Planner or Planning Coordinator is found non-compliant, it shall keep information related to the non-compliance until found compliant or the time periods specified above, whichever is longer.

1.5 Additional Compliance Information None

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

18

2. V

iola

tion

Seve

rity

Leve

ls

Lo

wer

VSL

M

oder

ate

VSL

Hig

h VS

L Se

vere

VSL

R1

The r

esponsib

le e

ntity

’s S

yste

m

model fa

iled

to r

epre

sent

one o

f th

e

Requ

irem

ent R

1,

Part

s 1

.1.1

th

roug

h 1

.1.6

.

The r

esponsib

le e

ntity

’s S

yste

m

model fa

iled

to r

epre

sent

two o

f th

e

Requ

irem

ent R

1,

Part

s 1

.1.1

thro

ugh

1.1

.6.

The r

esponsib

le e

ntity

’s S

yste

m

model fa

iled

to r

epre

sent

thre

e o

f th

e

Requ

irem

ent R

1,

Part

s 1

.1.1

thro

ugh

1.1

.6.

The r

esponsib

le e

ntity

’s S

yste

m m

odel

faile

d t

o r

epre

sent fo

ur

or

more

of

the

Requ

irem

ent R

1,

Part

s 1

.1.1

thro

ugh

1.1

.6.

OR

The r

esponsib

le e

ntity

’s S

yste

m m

odel

did

not re

pre

sent

pro

jecte

d S

yste

m

conditio

ns a

s d

escrib

ed in R

equ

irem

ent

R1.

OR

The r

esponsib

le e

ntity

’s S

yste

m m

odel

did

not

use d

ata

co

nsis

tent

with t

hat

pro

vid

ed in a

ccord

ance w

ith the

MO

D-

010 a

nd M

OD

-01

2 s

tan

dard

s a

nd o

ther

sourc

es, in

clu

din

g ite

ms r

epre

sente

d in

the C

orr

ective A

ctio

n P

lan

.

R2

The r

esponsib

le e

ntity

fa

iled to

com

ply

with R

eq

uirem

ent R

2, P

art

2.6

.

The r

esponsib

le e

ntity

fa

iled to

com

ply

with R

eq

uirem

ent R

2, P

art

2.3

or

Part

2.8

.

The r

esponsib

le e

ntity

fa

iled to

com

ply

with o

ne o

f th

e f

ollo

win

g

Part

s o

f R

eq

uirem

ent R

2:

Part

2.1

, P

art

2.2

, P

art

2.4

, P

art

2.5

, or

Part

2.7

.

The r

esponsib

le e

ntity

fa

iled to c

om

ply

w

ith t

wo o

r m

ore

of

the f

ollo

win

g P

art

s

of

Requir

em

ent R

2:

Part

2.1

, P

art

2.2

, P

art

2.4

, or

Part

2.7

.

OR

The r

esponsib

le e

ntity

do

es n

ot

ha

ve a

com

ple

ted a

nnua

l P

lann

ing

A

ssessm

ent.

R3

The r

esponsib

le e

ntity

did

not

ide

ntify

pla

nn

ing e

vents

as

described

in

Req

uirem

ent

R3, P

art

3.4

or

extr

em

e e

vents

as d

escribed

in R

equ

irem

ent R

3,

Part

3.5

.

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in R

eq

uirem

ent

R3, P

art

3.1

to

dete

rmin

e t

hat th

e

BE

S m

eets

the p

erf

orm

ance

requirem

ents

for

one o

f th

e c

ate

gori

es

(P2 thro

ugh

P7)

in T

able

1.

The r

esponsib

le e

ntity

did

not

perf

orm

stu

die

s a

s s

pecifie

d in

R

equ

irem

ent

R3,

Part

3.1

to

dete

rmin

e th

at th

e B

ES

meets

the

perf

orm

ance r

equirem

ents

for

two o

f th

e c

ate

gori

es (

P2

thro

ugh P

7)

in

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in R

eq

uirem

ent

R3,

Part

3.1

to d

ete

rmin

e that

the B

ES

m

eets

the p

erf

orm

ance r

eq

uirem

ents

fo

r th

ree o

r m

ore

of

the c

ate

gori

es (

P2

thro

ug

h P

7)

in T

able

1.

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

19

Lo

wer

VSL

M

oder

ate

VSL

Hig

h VS

L Se

vere

VSL

OR

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in R

eq

uirem

ent

R3, P

art

3.2

to

assess the im

pact of

extr

em

e e

vents

.

Table

1.

OR

The r

esponsib

le e

ntity

did

not

perf

orm

Contin

gency a

naly

sis

as

described

in

Req

uirem

ent

R3, P

art

3.3

.

OR

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s t

o d

ete

rmin

e tha

t th

e B

ES

m

eets

the p

erf

orm

ance r

eq

uirem

ents

fo

r th

e P

0 o

r P

1 c

ate

gori

es in T

able

1.

OR

The r

esponsib

le e

ntity

did

not base

its

stu

die

s o

n c

om

pute

r sim

ula

tion

models

usin

g d

ata

pro

vid

ed

in

Req

uirem

ent R

1.

R4

The r

esponsib

le e

ntity

did

not

ide

ntify

pla

nn

ing e

vents

as

described

in

Req

uirem

ent

R4, P

art

4.4

or

extr

em

e e

vents

as d

escribed

in R

equ

irem

ent R

4,

Part

4.5

.

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in R

eq

uirem

ent

R4, P

art

4.1

to

dete

rmin

e that th

e

BE

S m

eets

the p

erf

orm

ance

requirem

ents

for

one o

f th

e c

ate

gori

es

(P1 thro

ugh

P7)

in T

able

1.

OR

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in R

eq

uirem

ent

R4, P

art

4.2

to

assess the im

pact of

extr

em

e e

vents

.

The r

esponsib

le e

ntity

did

not

perf

orm

stu

die

s a

s s

pecifie

d in

R

equ

irem

ent

R4,

Part

4.1

to

dete

rmin

e th

at th

e B

ES

meets

the

perf

orm

ance r

equirem

ents

for

two o

f th

e c

ate

gori

es (

P1

thro

ugh P

7)

in

Table

1.

OR

The r

esponsib

le e

ntity

did

not

perf

orm

Contin

gency a

naly

sis

as

described

in

Req

uirem

ent

R4, P

art

4.3

.

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in R

eq

uirem

ent

R4,

Part

4.1

to d

ete

rmin

e that

the B

ES

m

eets

the p

erf

orm

ance r

eq

uirem

ents

fo

r th

ree o

r m

ore

of

the c

ate

gori

es (

P1

thro

ug

h P

7)

in T

able

1.

OR

The r

esponsib

le e

ntity

did

not base

its

stu

die

s o

n c

om

pute

r sim

ula

tion

models

usin

g d

ata

pro

vid

ed

in

Req

uirem

ent R

1.

R5

N/A

N

/A

N/A

T

he r

esponsib

le e

ntity

do

es n

ot

ha

ve

crite

ria f

or

accepta

ble

Syste

m s

tead

y

sta

te v

oltag

e lim

its, post-

Continge

ncy

vo

ltag

e d

evia

tions,

or

the tra

nsie

nt

vo

ltag

e r

espo

nse f

or

its S

yste

m.

R6

N/A

N

/A

N/A

T

he r

esponsib

le e

ntity

fa

iled to d

efine

and d

ocum

ent th

e c

rite

ria

or

meth

odolo

gy f

or

Syste

m in

sta

bili

ty u

se

d

with

in its

an

aly

sis

as d

escribed in

Requ

irem

ent R

6.

Stan

dard

TPL

-001

-4 —

Tra

nsm

issi

on S

yste

m P

lann

ing

Perf

orm

ance

Req

uire

men

ts

20

Lo

wer

VSL

M

oder

ate

VSL

Hig

h VS

L Se

vere

VSL

R7

N/A

N

/A

N/A

T

he P

lannin

g C

oord

ina

tor,

in

conju

nctio

n w

ith e

ach o

f its

Tra

nsm

issio

n P

lan

ners

, fa

iled to

dete

rmin

e a

nd ide

ntify

ind

ivid

ual or

join

t re

sponsib

ilities f

or

perf

orm

ing r

eq

uire

d

stu

die

s.

R8

The r

esponsib

le e

ntity

dis

trib

ute

d its

P

lann

ing

Assessm

ent re

sults t

o

adja

cent

Pla

nn

ing C

oord

inato

rs a

nd

adja

cent T

ransm

issio

n P

lanners

but

it w

as m

ore

than

90 d

ays b

ut

less

than o

r eq

ua

l to

120

da

ys f

ollo

win

g

its c

om

ple

tio

n.

OR

,

The r

esponsib

le e

ntity

dis

trib

ute

d its

P

lann

ing

Assessm

ent re

sults t

o

functiona

l e

ntities h

avin

g a

relia

bili

ty

rela

ted n

eed

who

requ

este

d the

P

lann

ing

Assessm

ent in

wri

ting

but

it w

as m

ore

than

30 d

ays b

ut

less

than o

r eq

ua

l to

40 d

ays f

ollo

win

g

the r

eq

uest.

The r

esponsib

le e

ntity

dis

trib

ute

d its

P

lann

ing

Assessm

ent re

sults t

o

adja

cent

Pla

nn

ing C

oord

inato

rs a

nd

adja

cent T

ransm

issio

n P

lanners

but

it

was m

ore

than 1

20 d

ays b

ut

less than

or

equ

al to

130 d

ays f

ollo

win

g its

com

ple

tion.

OR

,

The r

esponsib

le e

ntity

dis

trib

ute

d its

P

lann

ing

Assessm

ent re

sults t

o

functiona

l e

ntities h

avin

g a

relia

bili

ty

rela

ted n

eed

who

requ

este

d the

P

lann

ing

Assessm

ent in

wri

ting

but

it

was m

ore

than 4

0 d

ays b

ut

less tha

n

or

equ

al to

50 d

ays f

ollo

win

g the

re

quest.

The r

esponsib

le e

ntity

dis

trib

ute

d its

P

lann

ing

Assessm

ent re

sults t

o

adja

cent

Pla

nn

ing C

oord

inato

rs a

nd

adja

cent T

ransm

issio

n P

lanners

but

it w

as m

ore

than

13

0 d

ays b

ut

less

than o

r eq

ua

l to

14

0 d

ays f

ollo

win

g

its c

om

ple

tio

n.

OR

,

The r

esponsib

le e

ntity

dis

trib

ute

d its

P

lann

ing

Assessm

ent re

sults t

o

functiona

l e

ntities h

avin

g a

relia

bili

ty

rela

ted n

eed

who

requ

este

d the

P

lann

ing

Assessm

ent in

wri

ting

but

it

was m

ore

than 5

0 d

ays b

ut

less tha

n

or

equ

al to

60 d

ays f

ollo

win

g the

re

quest.

The r

esponsib

le e

ntity

dis

trib

ute

d its

P

lann

ing

Assessm

ent re

sults t

o

adja

cent

Pla

nn

ing C

oord

inato

rs a

nd

adja

cent T

ransm

issio

n P

lanners

but

it

was m

ore

than 1

40 d

ays f

ollo

win

g its

com

ple

tion.

OR

The r

esponsib

le e

ntity

did

not d

istr

ibute

its P

lan

nin

g A

ssessm

ent re

sults t

o

adja

cent

Pla

nn

ing C

oord

inato

rs a

nd

adja

cent T

ransm

issio

n P

lanners

.

OR

The r

esponsib

le e

ntity

dis

trib

ute

d its

P

lann

ing

Assessm

ent re

sults t

o

functiona

l e

ntities h

avin

g a

relia

bili

ty

rela

ted n

eed

who

requ

este

d the

P

lann

ing

Assessm

ent in

wri

ting

but

it

was m

ore

than 6

0 d

ays f

ollo

win

g th

e

request.

OR

The r

esponsib

le e

ntity

did

not d

istr

ibute

its P

lan

nin

g A

ssessm

ent re

sults t

o

functiona

l e

ntities h

avin

g a

relia

bili

ty

rela

ted n

eed

who

requ

este

d the

P

lann

ing

Assessm

ent in

wri

ting

.


E. Regional Variances None.

Version History

Version Date Action Change Tracking 0 April 1, 2005 Effective Date New

0 February 8, 2005 BOT Approval Revised

0 June 3, 2005 Fixed reference in M1 to read TPL-001-0 R2.1 and TPL-001-0 R2.2

Errata

0 July 24, 2007 Corrected reference in M1. to read TPL-001-0 R1 and TPL-001-0 R2.

Errata

0.1 October 29, 2008 BOT adopted errata changes; updated version number to “0.1”

Errata

0.1 May 13, 2009 FERC Approved – Updated Effective Date and Footer Revised

1 Approved by Board of Trustees February 17, 2011

Revised footnote ‘b’ pursuant to FERC Order RM06-16-009

Revised (Project 2010-11)

2 August 4, 2011 Revision of TPL-001-1; includes merging and upgrading requirements of TPL-001-0, TPL-002-0, TPL-003-0, and TPL-004-0 into one, single, comprehensive, coordinated standard: TPL-001-2; and retirement of TPL-005-0 and TPL-006-0.

Project 2006-02 – complete revision

2 August 4, 2011 Adopted by Board of Trustees

1 April 19, 2012 FERC issued Order 762 remanding TPL-001-1, TPL-002-1b, TPL-003-1a, and TPL-004-1. FERC also issued a NOPR proposing to remand TPL-001-2. NERC has been directed to revise footnote 'b' in accordance with the directives of Order Nos. 762 and 693.

3 February 7, 2013 TPL-001-3 was created after the Board of Trustees approved the revised footnote ‘b’ in TPL-002-2b, which was balloted and appended to:

Adopted by the NERC Board of Trustees.

TPL-001-0.1, TPL-002-0b, TPL-003-0a, and TPL-004-0.

4 February 7, 2013 TPL-001-4 was adopted by the Board of Trustees as TPL-001-3, but a discrepancy in numbering was identified and corrected prior to filing with the regulatory agencies.

Adopted by the NERC Board of Trustees.

4 October 17, 2013 FERC Order issued approving TPL-001-4 (Order effective December 23, 2013).

http://www.nerc.com/files/Order_TPL-002-0b_RM11-18.pdf�




http://www.nerc.com/files/order_693.pdf�

http://www.nerc.com/files/order_693.pdf�


Appendix A

Reliability Standards Assessed by BC Hydro

Red-lined

Standard TPL-001-40.1 —Transmission System Planning Performance RequirementsUnder Normal (No Contingency)Conditions (Category A)

1

A. Introduction

1. Title: Transmission System Planning Performance RequirementsUnder Normal (No Contingency) Conditions (Category A)

2. Number: TPL-001-40.1

3. Purpose: Establish Transmission system planning performance requirements within the

planning horizon to develop a Bulk Electric System (BES) that will operate reliably over a

broad spectrum of System conditions and following a wide range of probable Contingencies.

3. Purpose: System simulations and associated assessments are needed periodically to ensure

that reliable systems are developed that meet specified performance requirements with

sufficient lead time, and continue to be modified or upgraded as necessary to meet present

and future system needs.

4. Applicability:

4.1. Functional Entity

4.1.4.1.1. Planning Coordinator.Authority

4.2.4.1.2. Transmission Planner.

5. Effective Date: Requirements R1 and R7 as well as the definitions shall become effective on

the first day of the first calendar quarter, 12 months after applicable regulatory approval. In

those jurisdictions where regulatory approval is not required, Requirements R1 and R7 become

effective on the first day of the first calendar quarter, 12 months after Board of Trustees

adoption or as otherwise made effective pursuant to the laws applicable to such ERO

governmental authorities.

Except as indicated below, Requirements R2 through R6 and Requirement R8 shall become

effective on the first day of the first calendar quarter, 24 months after applicable regulatory

approval. In those jurisdictions where regulatory approval is not required, all requirements,

except as noted below, go into effect on the first day of the first calendar quarter, 24 months

after Board of Trustees adoption or as otherwise made effective pursuant to the laws

applicable to such ERO governmental authorities.

For 84 calendar months beginning the first day of the first calendar quarter following

applicable regulatory approval, or in those jurisdictions where regulatory approval is not

required on the first day of the first calendar quarter 84 months after Board of Trustees

adoption or as otherwise made effective pursuant to the laws applicable to such ERO

governmental authorities, Corrective Action Plans applying to the following categories of

Contingencies and events identified in TPL-001-4, Table 1 are allowed to include Non-

Consequential Load Loss and curtailment of Firm Transmission Service (in accordance with

Requirement R2, Part 2.7.3.) that would not otherwise be permitted by the requirements of

TPL-001-4:

P1-2 (for controlled interruption of electric supply to local network customers

connected to or supplied by the Faulted element)

P1-3 (for controlled interruption of electric supply to local network customers

connected to or supplied by the Faulted element)

P2-1

P2-2 (above 300 kV)

P2-3 (above 300 kV)

P3-1 through P3-5

Anita Swanson

Cross-Out


2

P4-1 through P4-5 (above 300 kV)

P5 (above 300 kV)

B. Requirements

R1. Each Transmission Planner and Planning Coordinator shall maintain System models within its

respective area for performing the studies needed to complete its Planning Assessment. The

models shall use data consistent with that provided in accordance with the MOD-010 and

MOD-012 standards, supplemented by other sources as needed, including items represented in

the Corrective Action Plan, and shall represent projected System conditions. This establishes

Category P0 as the normal System condition in Table 1. [Violation Risk Factor: Medium]

[Time Horizon: Long-term Planning]

1.1. System models shall represent:

1.1.1. Existing Facilities

1.1.2. Known outage(s) of generation or Transmission Facility(ies) with a duration

of at least six months.

1.1.3. New planned Facilities and changes to existing Facilities

1.1.4. Real and reactive Load forecasts

1.1.5. Known commitments for Firm Transmission Service and Interchange

1.1.6. Resources (supply or demand side) required for Load

R2. Each Transmission Planner and Planning Coordinator shall prepare an annual Planning

Assessment of its portion of the BES. This Planning Assessment shall use current or qualified

past studies (as indicated in Requirement R2, Part 2.6), document assumptions, and document

summarized results of the steady state analyses, short circuit analyses, and Stability analyses.

[Violation Risk Factor: High] [Time Horizon: Long-term Planning]

2.1. For the Planning Assessment, the Near-Term Transmission Planning Horizon portion

of the steady state analysis shall be assessed annually and be supported by current

annual studies or qualified past studies as indicated in Requirement R2, Part 2.6.

Qualifying studies need to include the following conditions:

2.1.1. System peak Load for either Year One or year two, and for year five.


2.1.3. P1 events in Table 1, with known outages modeled as in Requirement R1,

Part 1.1.2, under those System peak or Off-Peak conditions when known

outages are scheduled.

2.1.4. For each of the studies described in Requirement R2, Parts 2.1.1 and 2.1.2,

sensitivity case(s) shall be utilized to demonstrate the impact of changes to

the basic assumptions used in the model. To accomplish this, the sensitivity

analysis in the Planning Assessment must vary one or more of the following

conditions by a sufficient amount to stress the System within a range of

credible conditions that demonstrate a measurable change in System

response :

Real and reactive forecasted Load.

Expected transfers.

Expected in service dates of new or modified Transmission Facilities.

Reactive resource capability.

Anita Swanson

Cross-Out


3

Generation additions, retirements, or other dispatch scenarios.

Controllable Loads and Demand Side Management.

Duration or timing of known Transmission outages.

2.1.5. When an entity’s spare equipment strategy could result in the unavailability

of major Transmission equipment that has a lead time of one year or more

(such as a transformer), the impact of this possible unavailability on System

performance shall be studied. The studies shall be performed for the P0, P1,

and P2 categories identified in Table 1 with the conditions that the System is

expected to experience during the possible unavailability of the long lead

time equipment.

2.2. For the Planning Assessment, the Long-Term Transmission Planning Horizon portion

of the steady state analysis shall be assessed annually and be supported by the

following annual current study, supplemented with qualified past studies as indicated

in Requirement R2, Part 2.6:

2.2.1. A current study assessing expected System peak Load conditions for one of

the years in the Long-Term Transmission Planning Horizon and the rationale

for why that year was selected.

2.3. The short circuit analysis portion of the Planning Assessment shall be conducted

annually addressing the Near-Term Transmission Planning Horizon and can be

supported by current or past studies as qualified in Requirement R2, Part 2.6. The

analysis shall be used to determine whether circuit breakers have interrupting

capability for Faults that they will be expected to interrupt using the System short

circuit model with any planned generation and Transmission Facilities in service

which could impact the study area.

2.4. For the Planning Assessment, the Near-Term Transmission Planning Horizon portion

of the Stability analysis shall be assessed annually and be supported by current or past

studies as qualified in Requirement R2, Part2.6. The following studies are required:

2.4.1. System peak Load for one of the five years. System peak Load levels shall

include a Load model which represents the expected dynamic behavior of

Loads that could impact the study area, considering the behavior of induction

motor Loads. An aggregate System Load model which represents the overall

dynamic behavior of the Load is acceptable.


2.4.3. For each of the studies described in Requirement R2, Parts 2.4.1 and 2.4.2,

sensitivity case(s) shall be utilized to demonstrate the impact of changes to

the basic assumptions used in the model. To accomplish this, the sensitivity

analysis in the Planning Assessment must vary one or more of the following

conditions by a sufficient amount to stress the System within a range of

credible conditions that demonstrate a measurable change in performance:

Load level, Load forecast, or dynamic Load model assumptions.

Expected transfers.

Expected in service dates of new or modified Transmission Facilities.

Reactive resource capability.

Generation additions, retirements, or other dispatch scenarios.

2.5. For the Planning Assessment, the Long-Term Transmission Planning Horizon portion

of the Stability analysis shall be assessed to address the impact of proposed material


4

generation additions or changes in that timeframe and be supported by current or past

studies as qualified in Requirement R2, Part2.6 and shall include documentation to

support the technical rationale for determining material changes.

2.6. Past studies may be used to support the Planning Assessment if they meet the

following requirements:

2.6.1. For steady state, short circuit, or Stability analysis: the study shall be five

calendar years old or less, unless a technical rationale can be provided to

demonstrate that the results of an older study are still valid.

2.6.2. For steady state, short circuit, or Stability analysis: no material changes have

occurred to the System represented in the study. Documentation to support

the technical rationale for determining material changes shall be included.

2.7. For planning events shown in Table 1, when the analysis indicates an inability of the

System to meet the performance requirements in Table 1, the Planning Assessment

shall include Corrective Action Plan(s) addressing how the performance requirements

will be met. Revisions to the Corrective Action Plan(s) are allowed in subsequent

Planning Assessments but the planned System shall continue to meet the performance

requirements in Table 1. Corrective Action Plan(s) do not need to be developed solely

to meet the performance requirements for a single sensitivity case analyzed in

accordance with Requirements R2, Parts 2.1.4 and 2.4.3. The Corrective Action

Plan(s) shall:

2.7.1. List System deficiencies and the associated actions needed to achieve

required System performance. Examples of such actions include:

Installation, modification, retirement, or removal of Transmission and

generation Facilities and any associated equipment.

Installation, modification, or removal of Protection Systems or Special

Protection Systems

Installation or modification of automatic generation tripping as a response to a single or multiple Contingency to mitigate Stability

performance violations.

Installation or modification of manual and automatic generation

runback/tripping as a response to a single or multiple Contingency to

mitigate steady state performance violations.

Use of Operating Procedures specifying how long they will be needed

as part of the Corrective Action Plan.

Use of rate applications, DSM, new technologies, or other initiatives.

2.7.2. Include actions to resolve performance deficiencies identified in multiple

sensitivity studies or provide a rationale for why actions were not necessary.

2.7.3. If situations arise that are beyond the control of the Transmission

Planner or Planning Coordinator that prevent the implementation of a

Corrective Action Plan in the required timeframe, then the Transmission

Planner or Planning Coordinator is permitted to utilize Non-Consequential

Load Loss and curtailment of Firm Transmission Service to correct the

situation that would normally not be permitted in Table 1, provided that the

Transmission Planner or Planning Coordinator documents that they are

taking actions to resolve the situation. The Transmission Planner or

Planning Coordinator shall document the situation causing the problem,

alternatives evaluated, and the use of Non-Consequential Load Loss or


5

curtailment of Firm Transmission Service.

2.7.4. Be reviewed in subsequent annual Planning Assessments for continued

validity and implementation status of identified System Facilities and

Operating Procedures.

2.8. For short circuit analysis, if the short circuit current interrupting duty on circuit

breakers determined in Requirement R2, Part 2.3 exceeds their Equipment Rating, the

Planning Assessment shall include a Corrective Action Plan to address the Equipment

Rating violations. The Corrective Action Plan shall:

2.8.1. List System deficiencies and the associated actions needed to achieve

required System performance.

2.8.2. Be reviewed in subsequent annual Planning Assessments for continued

validity and implementation status of identified System Facilities and

Operating Procedures.

R3. For the steady state portion of the Planning Assessment, each Transmission Planner and

Planning Coordinator shall perform studies for the Near-Term and Long-Term Transmission

Planning Horizons in Requirement R2, Parts 2.1, and 2.2. The studies shall be based on

computer simulation models using data provided in Requirement R1. [Violation Risk Factor:

Medium] [Time Horizon: Long-term Planning]

3.1. Studies shall be performed for planning events to determine whether the BES meets

the performance requirements in Table 1 based on the Contingency list created in

Requirement R3, Part 3.4.

3.2. Studies shall be performed to assess the impact of the extreme events which are

identified by the list created in Requirement R3, Part 3.5.

3.3. Contingency analyses for Requirement R3, Parts 3.1 & 3.2 shall:

3.3.1. Simulate the removal of all elements that the Protection System and other

automatic controls are expected to disconnect for each Contingency without

operator intervention. The analyses shall include the impact of subsequent:

3.3.1.1. Tripping of generators where simulations show generator bus

voltages or high side of the generation step up (GSU) voltages

are less than known or assumed minimum generator steady state

or ride through voltage limitations. Include in the assessment

any assumptions made.

3.3.1.2. Tripping of Transmission elements where relay loadability limits

are exceeded.

3.3.2. Simulate the expected automatic operation of existing and planned devices

designed to provide steady state control of electrical system quantities when

such devices impact the study area. These devices may include equipment

such as phase-shifting transformers, load tap changing transformers, and

switched capacitors and inductors.

3.4. Those planning events in Table 1, that are expected to produce more severe System

impacts on its portion of the BES, shall be identified and a list of those

Contingencies to be evaluated for System performance in Requirement R3, Part 3.1

created. The rationale for those Contingencies selected for evaluation shall be

available as supporting information.

3.4.1. The Planning Coordinator and Transmission Planner shall coordinate with

adjacent Planning Coordinators and Transmission Planners to ensure that


6

Contingencies on adjacent Systems which may impact their Systems are

included in the Contingency list.

3.5. Those extreme events in Table 1 that are expected to produce more severe System

impacts shall be identified and a list created of those events to be evaluated in

Requirement R3, Part 3.2. The rationale for those Contingencies selected for

evaluation shall be available as supporting information. If the analysis concludes

there is Cascading caused by the occurrence of extreme events, an evaluation of

possible actions designed to reduce the likelihood or mitigate the consequences and

adverse impacts of the event(s) shall be conducted.

R4. For the Stability portion of the Planning Assessment, as described in Requirement R2, Parts 2.4

and 2.5, each Transmission Planner and Planning Coordinator shall perform the Contingency

analyses listed in Table 1. The studies shall be based on computer simulation models using

data provided in Requirement R1. [Violation Risk Factor: Medium] [Time Horizon: Long-

term Planning]

4.1. Studies shall be performed for planning events to determine whether the BES meets

the performance requirements in Table 1 based on the Contingency list created in

Requirement R4, Part 4.4.

4.1.1. For planning event P1: No generating unit shall pull out of synchronism. A

generator being disconnected from the System by fault clearing action or by

a Special Protection System is not considered pulling out of synchronism.

4.1.2. For planning events P2 through P7: When a generator pulls out of

synchronism in the simulations, the resulting apparent impedance swings

shall not result in the tripping of any Transmission system elements other

than the generating unit and its directly connected Facilities.

4.1.3. For planning events P1 through P7: Power oscillations shall exhibit

acceptable damping as established by the Planning Coordinator and

Transmission Planner.

4.2. Studies shall be performed to assess the impact of the extreme events which are

identified by the list created in Requirement R4, Part 4.5.

4.3. Contingency analyses for Requirement R4, Parts 4.1 and 4.2 shall :

4.3.1. Simulate the removal of all elements that the Protection System and other

automatic controls are expected to disconnect for each Contingency without

operator intervention. The analyses shall include the impact of subsequent:

4.3.1.1. Successful high speed (less than one second) reclosing and

unsuccessful high speed reclosing into a Fault where high speed

reclosing is utilized.

4.3.1.2. Tripping of generators where simulations show generator bus

voltages or high side of the GSU voltages are less than known or

assumed generator low voltage ride through capability. Include

in the assessment any assumptions made.

4.3.1.3. Tripping of Transmission lines and transformers where transient

swings cause Protection System operation based on generic or

actual relay models.

4.3.2. Simulate the expected automatic operation of existing and planned devices

designed to provide dynamic control of electrical system quantities when

such devices impact the study area. These devices may include equipment

such as generation exciter control and power system stabilizers, static var


7

compensators, power flow controllers, and DC Transmission controllers.

4.4. Those planning events in Table 1 that are expected to produce more severe System

impacts on its portion of the BES, shall be identified, and a list created of those

Contingencies to be evaluated in Requirement R4, Part 4.1. The rationale for those

Contingencies selected for evaluation shall be available as supporting information.

4.4.1. Each Planning Coordinator and Transmission Planner shall coordinate with

adjacent Planning Coordinators and Transmission Planners to ensure that

Contingencies on adjacent Systems which may impact their Systems are

included in the Contingency list.

4.5. Those extreme events in Table 1 that are expected to produce more severe System

impacts shall be identified and a list created of those events to be evaluated in

Requirement R4, Part 4.2. The rationale for those Contingencies selected for

evaluation shall be available as supporting information. If the analysis concludes

there is Cascading caused by the occurrence of extreme events, an evaluation of

possible actions designed to reduce the likelihood or mitigate the consequences of the

event(s) shall be conducted.

R5. Each Transmission Planner and Planning Coordinator shall have criteria for acceptable System

steady state voltage limits, post-Contingency voltage deviations, and the transient voltage

response for its System. For transient voltage response, the criteria shall at a minimum, specify

a low voltage level and a maximum length of time that transient voltages may remain below

that level. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

R6. Each Transmission Planner and Planning Coordinator shall define and document, within their

Planning Assessment, the criteria or methodology used in the analysis to identify System

instability for conditions such as Cascading, voltage instability, or uncontrolled islanding.

[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

R7. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall

determine and identify each entity’s individual and joint responsibilities for performing the

required studies for the Planning Assessment. [Violation Risk Factor: Low] [Time Horizon:

Long-term Planning]

R8. Each Planning Coordinator and Transmission Planner shall distribute its Planning Assessment

results to adjacent Planning Coordinators and adjacent Transmission Planners within 90

calendar days of completing its Planning Assessment, and to any functional entity that has a

reliability related need and submits a written request for the information within 30 days of such

a request. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

8.1. If a recipient of the Planning Assessment results provides documented comments on

the results, the respective Planning Coordinator or Transmission Planner shall provide

a documented response to that recipient within 90 calendar days of receipt of those

comments.

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

issio

n S

yste

m P

lan

nin

g P

erf

orm

an

ce R

eq

uir

em

en

tsU

nd

er

No

rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Cate

go

ry A

)

8

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

iss

ion

Sys

tem

Pla

nn

ing

Pe

rfo

rma

nc

e R

eq

uir

em

en

tsU

nd

er

No

rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Ca

teg

ory

A)

9

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

iss

ion

Sys

tem

Pla

nn

ing

Pe

rfo

rma

nc

e R

eq

uir

em

en

tsU

nd

er

No

rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Ca

teg

ory

A)

1

0

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

issio

n S

yste

m P

lan

nin

g P

erf

orm

an

ce R

eq

uir

em

en

tsU

nd

er

No

rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Cate

go

ry A

)

1

1

Tab

le 1

– S

tead

y S

tate

& S

tab

ilit

y P

erf

orm

an

ce

Extr

em

e E

ven

ts

Ste

ad

y S

tate

& S

tab

ilit

y

For

all

extr

em

e e

vents

evalu

ate

d:

a.

Sim

ula

te the r

em

oval o

f all

ele

ments

that P

rote

ction S

yste

ms a

nd a

uto

matic c

ontr

ols

are

expecte

d to d

isconn

ect fo

r each C

ontin

gency.

b.

Sim

ula

te N

orm

al C

learing u

nle

ss o

therw

ise

specifie

d.

Ste

ad

y S

tate

1.

Loss o

f a s

ing

le g

enera

tor,

Tra

nsm

issio

n C

ircuit, sin

gle

pole

of a D

C

Lin

e, shunt de

vic

e, or

transfo

rmer

forc

ed

out of serv

ice follo

we

d b

y

anoth

er

sin

gle

genera

tor,

Tra

nsm

issio

n C

ircuit, sin

gle

pole

of a

diffe

rent D

C L

ine, shunt devic

e, or

transfo

rmer

forc

ed o

ut of serv

ice

prior

to S

yste

m a

dju

stm

ents

.

2.

Local a

rea e

vents

aff

ecting the T

ransm

issio

n S

yste

m s

uch a

s:

a.

Loss o

f a tow

er

line w

ith thre

e o

r m

ore

circuits.1

1

b.

Loss o

f all

Tra

nsm

issio

n li

nes o

n a

com

mon R

ight-

of-

Wa

y11.

c.

Loss o

f a s

witchin

g s

tation

or

substa

tion

(lo

ss o

f one v

oltage

le

vel p

lus tra

nsfo

rmers

).

d.

Loss o

f all

genera

ting

units a

t a g

enera

ting

sta

tion

.

e.

Loss o

f a larg

e L

oad o

r m

ajo

r Loa

d c

ente

r.

3.

Wid

e a

rea e

vents

aff

ecting the T

ransm

issio

n S

yste

m b

ased o

n

Syste

m topo

log

y s

uch

as:

a.

Loss o

f tw

o g

enera

ting

sta

tions r

esu

ltin

g fro

m c

onditio

ns s

uch

as:

i.

Loss o

f a larg

e g

as p

ipe

line

into

a r

eg

ion

or

multip

le

regio

ns that have s

ignific

ant gas-f

ired g

enera

tion.

ii.

Loss o

f th

e u

se o

f a larg

e b

od

y o

f w

ate

r as the c

oo

ling

sourc

e for

genera

tion.

iii.

Wild

fire

s.

iv.

Severe

weath

er,

e.g

., h

urr

icanes, to

rnadoes, etc

.

v.

A s

uccessfu

l cyber

attack.

vi.

Shutd

ow

n o

f a n

ucle

ar

po

wer

pla

nt(

s)

and r

ela

ted

fa

cili

ties for

a d

ay o

r m

ore

for

com

mon

causes s

uch

as p

roble

ms w

ith s

imila

rly d

esig

ned

pla

nts

.

b.

Oth

er

events

based u

pon o

pera

ting

experience

that m

ay

result in

wid

e a

rea d

istu

rba

nces.

Sta

bilit

y

1.

With a

n in

itia

l cond

itio

n o

f a s

ingle

genera

tor,

Tra

nsm

issio

n c

ircuit,

sin

gle

pole

of a D

C lin

e, shu

nt de

vic

e, or

transfo

rmer

forc

ed o

ut of

serv

ice, apply

a 3

Ø fault o

n a

noth

er

sin

gle

genera

tor,

Tra

nsm

issio

n

circuit, sin

gle

po

le o

f a d

iffe

rent D

C lin

e, sh

unt devic

e, or

transfo

rmer

prior

to S

yste

m a

dju

stm

ents

.

2.

Local o

r w

ide a

rea e

vents

aff

ecting

the T

ransm

issio

n S

yste

m s

uch

as:

a.

3Ø

fault o

n g

enera

tor

with

stu

ck b

reaker1

0 o

r a r

ela

y failu

re13

resultin

g in

Dela

ye

d F

ault C

leari

ng.

b.

3Ø

fault o

n T

ransm

issio

n c

ircuit w

ith s

tuck b

reaker1

0 o

r a r

ela

y

failu

re13 re

sultin

g in

Dela

ye

d F

ault C

learing.

c.

3Ø

fault o

n tra

nsfo

rmer

with s

tuck b

reaker1

0 o

r a r

ela

y failu

re13

resultin

g in

Dela

ye

d F

ault C

leari

ng.

d.

3Ø

fault o

n b

us s

ection w

ith

stu

ck b

reaker1

0 o

r a r

ela

y failu

re13

resultin

g in

Dela

ye

d F

ault C

leari

ng.

e.

3Ø

inte

rna

l bre

aker

fault.

f.

Oth

er

events

based u

pon o

pera

ting e

xperience, such

as

consid

era

tion

of in

itia

tin

g e

vents

that experience

sugge

sts

ma

y

result in

wid

e a

rea d

istu

rbances

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

iss

ion

Sys

tem

Pla

nn

ing

Pe

rfo

rma

nc

e R

eq

uir

em

en

tsU

nd

er

No

rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Ca

teg

ory

A)

1

2

Ta

ble

1 –

Ste

ad

y S

tate

& S

tab

ilit

y P

erf

orm

an

ce

Fo

otn

ote

s

(Pla

nn

ing

Ev

en

ts a

nd

Ex

tre

me

Ev

en

ts)

1.

If the e

ve

nt a

na

lyze

d in

vo

lve

s B

ES

ele

me

nts

at m

ultip

le S

yste

m v

olta

ge le

ve

ls, th

e lo

we

st S

yste

m v

olta

ge le

ve

l of th

e e

lem

ent(

s)

rem

oved

fo

r th

e a

na

lyze

d

eve

nt d

ete

rmin

es the s

tate

d p

erf

orm

ance

crite

ria

re

ga

rdin

g a

llow

ance

s fo

r in

terr

uptio

ns o

f F

irm

Tra

nsm

issio

n S

erv

ice a

nd

No

n-C

on

se

qu

en

tia

l Lo

ad L

oss.

2.

Un

less s

pecifie

d o

the

rwis

e, sim

ula

te N

orm

al C

lea

rin

g o

f fa

ults. S

ingle

lin

e to g

rou

nd (

SL

G)

or

thre

e-p

hase

(3

Ø)

are

the fa

ult typ

es that m

ust be e

va

luate

d in

S

tab

ility

sim

ula

tio

ns fo

r th

e e

ve

nt d

escrib

ed

. A

3Ø

or

a d

ou

ble

lin

e to g

rou

nd

fa

ult s

tud

y in

dic

atin

g the c

rite

ria a

re b

ein

g m

et is

su

ffic

ient e

vid

en

ce

that a S

LG

co

nd

itio

n w

ould

als

o m

eet th

e c

rite

ria.

3.

Bu

lk E

lectr

ic S

yste

m (

BE

S)

leve

l re

fere

nces in

clu

de

extr

a-h

igh

vo

lta

ge (

EH

V)

Fa

cili

tie

s d

efin

ed

as g

rea

ter

than 3

00

kV

and

hig

h v

olta

ge (

HV

) F

acili

ties d

efin

ed

as the 3

00

kV

an

d lo

we

r vo

lta

ge S

yste

ms.

Th

e d

esig

na

tio

n o

f E

HV

an

d H

V is u

se

d to d

istin

gu

ish

betw

een

sta

ted

perf

orm

ance

crite

ria

allo

wa

nces fo

r in

terr

uptio

n o

f F

irm

Tra

nsm

issio

n S

erv

ice a

nd

No

n-C

on

se

qu

en

tia

l Loa

d L

oss.

4.

Cu

rta

ilme

nt of C

on

ditio

na

l Firm

Tra

nsm

issio

n S

erv

ice is a

llow

ed

wh

en the

co

nd

itio

ns a

nd/o

r e

ve

nts

be

ing s

tud

ied

fo

rme

d the b

asis

fo

r th

e C

on

ditio

na

l Firm

T

ransm

issio

n S

erv

ice

.

5.

Fo

r non

-gen

era

tor

ste

p u

p tra

nsfo

rme

r outa

ge

eve

nts

, th

e r

efe

rence

vo

lta

ge

, as u

se

d in

fo

otn

ote

1, a

pp

lies to th

e lo

w-s

ide

win

din

g (

exclu

din

g te

rtia

ry

win

din

gs).

F

or

gen

era

tor

and G

ene

rato

r S

tep

Up tra

nsfo

rme

r outa

ge e

ve

nts

, th

e r

efe

rence

vo

lta

ge a

pp

lies to the B

ES

co

nn

ecte

d v

olta

ge (

hig

h-s

ide o

f th

e

Ge

ne

rato

r S

tep U

p tra

nsfo

rme

r).

Re

quirem

en

ts w

hic

h a

re a

pp

lica

ble

to tra

nsfo

rmers

als

o a

pp

ly to v

ariab

le fre

qu

en

cy tra

nsfo

rme

rs a

nd p

ha

se

sh

iftin

g

tra

nsfo

rme

rs.

6.

Re

quirem

ents

wh

ich a

re a

pp

lica

ble

to s

hu

nt d

evic

es a

lso

app

ly to

FA

CT

S d

evic

es that a

re c

onn

ecte

d to g

rou

nd.

7.

Op

en

ing

one e

nd o

f a li

ne

se

ctio

n w

ith

ou

t a fa

ult o

n a

no

rma

lly n

etw

ork

ed

Tra

nsm

issio

n c

ircu

it s

uch

that th

e lin

e is p

ossib

ly s

erv

ing

Lo

ad r

adia

l fro

m a

sin

gle

so

urc

e p

oin

t.

8.

An in

tern

al b

reaker

fault m

ea

ns a

bre

aker

faili

ng in

tern

ally

, th

us c

reatin

g a

Syste

m fa

ult w

hic

h m

ust be c

lea

red

by p

rote

ctio

n o

n b

oth

sid

es o

f th

e b

reaker.

9.

An o

bje

ctive

of th

e p

lann

ing

pro

cess s

hou

ld b

e to

min

imiz

e th

e lik

elih

oo

d a

nd

ma

gn

itu

de

of in

terr

uptio

n o

f F

irm

Tra

nsm

issio

n S

erv

ice fo

llow

ing C

on

tin

gen

cy

eve

nts

. C

urt

ailm

ent of F

irm

Tra

nsm

issio

n S

erv

ice

is a

llow

ed b

oth

as a

Syste

m a

dju

stm

ent (a

s id

en

tifie

d in th

e c

olu

mn

entitle

d ‘Initial C

ondition’)

and a

co

rrective

actio

n w

hen a

ch

ieve

d th

rou

gh

th

e a

ppro

pri

ate

re-d

isp

atc

h o

f re

so

urc

es o

blig

ate

d to r

e-d

isp

atc

h, w

he

re it

ca

n b

e d

em

onstr

ate

d th

at F

acili

tie

s,

inte

rnal a

nd e

xte

rna

l to th

e T

ransm

issio

n P

lanner’s p

lan

nin

g r

egio

n, re

ma

in w

ith

in a

pp

lica

ble

Fa

cili

ty R

atin

gs a

nd the r

e-d

isp

atc

h d

oe

s n

ot re

su

lt in a

ny N

on-

Co

nse

qu

en

tia

l Loa

d L

oss.

Whe

re li

mite

d o

ptio

ns fo

r re

-dis

pa

tch

exis

t, s

ensitiv

itie

s a

sso

cia

ted

with th

e a

va

ilab

ility

of th

ose

re

so

urc

es s

hou

ld b

e c

onsid

ere

d.

10

. A

stu

ck b

reaker

me

an

s that fo

r a g

ang-o

pe

rate

d b

reake

r, a

ll th

ree

ph

ase

s o

f th

e b

rea

ke

r h

ave r

em

ain

ed

clo

se

d. F

or

an in

de

pe

nd

ent p

ole

op

era

ted

(IP

O)

or

an in

dep

end

ent p

ole

tri

pp

ing

(IP

T)

bre

aker,

only

on

e p

ole

is a

ssu

me

d to r

em

ain

clo

se

d.

A s

tuck b

reaker

resu

lts in D

ela

ye

d F

au

lt C

lea

rin

g.

11

. E

xclu

des c

ircu

its that sh

are

a c

om

mo

n s

tructu

re (

Pla

nn

ing e

ve

nt P

7, E

xtr

em

e e

ve

nt ste

ad

y s

tate

2a)

or

co

mm

on R

igh

t-of-

Wa

y (E

xtr

em

e e

ve

nt,

ste

ad

y s

tate

2b)

for

1 m

ile o

r le

ss.

12

. A

n o

bje

ctive

of th

e p

lan

nin

g p

rocess is to m

inim

ize

th

e lik

elih

oo

d a

nd

ma

gn

itu

de

of N

on-C

onse

qu

entia

l Load

Loss fo

llow

ing

pla

nn

ing

eve

nts

. In

lim

ite

d

circum

sta

nce

s, N

on-C

onseq

uen

tia

l Load

Loss m

ay b

e n

eeded th

rou

gh

ou

t th

e p

lan

nin

g h

orizo

n to

ensu

re th

at B

ES

perf

orm

ance

re

qu

irem

en

ts a

re m

et.

H

ow

eve

r, w

hen

No

n-C

onse

que

ntia

l Lo

ad L

oss is

utiliz

ed u

nder

footn

ote

12 w

ith

in th

e N

ea

r-T

erm

Tra

nsm

issio

n P

lan

nin

g H

ori

zo

n to a

dd

ress B

ES

pe

rfo

rma

nce

re

qu

irem

ents

, su

ch

inte

rru

ptio

n is

lim

ite

d to c

ircum

sta

nce

s w

here

the N

on-C

on

se

qu

entia

l Lo

ad

Lo

ss m

eets

the

co

nd

itio

ns s

how

n in

Att

ach

me

nt

1.

In n

o c

ase

ca

n th

e p

lan

ned

No

n-C

on

se

qu

entia

l L

oa

d L

oss u

nder

footn

ote

12 e

xcee

d 7

5 M

W fo

r U

S r

egis

tere

d e

ntitie

s.

Th

e a

mo

un

t of p

lann

ed N

on-

Co

nse

qu

en

tia

l Lo

ad

Loss for

a n

on-U

S R

eg

iste

red

En

tity

sh

ould

be im

ple

me

nte

d in

a m

ann

er

that is

co

nsis

ten

t w

ith

, or

under

the

dire

ctio

n o

f, th

e a

pplic

ab

le

gove

rnm

enta

l auth

ority

or

its a

ge

ncy in

th

e n

on

-US

juri

sd

ictio

n.

13

. A

pplie

s to the fo

llow

ing

re

lay fu

nctio

ns o

r ty

pes: p

ilot (#

85),

dis

tan

ce

(#

21),

diffe

rentia

l (#

87

), c

urr

ent (#

50

, 51, and 6

7),

vo

lta

ge

(#

27

& 5

9),

dire

ctio

na

l (#

32

, &

67),

and trip

pin

g (

#8

6, &

94).


13

Attachment 1

I. Stakeholder Process

During each Planning Assessment before the use of Non-Consequential Load Loss under

footnote 12 is allowed as an element of a Corrective Action Plan in the Near-Term Transmission

Planning Horizon of the Planning Assessment, the Transmission Planner or Planning

Coordinator shall ensure that the utilization of footnote 12 is reviewed through an open and

transparent stakeholder process. The responsible entity can utilize an existing process or develop

a new process. .The process must include the following:

1. Meetings must be open to affected stakeholders including applicable regulatory

authorities or governing bodies responsible for retail electric service issues

2. Notice must be provided in advance of meetings to affected stakeholders including

applicable regulatory authorities or governing bodies responsible for retail electric service

issues and include an agenda with:

a. Date, time, and location for the meeting

b. Specific location(s) of the planned Non-Consequential Load Loss under footnote

12

c. Provisions for a stakeholder comment period

3. Information regarding the intended purpose and scope of the proposed Non-

Consequential Load Loss under footnote 12 (as shown in Section II below) must be made

available to meeting participants

4. A procedure for stakeholders to submit written questions or concerns and to receive

written responses to the submitted questions and concerns

5. A dispute resolution process for any question or concern raised in #4 above that is not

resolved to the stakeholder’s satisfaction

An entity does not have to repeat the stakeholder process for a specific application of footnote 12

utilization with respect to subsequent Planning Assessments unless conditions spelled out in

Section II below have materially changed for that specific application.

I. Information for Inclusion in Item #3 of the Stakeholder Process

The responsible entity shall document the planned use of Non-Consequential Load Loss under

footnote 12 which must include the following:

1. Conditions under which Non-Consequential Load Loss under footnote 12 would be

necessary:

a. System Load level and estimated annual hours of exposure at or above that Load

level

b. Applicable Contingencies and the Facilities outside their applicable rating due to

that Contingency

2. Amount of Non-Consequential Load Loss with:

a. The estimated number and type of customers affected


14

b. An explanation of the effect of the use of Non-Consequential Load Loss under

footnote 12 on the health, safety, and welfare of the community

3. Estimated frequency of Non-Consequential Load Loss under footnote 12 based on

historical performance

4. Expected duration of Non-Consequential Load Loss under footnote 12 based on historical

performance

5. Future plans to alleviate the need for Non-Consequential Load Loss under footnote 12

6. Verification that TPL Reliability Standards performance requirements will be met

following the application of footnote 12

7. Alternatives to Non-Consequential Load Loss considered and the rationale for not

selecting those alternatives under footnote 12

8. Assessment of potential overlapping uses of footnote 12 including overlaps with adjacent

Transmission Planners and Planning Coordinators

II. Instances for which Regulatory Review of Non-Consequential Load Loss under Footnote 12

is Required

Before a Non-Consequential Load Loss under footnote 12 is allowed as an element of a

Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or

Planning Coordinator must ensure that the applicable regulatory authorities or governing bodies

responsible for retail electric service issues do not object to the use of Non-Consequential Load

Loss under footnote 12 if either:

1. The voltage level of the Contingency is greater than 300 kV

a. If the Contingency analyzed involves BES Elements at multiple System voltage

levels, the lowest System voltage level of the element(s) removed for the

analyzed Contingency determines the stated performance criteria regarding

allowances for Non-Consequential Load Loss under footnote 12, or

b. For a non-generator step up transformer outage Contingency, the 300 kV limit

applies to the low-side winding (excluding tertiary windings). For a generator or

generator step up transformer outage Contingency, the 300 kV limit applies to the

BES connected voltage (high-side of the Generator Step Up transformer)

2. The planned Non-Consequential Load Loss under footnote 12 is greater than or equal to

25 MW

Once assurance has been received that the applicable regulatory authorities or governing bodies

responsible for retail electric service issues do not object to the use of Non-Consequential Load

Loss under footnote 12, the Planning Coordinator or Transmission Planner must submit the

information outlined in items II.1 through II.8 above to the ERO for a determination of whether

there are any Adverse Reliability Impacts caused by the request to utilize footnote 12 for Non-

Consequential Load Loss.


15

5. Effective Date: May 13, 2009

B. Requirements

R1. The Planning Authority and Transmission Planner shall each demonstrate through a valid

assessment that its portion of the interconnected transmission system is planned such that,

with all transmission facilities in service and with normal (pre-contingency) operating

procedures in effect, the Network can be operated to supply projected customer demands and

projected Firm (non- recallable reserved) Transmission Services at all Demand levels over

the range of forecast system demands, under the conditions defined in Category A of Table I.

To be considered valid, the Planning Authority and Transmission Planner assessments shall:

R1.1. Be made annually.

R1.2. Be conducted for near-term (years one through five) and longer-term (years six

through ten) planning horizons.

R1.3. Be supported by a current or past study and/or system simulation testing that

addresses each of the following categories, showing system performance following

Category A of Table 1 (no contingencies). The specific elements selected (from

each of the following categories) shall be acceptable to the associated Regional

Reliability Organization(s).

R1.3.1. Cover critical system conditions and study years as deemed appropriate by

the entity performing the study.

R1.3.2. Be conducted annually unless changes to system conditions do not warrant

such analyses.

R1.3.3. Be conducted beyond the five-year horizon only as needed to address

identified marginal conditions that may have longer lead-time solutions.

R1.3.4. Have established normal (pre-contingency) operating procedures in place.

R1.3.5. Have all projected firm transfers modeled.

R1.3.6. Be performed for selected demand levels over the range of forecast system

demands.

R1.3.7. Demonstrate that system performance meets Table 1 for Category A (no

contingencies).

R1.3.8. Include existing and planned facilities.

R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources

are available to meet system performance.

R1.4. Address any planned upgrades needed to meet the performance requirements of

Category A.

R2. When system simulations indicate an inability of the systems to respond as

prescribed in Reliability Standard TPL-001-0_R1, the Planning Authority

and Transmission Planner shall each:

R2.1. Provide a written summary of its plans to achieve the required system

performance as described above throughout the planning horizon.

R2.1.1. Including a schedule for implementation.

R2.1.2. Including a discussion of expected required in-service dates of facilities.

R2.1.3. Consider lead times necessary to implement plans.

Anita Swanson

Cross-Out


16

R2.2. Review, in subsequent annual assessments, (where sufficient lead time exists), the

continuing need for identified system facilities. Detailed implementation plans are

not needed.

R3. The Planning Authority and Transmission Planner shall each document the

results of these reliability assessments and corrective plans and shall

annually provide these to its respective NERC Regional Reliability

Organization(s), as required by the Regional Reliability Organization.

C. Measures

M1. Each Transmission Planner and Planning Coordinator shall provide evidence, in electronic or

hard copy format, that it is maintaining System models within their respective area, using data

consistent with MOD-010 and MOD-012, including items represented in the Corrective Action

Plan, representing projected System conditions, and that the models represent the required

information in accordance with Requirement R1.

M2. Each M1. The Planning Authority and Transmission Planner shall have

a valid assessment and corrective plans as specified in Reliability

Standard TPL-001-0_R1 and TPL-001- 0_R2.

M2. The Planning Authority and Transmission Planner and Planning Coordinator shall provide

dated evidence, such as electronic or hard copies of its annual Planning Assessment, that it

has prepared an annual Planning Assessment of its portion of the BES in accordance with

Requirement R2.

M3. Each Transmission Planner and Planning Coordinator shall provide dated evidence, such as

electronic or hard copies of the studies utilized in preparing the Planning Assessment, in

accordance with Requirement R3.


electronic or hard copies of the studies utilized in preparing the Planning Assessment in

accordance with Requirement R4.

M5. Each Transmission Planner and Planning Coordinator shall provide dated evidence such as

electronic or hard copies of thehave evidence it reported documentation specifying the

criteria for acceptable System steady state voltage limits, post-Contingency voltage

deviations, and the transient voltage response for its System in accordance with

Requirement R5.


electronic or hard copies of documentation specifying the criteria or methodology used in the

analysis to identify System instability for conditions such as Cascading, voltage instability, or

uncontrolled islanding that was utilized in preparing the Planning Assessment in accordance

with Requirement R6.

M7. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall

provide dated documentation on roles and responsibilities, such as meeting minutes,

agreements, and e-mail correspondence that identifies that agreement has been reached on

individual and joint responsibilities for performing the required studies and of results of its

Reliability Assessments in accordance with Requirement R7and corrective plans per

Reliability Standard TPL-001-0_R3.

M8. Each Planning Coordinator and Transmission Planner shall provide evidence, such as email

notices, documentation of updated web pages, postal receipts showing recipient and date; or a

demonstration of a public posting, that it has distributed its Planning Assessment results to

adjacent Planning Coordinators and adjacent Transmission Planners within 90 days of having

completed its Planning Assessment, and to any functional entity who has indicated a reliability


17

need within 30 days of a written request and that the Planning Coordinator or Transmission

Planner has provided a documented response to comments received on Planning Assessment

results within 90 calendar days of receipt of those comments in accordance with Requirement

R8.

D. Compliance

1. Compliance Monitoring Process

1.1 Compliance Enforcement Authority

Regional Entity

1.1.1.2 Compliance Monitoring Period and Reset TimeframeResponsibility

Not applicableCompliance Monitor: Regional Reliability Organization.

Each Compliance Monitor shall report compliance and violations to NERC via the NERC

Compliance Reporting Process.

1.2.1.3 Compliance Monitoring Period and Enforcement Processes:Reset Time Frame

Compliance Audits

Self-Certifications

Spot Checking

Compliance Violation Investigations Self-

Reporting

Complaints

Annually

1.3.1.4 Data Retention

The Transmission Planner and Planning Coordinator shall each retain data or evidence to

show compliance as identified unless directed by its Compliance Enforcement Authority

to retain specific evidence for a longer period of time as part of an investigation:

The models utilized in the current in-force Planning Assessment and one

previous Planning Assessment in accordance with Requirement R1 and Measure

M1.

The Planning Assessments performed since the last compliance audit in

accordance with Requirement R2 and Measure M2.

The studies performed in support of its Planning Assessments since the last

compliance audit in accordance with Requirement R3 and Measure M3.

The studies performed in support of its Planning Assessments since the last

compliance audit in accordance with Requirement R4 and Measure M4.

The documentation specifying the criteria for acceptable System steady state

voltage limits, post-Contingency voltage deviations, and transient voltage

response since the last compliance audit in accordance with Requirement R5 and

Measure M5.

The documentation specifying the criteria or methodology utilized in the analysis

to identify System instability for conditions such as Cascading, voltage

instability, or uncontrolled islanding in support of its Planning Assessments since

the last compliance audit in accordance with Requirement R6 and Measure M6.

Anita Swanson

Cross-Out


18

The current, in force documentation for the agreement(s) on roles and

responsibilities, as well as documentation for the agreements in force since the

last compliance audit, in accordance with Requirement R7 and Measure M7.

The Planning Coordinator shall retain data or evidence to show compliance as identified

unless directed by its Compliance Enforcement Authority to retain specific evidence for a

longer period of time as part of an investigation:

Three calendar years of the notifications employed in accordance with

Requirement R8 and Measure M8.

If a Transmission Planner or Planning Coordinator is found non-compliant, it shall keep

information related to the non-compliance until found compliant or the time periods

specified above, whichever is longer.

None specified.

1.4.1.5 Additional Compliance Information

None

Anita Swanson

Cross-Out

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

issio

n S

yste

m P

lan

nin

g P

erf

orm

an

ce R

eq

uir

em

en

tsU

nd

er

No

rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Cate

go

ry A

)

1

9

Vio

lati

on

Sev

erit

y

2.

Levels

of

Non-C

om

plia

nce

Lo

wer

VS

L

Modera

te V

SL

Hig

h V

SL

Severe

VS

L

R1

T

he r

esponsib

le entity’s

Syste

m

model f

aile

d to r

epre

sent one o

f th

e

Requ

irem

ent R

1, P

art

s 1

.1.1

th

rough 1

.1.6

.

The r

esponsib

le entity’s

Syste

m

model f

aile

d to r

epre

sent tw

o o

f th

e

Requ

irem

ent R

1, P

art

s 1

.1.1

thro

ugh

1.1

.6.

The r

esponsib

le entity’s

Syste

m

model f

aile

d to r

epre

sent th

ree o

f th

e

Requ

irem

ent R

1, P

art

s 1

.1.1

thro

ugh

1.1

.6.

The r

esponsib

le entity’s

Syste

m m

odel

faile

d to r

epre

sent fo

ur

or

more

of th

e

Requ

irem

ent R

1, P

art

s 1

.1.1

thro

ugh

1.1

.6.

OR

The r

esponsib

le entity’s

Syste

m m

odel

did

not re

pre

sent pro

jecte

d S

yste

m

conditio

ns a

s d

escribed

in R

equirem

ent

R1.

OR

The r

esponsib

le entity’s

Syste

m m

odel

did

not use

data

consis

tent

with that

pro

vid

ed in

acco

rdance

with

the M

OD

- 010 a

nd M

OD

-01

2 s

tand

ard

s a

nd o

ther

sourc

es, in

clu

din

g it

em

s r

epre

sente

d in

th

e C

orr

ective

Action P

lan.

R2

T

he r

esponsib

le e

ntity

faile

d to

com

ply

with R

equ

irem

ent R

2, P

art

2.6

.

The r

esponsib

le e

ntity

faile

d to

com

ply

with R

equ

irem

ent R

2, P

art

2.3

or

Part

2.8

.

The r

esponsib

le e

ntity

faile

d to

com

ply

with o

ne

of th

e follo

win

g

Part

s o

f R

equirem

ent R

2: P

art

2.1

, P

art

2.2

, P

art

2.4

, P

art

2.5

, or

Part

2.7

.

The r

esponsib

le e

ntity

fa

iled

to c

om

ply

w

ith t

wo

or

more

of

the f

ollo

win

g P

art

s

of

Requirem

ent

R2:

Part

2.1

, P

art

2.2

, P

art

2.4

, or

Part

2.7

.

OR

The r

esponsib

le e

ntity

do

es n

ot have

a

com

ple

ted

ann

ua

l Pla

nnin

g

Assessm

ent.

Anita Swanson

Cross-Out

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

issio

n S

yste

m P

lan

nin

g P

erf

orm

an

ce R

eq

uir

em

en

tsU

nd

er

No

rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Cate

go

ry A

)

2

0

R3

T

he r

esponsib

le e

ntity

did

not

ide

ntify

pla

nnin

g e

vents

as

described

in R

equirem

ent R

3, P

art

3.4

or

extr

em

e e

vents

as d

escribed

in

Req

uirem

ent R

3, P

art

3.5

.

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in

Requirem

ent

R3, P

art

3.1

to d

ete

rmin

e that th

e

BE

S m

eets

the p

erf

orm

ance

re

quirem

ents

for

one o

f th

e c

ate

gories

(P2 thro

ugh

P7)

in T

able

1.

The r

esponsib

le e

ntity

did

not

perf

orm

stu

die

s a

s s

pecifie

d in

R

equ

irem

ent R

3, P

art

3.1

to

dete

rmin

e that th

e B

ES

meets

the

perf

orm

ance

requirem

ents

for

two o

f th

e c

ate

gories (

P2 thro

ugh P

7)

in

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in R

equ

irem

ent R

3,

Part

3.1

to

de

term

ine that th

e B

ES

m

eets

the p

erf

orm

ance

requirem

ents

fo

r th

ree o

r m

ore

of th

e c

ate

gories (

P2

th

rough P

7)

in T

able

1.

Anita Swanson

Cross-Out

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

issio

n S

yste

m P

lan

nin

g P

erf

orm

an

ce R

eq

uir

em

en

tsU

nd

er

No

rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Cate

go

ry A

)

2

1

Lo

wer

VS

L

Modera

te V

SL

Hig

h V

SL

Severe

VS

L

OR

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in

Requirem

ent

R3, P

art

3.2

to a

ssess the im

pact of

extr

em

e e

vents

.

Table

1.

OR

The r

esponsib

le e

ntity

did

not

perf

orm

Contin

gency a

naly

sis

as

described

in R

equirem

ent R

3, P

art

3.3

.

OR

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s to

de

term

ine tha

t th

e B

ES

m

eets

the p

erf

orm

ance

requirem

ents

fo

r th

e P

0 o

r P

1 c

ate

gories in T

able

1.

OR

The r

esponsib

le e

ntity

did

not base its

stu

die

s o

n c

om

pute

r sim

ula

tion m

odels

usin

g d

ata

pro

vid

ed in

Re

qu

irem

ent R

1.

R4

T

he r

esponsib

le e

ntity

did

not

ide

ntify

pla

nnin

g e

vents

as

described

in R

equirem

ent R

4, P

art

4.4

or

extr

em

e e

vents

as d

escribed

in

Req

uirem

ent R

4, P

art

4.5

.

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in

Requirem

ent

R4, P

art

4.1

to d

ete

rmin

e that th

e

BE

S m

eets

the p

erf

orm

ance

re

quirem

ents

for

one o

f th

e c

ate

gories

(P1 thro

ugh

P7)

in T

able

1.

OR

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in

Requirem

ent

R4, P

art

4.2

to a

ssess the im

pact of

extr

em

e e

vents

.

The r

esponsib

le e

ntity

did

not

perf

orm

stu

die

s a

s s

pecifie

d in

R

equ

irem

ent R

4, P

art

4.1

to

dete

rmin

e that th

e B

ES

meets

the

perf

orm

ance

requirem

ents

for

two o

f th

e c

ate

gories (

P1 thro

ugh P

7)

in

Table

1.

OR

The r

esponsib

le e

ntity

did

not

perf

orm

Contin

gency a

naly

sis

as

described

in R

equirem

ent R

4, P

art

4.3

.

The r

esponsib

le e

ntity

did

not perf

orm

stu

die

s a

s s

pecifie

d in R

equ

irem

ent R

4,

Part

4.1

to

de

term

ine that th

e B

ES

m

eets

the p

erf

orm

ance

requirem

ents

fo

r th

ree o

r m

ore

of th

e c

ate

gories (

P1

th

rough P

7)

in T

able

1.

OR

The r

esponsib

le e

ntity

did

not base its

stu

die

s o

n c

om

pute

r sim

ula

tion m

odels

usin

g d

ata

pro

vid

ed in

Re

qu

irem

ent R

1.

R5

N

/A

N/A

N

/A

The r

esponsib

le e

ntity

do

es n

ot have

crite

ria for

accepta

ble

Syste

m s

tead

y

sta

te v

oltage li

mits, post-

Contingency

voltage d

evia

tions, or

the tra

nsie

nt

voltage r

esponse

for

its S

yste

m.

R6

N

/A

N/A

N

/A

The r

esponsib

le e

ntity

fa

iled

to d

efine

and d

ocum

ent th

e c

rite

ria

or

meth

odolo

gy for

Syste

m in

sta

bili

ty u

se

d

within

its

analy

sis

as d

escribed

in

Requ

irem

ent R

6.

Anita Swanson

Cross-Out

Sta

nd

ard

TP

L-0

01-4

0.1

—T

ran

sm

issio

n S

yste

m P

lan

nin

g P

erf

orm

an

ce R

eq

uir

em

en

tsU

nd

er

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rmal (N

o C

on

tin

gen

cy)C

on

dit

ion

s (

Cate

go

ry A

)

2

2

Lo

wer

VS

L

Modera

te V

SL

Hig

h V

SL

Severe

VS

L

R7

N

/A

N/A

N

/A

The P

lannin

g C

oord

inato

r, in

conju

nction

with e

ach o

f its

Tra

nsm

issio

n P

lanners

, fa

iled to

dete

rmin

e a

nd id

entify

indiv

idua

l or

join

t re

sponsib

ilities for perf

orm

ing

requir

ed

stu

die

s.

R8

T

he r

esponsib

le e

ntity

dis

trib

ute

d it

s

Pla

nnin

g A

ssessm

ent re

sults to

adja

cent P

lannin

g C

oord

ina

tors

and

adja

cent T

ransm

issio

n P

lan

ners

but

it w

as m

ore

than 9

0 d

ays b

ut le

ss

than o

r equal to

120 d

ays follo

win

g

its c

om

ple

tion.

OR

,

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esponsib

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s

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nnin

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ssessm

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sults to

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and

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cent T

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ore

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20 d

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ys follo

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ssessm

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ntities h

avin

g a

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ting b

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ore

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0 d

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o 5

0 d

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request.

The r

esponsib

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ntity

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trib

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d it

s

Pla

nnin

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ssessm

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sults to

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cent P

lannin

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oord

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tors

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cent T

ransm

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n P

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ners

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it w

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ore

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30 d

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ss

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OR

,

The r

esponsib

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ntity

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trib

ute

d it

s

Pla

nnin

g A

ssessm

ent re

sults to

functional e

ntities h

avin

g a

relia

bili

ty

rela

ted

need w

ho r

equeste

d the

Pla

nnin

g A

ssessm

ent in

wri

ting b

ut it

was m

ore

than 5

0 d

ays b

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ss than

or

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0 d

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win

g the

request.

The r

esponsib

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s

Pla

nnin

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ssessm

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sults to

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cent P

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and

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cent T

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ners

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was m

ore

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40 d

ays follo

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ple

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OR

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esponsib

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ntity

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istr

ibu

te

its P

lann

ing

Assessm

ent re

sults to

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cent P

lannin

g C

oord

ina

tors

and

adja

cent T

ransm

issio

n P

lanners

.

OR

The r

esponsib

le e

ntity

dis

trib

ute

d it

s

Pla

nnin

g A

ssessm

ent re

sults to

functional e

ntities h

avin

g a

relia

bili

ty

rela

ted n

eed w

ho r

equeste

d the

Pla

nnin

g A

ssessm

ent in

wri

ting b

ut it

was m

ore

than 6

0 d

ays follo

win

g the

request.

OR

The r

esponsib

le e

ntity

did

not d

istr

ibu

te

its P

lann

ing

Assessm

ent re

sults to

functional e

ntities h

avin

g a

relia

bili

ty

rela

ted n

eed w

ho r

equeste

d the

Pla

nnin

g A

ssessm

ent in

writing.

Anita Swanson

Cross-Out


23

2.1. Level 1: Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning

horizon is not available.

2.3. Level 3: Not applicable.

2.4. Level 4: A valid assessment and corrective plan for the near-term planning

horizon is not available.

E. Regional VariancesDifferences

1. None identified.

Version History

Version Date Action Change Tracking

0 April 1, 2005 Effective Date New

0 February 8, 2005 BOT Approval Revised

0 June 3, 2005 Fixed reference in M1 to read TPL-001-0 R2.1

and TPL-001-0 R2.2

Errata

0 July 24, 2007 Corrected reference in M1. to read TPL-001-0

R1 and TPL-001-0 R2.

Errata

0.1 October 29, 2008 BOT adopted errata changes; updated version number

to “0.1”

Errata

0.1 May 13, 2009 FERC Approved – Updated Effective Date and Footer Revised

1 Approved by

Board of Trustees

February 17, 2011

Revised footnote ‘b’ pursuant to FERC Order RM06-

16-009 Revised (Project 2010-

11)

2 August 4, 2011 Revision of TPL-001-1; includes merging and

upgrading requirements of TPL-001-0, TPL-002-0,

TPL-003-0, and TPL-004-0 into one, single,

comprehensive, coordinated standard: TPL-001-2; and

retirement of TPL-005-0 and TPL-006-0.

Project 2006-02 –

complete revision

2 August 4, 2011 Adopted by Board of Trustees

1 April 19, 2012 FERC issued Order 762 remanding TPL-001-1, TPL-

002-1b, TPL-003-1a, and TPL-004-1. FERC also

issued a NOPR proposing to remand TPL-001-2.

NERC has been directed to revise footnote 'b' in

accordance with the directives of Order Nos. 762 and

693.

3 February 7, 2013 Adopted by the NERC Board of Trustees.

TPL-001-3 was created after the Board of Trustees

approved the revised footnote ‘b’ in TPL-002-2b,

which was balloted and appended to: TPL-001-0.1,

TPL-002-0b, TPL-003-0a, and TPL-004-0.

http://www.nerc.com/files/Order_TPL-002-0b_RM11-18.pdf




http://www.nerc.com/files/order_693.pdf

http://www.nerc.com/files/order_693.pdf

Anita Swanson

Cross-Out


24

4 February 7, 2013 Adopted by the NERC Board of Trustees.

TPL-001-4 was adopted by the Board of Trustees as

TPL-001-3, but a discrepancy in numbering was

identified and corrected prior to filing with the

regulatory agencies.

4 October 17, 2013 FERC Order issued approving TPL-001-4 (Order

effective December 23, 2013).


25

Table I. Transmission System Standards – Normal and Emergency Conditions

Category Contingencies System Limits or Impacts

Initiating Event(s) and Contingency

Element(s)

System Stable and both

Thermal and

Voltage Limits within

Applicable

Rating a

Loss of Demand

or Curtailed Firm

Transfers

Cascading Outages

A

No Contingencies

All Facilities in Service

Yes

No

No

B

Event resulting in

the loss of a single element.

Single Line Ground (SLG) or 3-Phase (3Ø)

Fault, with Normal Clearing: 1. Generator

2. Transmission Circuit

3. Transformer Loss of an Element without a Fault

Yes

Yes

Yes Yes

No b

No b

No b

No b

No

No

No No

Single Pole Block, Normal Clearing e:

4. Single Pole (dc) Line

Yes

Nob

No

C

Event(s)

resulting in the loss of two or

more (multiple)

SLG Fault, with Normal Clearing e:

1. Bus Section

2. Breaker (failure or internal Fault)

e

Yes

Yes

Planned/

Controlledc

Planned/

Controlledc

No

No

elements. SLG or 3Ø Fault, with Normal Clearing ,

Manual System Adjustments, followed by another SLG or 3Ø Fault, with Normal

Clearing e:

3. Category B (B1, B2, B3, or B4)

contingency, manual system

adjustments, followed by another Category B (B1, B2, B3, or B4)

contingency

Yes

Planned/

Controlledc

No

Bipolar Block, with Normal Clearing: e

4. Bipolar (dc) Line Fault (non 3Ø), with

Normal Clearing e:

5. Any two circuits of a multiple circuit

towerlinef

Yes

Yes

Planned/

Controlledc

Planned/

Controlledc

No

No

SLG Fault, with Delayed Clearing e

(stuck breaker or protection system failure):

6. Generator

7. Transformer

8. Transmission Circuit

9. Bus Section

Yes

Yes Yes

Yes

Planned/

Controlledc

Planned/

Controlledc

Planned/

Controlledc

Planned/

Controlledc

No

No No

No


26

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as determined and

consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings applicable for short

durations as required to permit operating steps necessary to maintain system control. All Ratings must be established consistent

with applicable NERC Reliability Standards addressing Facility Ratings.

b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or

supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall reliability of

the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including

curtailments of contracted Firm (non-recallable reserved) electric power Transfers.

c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load

shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (non-recallable

reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected transmission

systems.

d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning

entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed contingency of

Category D will be evaluated.

e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected with

proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection system

component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.

f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station entrance, river

crossings) in accordance with Regional exemption criteria.

D d

Extreme event resulting in

two or more (multiple) elements removed or

Cascading out of service.

3Ø Fault, with Delayed Clearing e

(stuck breaker or protection system failure):

1. Generator 3. Transformer 2. Transmission Circuit 4. Bus Section

3Ø Fault, with Normal Clearing e:

5. Breaker (failure or internal Fault)

6. Loss of towerline with three or more circuits 7. All transmission lines on a common right-of way

8. Loss of a substation (one voltage level plus transformers)

9. Loss of a switching station (one voltage level plus transformers)

10. Loss of all generating units at a station

11. Loss of a large Load or major Load center 12. Failure of a fully redundant Special Protection System (or

remedial action scheme) to operate when required

13. Operation, partial operation, or misoperation of a fully redundant Special Protection System (or Remedial Action

Scheme) in response to an event or abnormal system

condition for which it was not intended to operate 14. Impact of severe power swings or oscillations from

Disturbances in another Regional Reliability Organization.

Evaluate for risks and consequences.

May involve substantial loss of customer Demand and

generation in a widespread

area or areas. Portions or all of the

interconnected systems may

or may not achieve a new, stable operating point.

Evaluation of these events may

require joint studies with neighboring systems.


Appendix B-1

BC Hydro Feedback Survey Forms

Disclaimer: This information has been prepared as input into BC Hydro's tenth assessment report on Mandatory Reliability Standards and is based on information available to BC Hydro as of the date sent. It should not be relied upon for any other purpose.

T&D Cost

One Time ($)

T&D Cost

Ongoing ($)

Generation Cost

One Time ($)

Generation Cost

Ongoing ($)

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

FERC Order 786 dated

10/17/13

Docket No. RM12-1-000

and RM13-9-000

145 FERC ¶ 61,051

T&D: First day of first calendar quarter, three years after BCUC adoption.


BCUC approval, Corrective Action Plans applying to the following categories of


Consequential Load Loss and curtailment of Firm Transmission Service (in accordance

with Requirement R2, Part 2.7.3.) that would not otherwise be permitted by the

requirements of TPL-001-4:

- P1-2 (for controlled interruption of electric supply to local network customers connected

to or supplied by the Faulted element)



- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

T&D: No incremental actions expected. $0 $0 N/A N/A












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)













- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

T&D: If the TPL assessments identify there is a need to shed non-

consequential load , then the use of NCLL will need to be reviewed through an

open and transparent stakeholder process.

Estimated Breakdown of Costs:

One-Time Costs - The use of NCLL is estimated to be on approximately four

occassions in lieu of transmission reinforcements. Each stakeholder process

required is estimated to cost about $100,000. The total cost of a stakeholder

process for all four events is estimated to be about $400,000.

Ongoing (Annual) - Not known at this time; will come out of future planning

studies.

$400,000 Unknown at this time N/A N/A












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)













- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

T&D: The study methodology need to be re written to take in to account the new

requirements:

a) Sensitivity studies

b) equipment spares availability related analysis

c) short circuit studies and analysis of results

d) options of alternatives to reinforcements detailed in the standard.


One-Time Costs - Two weeks worth of time for about eight transmission planners

= $56,000.

Ongoing (Annual) Costs - About one more week in increase of studies required

for about eight transmission planners (280 man hours) = $28,000. This

incremental increase in TPL assessment activity is due to aforementioned

additional TPL-001-4 requirements.

$56,000 $28,000 N/A N/A

Except as indicated below, Requirements R2 through R6 and Requirement R8 shall become effective on

the first day of the first calendar quarter, 24 months after applicable regulatory approval.

For 84 calendar months beginning the first day of the first calendar quarter following applicable

regulatory approval, Corrective Action Plans applying to the following categories of Contingencies and

events identified in TPL-001-4, Table 1 are allowed to include Non-Consequential Load Loss and

curtailment of Firm Transmission Service (in accordance with Requirement R2, Part 2.7.3.) that would

not otherwise be permitted by the requirements of TPL-001-4:

- P1-2 (for controlled interruption of electric supply to local network customers connected to or supplied

by the Faulted element)



- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

TPL-001-4 R2

23-Dec-2013












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

Name: Transmission System Planning Performance

Requirements

Description: Establish Transmission system planning

performance requirements within the planning horizon to develop

a Bulk Electric System (BES) that will operate reliably over a

broad spectrum of System conditions and following a wide range

of probable Contingencies.

TPL-001-4 R6

4 - Complete revision. Revision of TPL-001-1; includes

merging and upgrading requirements of TPL-001-0,

TPL-002-0, TPL-003-0, and TPL-004-0 into one, single,



TP, PC


and RM13-9-000, Order

786; Issue Date: October

17, 2013; Publication

Date: October 23, 2013

















- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

TPL-001-4 R5


Requirements











TP, PC 23-Dec-2013


Requirements











TP, PC






23-Dec-2013












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

TPL-001-4 R4


Requirements











TP, PC

TPL-001-4 R3


Requirements











TP, PC






23-Dec-2013












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

23-Dec-2013

BCUC Implementation Time

(Press Alt-Enter to insert a carriage return in a cell)

FERC Approved Standard/Requirement Implementation Time Provided and US Enforcement Date

(Each cell is linked to the respective implementation plan and effective dates if applicable)

Estimated Incremental/New Costs Associated with Revision/New Standard/Requirement, if any ($)

T&D: Modelling is an ongoing activity with minimal changes to existing process

if any. Equipment spares availability need to be dove tailed with power flow base

cases and contingency lists. The short circuit study equipment models are to be

included in existing TPL assessment planning models.There are no adverse

reliability impacts or technical / administrative suitability issues.


One-Time - $10,000 (assuming 100 man hours).

Ongoing (Annual) - $0

$10,000 $0 N/A N/A T&D: First day of first calendar quarter, two years after BCUC adoption.

BC Hydro Stakeholder Comments Organizational Activities and

Reliability/Suitability Impact


Functional

Applicability of FERC

Approved Standards/

Requirements

FERC Order No., Order

Date and Order

Publication Date

(Each cell is linked to

the respective FERC

Order if applicable)

US Effective

Date of FERC

Order Ruling

Approving

Standard(s)

(Each cell is

linked to the

respective

effective dates

of the FERC

Approval

Ruling if

applicable)

TPL-001-4 R1


Requirements











TP, PC






23-Dec-2013Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first

calendar quarter, 12 months after applicable regulatory approval.

FERC Approved

New/Revised

Standard/Requirement

(Select the respective

link to open the

Standards)

Standard Name and DescriptionCurrent BCUC Adopted

Standards to be Superseded

FERC Approved Revision(s) to

Standard/Requirement listed in Standard Version

History

Appendix B-1

Mandatory Reliability Standard TPL-001-4 Assessment Report

Page 1 of 3

http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=TPL-001-0.1&title=System%20Performance%20Under%20Normal%20(No%20Contingency)%20Conditions%20(Category%20A)&jurisdiction=United%20States

http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=TPL-002-0b&title=System%20Performance%20Following%20Loss%20of%20a%20Single%20Bulk%20Electric%20System%20Element%20(Category%20B)&jurisdiction=United%20States

http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=TPL-003-0b&title=System%20Performance%20Following%20Loss%20of%20Two%20or%20More%20Bulk%20Electric%20System%20Elements%20(Category%20C)&jurisdiction=United%20States

http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=TPL-004-0a&title=System%20Performance%20Following%20Extreme%20Events%20Resulting%20in%20the%20Loss%20of%20Two%20or%20More%20Bulk%20Electric%20System%20Elements%20(Category%20D)&jurisdiction=Un





















http://www.nerc.com/FilingsOrders/us/FERCOrdersRules/E-2 Transmission PLanning Rel. Strd.pdf





http://www.nerc.com/pa/Stand/TPL0014RD/Implementation Plan for 2010-11_TPL-001-4.pdf


















http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=TPL-001-4&title=Transmission%20System%20Planning%20Performance%20Requirements&jurisdiction=United%20States

https://www.federalregister.gov/articles/2013/10/23/2013-24828/transmission-planning-reliability-standards




















https://extranet.bchydro.com/sites/rc_bcuc/BC Approved Standards Library/TPL-001-4 - Redlined.pdf









































































































































T&D Cost

One Time ($)

T&D Cost

Ongoing ($)

Generation Cost

One Time ($)

Generation Cost

Ongoing ($)





Estimated Incremental/New Costs Associated with Revision/New Standard/Requirement, if any ($)

T&D: Modelling is an ongoing activity with minimal changes to existing process

if any. Equipment spares availability need to be dove tailed with power flow base

cases and contingency lists. The short circuit study equipment models are to be

included in existing TPL assessment planning models.There are no adverse

reliability impacts or technical / administrative suitability issues.


One-Time - $10,000 (assuming 100 man hours).

Ongoing (Annual) - $0

$10,000 $0 N/A N/A T&D: First day of first calendar quarter, two years after BCUC adoption.

BC Hydro Stakeholder Comments Organizational Activities and



Functional

Applicability of FERC

Approved Standards/

Requirements

FERC Order No., Order

Date and Order

Publication Date

(Each cell is linked to

the respective FERC

Order if applicable)

US Effective

Date of FERC

Order Ruling

Approving

Standard(s)

(Each cell is

linked to the

respective

effective dates

of the FERC

Approval

Ruling if

applicable)

TPL-001-4 R1


Requirements











TP, PC








FERC Approved

New/Revised



link to open the

Standards)

Standard Name and DescriptionCurrent BCUC Adopted

Standards to be Superseded



History

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)


NOTE: This requirement applies to the PC role (not yet defined in BC) in

conjunction with the TP role. Only provide feedback if necessary here.

NOTE: This requirement applies

to the PC role (not yet defined in

BC) in conjunction with the TP

role. Only provide feedback if

necessary here.

NOTE: This requirement

applies to the PC role (not yet

defined in BC) in conjunction

with the TP role. Only provide

feedback if necessary here.

N/A N/A

NOTE: This requirement applies to the PC role (not yet defined in BC) in conjunction with

the TP role. Only provide feedback if necessary here.23-Dec-2013Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first


TPL-001-4 R8


Requirements











TP, PC






23-Dec-2013












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

TPL-001-4 R7


Requirements











PC






Appendix B-1


Page 2 of 3













































































Cost

One Time ($)

Cost

Ongoing ($)

Bus-tie Breaker

*Glossary term is specific to the TPL-001-4 standard.

N/A A circuit breaker that is positioned to connect two individual substation bus configurations. New N/A 17-Oct-13 01-Jan-15

Coincide with the earliest effective date of the TPL-001-4

standard after BCUC adoption.



N/A

All Load that is no longer served by the Transmission system as a result of Transmission

Facilities being removed from service by a Protection System operation designed to isolate

the fault.

New N/A 17-Oct-13 01-Jan-15





N/A

Transmission planning period that covers years six through ten or beyond when required to

accommodate any known longer lead time projects that may take longer than ten years to

complete.






N/A

Non-Interruptible Load loss that does not include: (1) Consequential Load Loss, (2) the

response of voltage sensitive Load, or (3) Load that is disconnected from the System by end-

user equipment.




Planning Assessment


N/ADocumented evaluation of future Transmission System performance and Corrective Action

Plans to remedy identified deficiencies.New N/A 17-Oct-13 01-Jan-15



Effective Date of

New/Revised/Retired NERC

Term and Definition in United

States

Stakeholder Comments




Estimated Incremental Cost Associated with

Revised/New Term and Definition, if any ($).

(Press Alt-Enter to insert a carriage return in a cell)FERC Approved New/Revised/Retired NERC Glossary of Terms from the

February 7, 2017 Glossary of Terms

Acronym

(If Available)

FERC Approved New/Revised NERC Term Definitions against Terms and Definitions

listed in Columns "D" and "E"

(changes to definition indicated by red text; deletions are not indicated)

Current BCUC Adopted Terms

from

December 7, 2015

Glossary of Terms

(Column "D")

Current BCUC Adopted

Definition from December 7, 2015

Glossary of Terms

FERC Approval Date of


Term and Definition

Appendix B-1


Page 3 of 3


Appendix B-2

Instructions for Registered Entities

Task # Task Description Reference Files and Links Comments

3 Compliance Leads are requested to email the Reliability Compliance department (use the email address provided in the column to the right) when all

feedback is completed.

[email protected]

Contact Information for help:

Patricia Robertson, Reliability Compliance Manager

British Columbia Hydro and Power Authority

(604)-455-4233

[email protected]

Vijay Raghunathan, Senior Reliability Compliance Engineer


(604)-516-8958

[email protected]

Sousheela Ramsamy, Consultant


(604) 455-4215

[email protected]

1 Within this feedback spreadsheet, go to the tab titled ‘CIP Stnds Feedback Survey Form’ for Critical Infrastructure Protection (CIP) standards or 'OPS

Stnds Feedback Survey Form' for operations standards (highlighted in yellow) and search for your name using the filters in Columns ‘I‘ and ‘J’ to identify

Standards/requirements (Columns 'A' & ‘B’) for which you have been identified as an internal stakeholder (i.e. Compliance Leads, Primary/Secondary

Contacts, Subject Matter Experts, Managers).

NOTE: If there are errors in identified stakeholders or individuals missing, Compliance Leads are requested to coordinate as necessary and directly with

said individuals and make corrections using red text. Please also notify Reliability Compliance (Patricia Robertson, Vijay Raghunathan, and/or Sousheela

Ramsamy) of the changes made ASAP.

The majority of the 36 new and revised standards have been presented in the feedback survey form

spreadsheet on a per requirement basis to highlight new requirements for new standards and for

revised standards, significant requirement changes to currently adopted versions. This enables

stakeholders to identify specific actions, costs, and recommended implementation times on a per

requirement basis instead of providing general comments against said standards.

2

For each Standard/requirement listed in the 'CIPStnds Feedback Survey Form' or 'OPS Stnds Feedback Survey Form' tab for which you are a

stakeholder, please review each referenced FERC adopted new/revised Standard and corresponding redline (for revised standards only indicating changes

from current BCUC adopted standard versions) located in the Assessment Report No. 10 page on MRS SharePoint and provide feedback as applicable

under either Columns 'K' to 'V' of the 'CIP Stnds Feedback Survey Form' or Columns ‘K’ to 'P' of the ‘OPS Stnds Feedback Survey Form’ tabs

highlighted in yellow (see below for details):

IMPORTANT: Designated Compliance Leads identified per Column 'I' from business units (i.e. Transmission, Generation, etc.) are requested to

coordinate/collaborate with other identified Compliance Leads and Supporting Contacts per Column 'J' prior to providing feedback.

a. BC Hydro Stakeholder Comments (Column "K"): Please advise if there are no changes to BC Hydro's current processes, or if changes are

required, describe a list of high-level incremental activities required to reach compliance. Please also indicate if there are any technical/administrative

suitability issues that could impede adoption (i.e. specific NERC reporting tools or NERC membership required OR undefined processes/procedures

referenced from Standard/requirement).

b. Estimated Incremental/New Costs Associated with Revision/New Standard/requirement, if any ($) (Columns 'L' to 'U' of the 'CIP Stnds

Feedback Survey Form' tab or Columns 'L' to 'O' of the 'OPS Stnds Feedback Survey Form' tab)*, if any associated with:

- a revision to a Standard compared to the immediately preceding version currently adopted by the BCUC; or.

- the adoption of a new Standard.

Please indicate which costs are one-time versus ongoing (in dollars $), and identify the assumptions associated with each estimate (assumptions should be

documented in Column 'K' and linked with the actions identified per Column 'K'.

c. BCUC Implementation Time (Column "V" of the 'CIP Stnds Feedback Survey Form' tab or Column “P” of the 'OPS Stnds Feedback Survey

Form' tab):

Please include an assessment of the amount of time BC Hydro would reasonably require to come into compliance with the Standard/requirement once

adopted by the BCUC (i.e. 6 months from adoption, immediately after adoption, etc.). BC Hydro will use this information, in conjunction with external

stakeholder feedback, to recommend an overall implementation time for each Standard/requirement for inclusion in the Report. The BCUC will then use

this information to develop Effective Dates in BC for each Standard/requirement. Please Note: Implementation times in the U.S. have been provided

for you to use as a benchmark.

1) The ‘Compliance’ sections are to be determined by the BCUC and are not included in this

assessment.

2) The ‘Effective Date’ sections will be subject to assessment by internal BC Hydro and external

stakeholders in B.C. Please ignore the existing US dates.

Assessment Report No. 10 Standards Library

Appendix B-2


Page 1 of 2


Task # Task Description Reference Files and Links

NERC Glossary of Terms Nov 28, 2016

1

Please review the NERC Glossary of Terms November 28, 2016 and provide feedback under Columns 'H', ‘I’, ‘J’, and ‘K’ of

the ‘Glossary Feedback Survey Form’ tab. For each Term assessed, please complete the following fields highlighted in

yellow: (Note the link to the right is to the complete NERC Glossary, the terms for this assessment have been duplicated in

the ‘Glossary Feedback Survey Form’ tab for your convenience.

IMPORTANT: When providing your comments in the columns below, please use the following format to allow us to follow

who has commented: First Name Last Name: Comment

a. Stakeholder Comments (Column "H"): Please provide a high-level list of activities required to mitigate/eliminate

impacts based on the revised or new Terms definitions.

b. The Estimated Incremental Cost Associated with Revised/New Term/Definition (Columns “I" and "J”), if any

associated with:

- a revision to a Term/Definition compared to the version adopted by the BCUC; or

- the adoption of a new Term/Definition.

Please indicate which costs are one-time versus ongoing (in dollars $), and identify the assumptions associated with each

estimate.

c. BCUC Implementation Time (Column “K”):

Please include an assessment of the amount of time reasonably required to come into compliance with the Term's definition

once adopted by the BCUC (i.e. 6 months from adoption, immediately after adoption, etc.). BC Hydro will use this

information to recommend an overall implementation time for inclusion in the Report.

2

Compliance Leads are requested to email the Reliability Compliance department (use the email address provided in the

column to the right) when all feedback is completed. [email protected]

Assessment Report No. 10 Standards Library

Appendix B-2


Page 2 of 2



Appendix B-3

External Stakeholder Feedback

Cost

One Time ($)

Cost

Ongoing ($)

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-4 R1


Requirements



a Bulk Electric System (BES) that will operate reliably over a broad

spectrum of System conditions and following a wide range of

probable Contingencies.

FERC Approved

New/Revised


(Select the respective link

to open the Standards)

Standard Name and DescriptionCurrent BCUC Adopted Standards to

be Superseded



History

Functional Applicability of

FERC Approved

Standards/Requirements

Docket No. RM12-1-000 and RM13-9-

000, Order 786; Issue Date: October

17, 2013; Publication Date: October

23, 2013

FERC Order 786 dated 10/17/13


000

145 FERC ¶ 61,051


(Press Alt-Enter to insert a carriage return in

a cell)

US Effective Date of

FERC Order Ruling

Approving Standard(s)

(Each cell is linked to the

respective effective

dates of the FERC

Approval Ruling if

applicable)



Stakeholder Comments Organizational Activities

and Reliability/Suitability Impact

(Press Alt-Enter to insert a carriage return in a

cell)

Estimated Incremental/New Costs Associated with Revision/New

Standard/Requirement, if any ($)

FERC Order No., Order Date and

Order Publication Date


respective FERC Order if

applicable)


merging and upgrading requirements of TPL-001-0, TPL-

002-0, TPL-003-0, and TPL-004-0 into one, single,



TP, PC




23, 2013

23-Dec-2013Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first calendar quarter, 12

months after applicable regulatory approval.

NOTE: This standard was originally included for

assessment under Assessment Report No. 8, but

adoption was held by the BCUC pending

reassessment per Order R-38-15. As such, this

standard is now up for reassessment.

TPL-001-4 R2


Requirements











TP, PC




23, 2013

23-Dec-2013

Except as indicated below, Requirements R2 through R6 and Requirement R8 shall become effective on the first day of the

first calendar quarter, 24 months after applicable regulatory approval.

For 84 calendar months beginning the first day of the first calendar quarter following applicable regulatory approval,

Corrective Action Plans applying to the following categories of Contingencies and events identified in TPL-001-4, Table 1

are allowed to include Non-Consequential Load Loss and curtailment of Firm Transmission Service (in accordance with

Requirement R2, Part 2.7.3.) that would not otherwise be permitted by the requirements of TPL-001-4:

- P1-2 (for controlled interruption of electric supply to local network customers connected to or supplied by the Faulted

element)


element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






TPL-001-4 R4


Requirements











TP, PC

TPL-001-4 R3


Requirements











TP, PC




23, 2013

23-Dec-2013








element)


element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






NOTE: This requirement applies to the PC role

(not yet defined in BC). Only provide feedback

if necessary here.








element)


element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






23-Dec-2013








element)


element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






TPL-001-4 R5


Requirements











TP, PC 23-Dec-2013


Requirements






TPL-001-4 R6






TP, PC




23, 2013

23-Dec-2013








element)


element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)







Catalyst Paper Corporation, Crofton Division (CPCD), Port Alberni Division (CPPAD), Powell River Division (CPPR) (all registered as DP only with UFLS)

Appendix B-3


Page 1 of 12



























































































































































Cost

One Time ($)

Cost

Ongoing ($)

TPL-001-4 R1


Requirements






FERC Approved

New/Revised





be Superseded



History

Functional Applicability of

FERC Approved



(Press Alt-Enter to insert a carriage return in

a cell)


FERC Order Ruling




dates of the FERC

Approval Ruling if

applicable)



Stakeholder Comments Organizational Activities

and Reliability/Suitability Impact

(Press Alt-Enter to insert a carriage return in a

cell)

Estimated Incremental/New Costs Associated with Revision/New

Standard/Requirement, if any ($)





applicable)






TP, PC




23, 2013








TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

NOTE: This requirement applies to the PC role (not

yet defined in BC) in conjunction with the TP role.

Only provide feedback if necessary here. This

standard was originally included for assessment

under Assessment Report No. 8, but adoption was

held by the BCUC pending reassessment per Order

R-38-15. As such, this standard is now up for

reassessment.

NOTE: This requirement applies to

the PC role (not yet defined in BC) in

conjunction with the TP role. Only

provide feedback if necessary

here.

NOTE: This requirement applies to the PC

role (not yet defined in BC) in conjunction

with the TP role. Only provide feedback if

necessary here.


(not yet defined in BC) in conjunction with the TP

role. Only provide feedback if necessary

here.






PC




23, 2013



23-Dec-2013








element)


element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






TPL-001-4 R8


Requirements











TP, PC




23, 2013

TPL-001-4 R7


Requirements






Appendix B-3


Page 2 of 12



















































Cost

One Time ($)

Cost

Ongoing ($)

Bus-tie Breaker



NOTE: This Glossary Term was included initially under Assessment Report

No. 8, however, adoption was held by the BCUC pending further

reassessment per Order R-38-15. As such, this Glossary Term is now up for

reassessment. A separate TPL-001-4 specific report will be filed per the

BCUC's request. Please provide any feedback here.

No comments.



N/A


Facilities being removed from service by a Protection System operation designed to isolate the

fault.







No comments.



N/A



complete.







No comments.



N/A



user equipment.







No comments.

Planning Assessment









No comments.


Catalyst Paper Corporation, Crofton Division (CPCD), Port Alberni Division (CPPAD), Powell River Division (CPPR) (all registered as DP only with UFLS)



Estimated Incremental/New Costs Associated

with Revised/New Glossary Term and Definition if

any ($) FERC Approved New/Revised/Retired NERC Glossary of Terms from the

November 28, 2016 Glossary of Terms

Acronym

(If Available)


listed in Columns "E" and "F"


Current BCUC Adopted Terms from

December 7, 2015 Glossary of Terms

(Column "B")



Glossary of Terms



Term and Definition

Effective Date of


Term and Definition in

United States



Appendix B-3


Page 3 of 12


FortisBC Inc. (TO, TOP, GO, GOP, PSE, LSE, DP, RP, TP, TSP)

Cost

One Time ($)

Cost

Ongoing ($)

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

See TPL-001-4, R1.

TPL-001-4 R7

Name: Transmission System Planning Performance Requirements

Description: Establish Transmission system planning performance

requirements within the planning horizon to develop a Bulk Electric System

(BES) that will operate reliably over a broad spectrum of System conditions

and following a wide range of probable Contingencies.

4 - Complete revision. Revision of TPL-001-1; includes merging and

upgrading requirements of TPL-001-0, TPL-002-0, TPL-003-0, and TPL-

004-0 into one, single, comprehensive, coordinated standard: TPL-001-2;

and retirement of TPL-005-0 and TPL-006-0.

PC

Docket No. RM12-1-000 and RM13-

9-000, Order 786; Issue Date:

October 17, 2013; Publication Date:

October 23, 2013



NOTE: This requirement applies to the PC role (not yet defined in BC)

in conjunction with the TP role. Only provide feedback if necessary here.

This standard was originally included for assessment under

Assessment Report No. 8, but adoption was held by the BCUC

pending reassessment per Order R-38-15. As such, this standard

is now up for reassessment.


applies to the PC role (not

yet defined in BC) in

conjunction with the TP

role. Only provide

feedback if necessary

here.




conjunction with the TP

role. Only provide

feedback if necessary

here.


(not yet defined in BC) in conjunction with the TP role.

Only provide feedback if necessary here.

23-Dec-2013



For 84 calendar months beginning the first day of the first calendar quarter following applicable regulatory

approval, Corrective Action Plans applying to the following categories of Contingencies and events

identified in TPL-001-4, Table 1 are allowed to include Non-Consequential Load Loss and curtailment of

Firm Transmission Service (in accordance with Requirement R2, Part 2.7.3.) that would not otherwise be

permitted by the requirements of TPL-001-4:

- P1-2 (for controlled interruption of electric supply to local network customers connected to or supplied by

the Faulted element)



- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

See TPL-001-4, R1. See TPL-001-4, R1. See TPL-001-4, R1.






TPL-001-4 R6





TP, PC




October 23, 2013

TPL-001-4 R5










TP, PC 23-Dec-2013

TPL-001-4 R4










TP, PC

See TPL-001-4, R1.

TPL-001-4 R3










TP, PC




October 23, 2013

23-Dec-2013












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

See TPL-001-4, R1. See TPL-001-4, R1. See TPL-001-4, R1. See TPL-001-4, R1.

23-Dec-2013












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

See TPL-001-4, R1. See TPL-001-4, R1. See TPL-001-4, R1.TPL-001-4 R2










TP, PC




October 23, 2013

Recommended effective date is 24 - 36 months after

BCUC approval.23-Dec-2013Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first


Studies using short circuit models with any planned generation and

transmission facilities in service which could impact the study area will

need to be developed and maintained.

Minor modifications to the annual FortisBC planning study will be

required and a new short circuit analyses will be required annually.

30,000-50,0000 15,000-20,000TPL-001-4 R1










TP, PC




October 23, 2013





applicable)

FERC Approved

New/Revised




Standard Name and Description


Standards to be

Superseded

FERC Approved Revision(s) to Standard/Requirement listed in

Standard Version History

Functional Applicability of FERC

Approved





FERC Order Ruling




dates of the FERC

Approval Ruling if

applicable)

FERC Approved Standard/Requirement Implementation Time Provided and US Enforcement

Date


Stakeholder Comments Organizational Activities and



Estimated Incremental/New Costs Associated with

Revision/New Standard/Requirement, if any ($)

See TPL-001-4, R1.





October 23, 2013



9-000

145 FERC ¶ 61,051












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

See TPL-001-4, R1.

23-Dec-2013












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)


Appendix B-3


Page 4 of 12















































































































































































Cost

One Time ($)

Cost

Ongoing ($)

Recommended effective date is 24 - 36 months after

BCUC approval.23-Dec-2013Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first


Studies using short circuit models with any planned generation and

transmission facilities in service which could impact the study area will

need to be developed and maintained.

Minor modifications to the annual FortisBC planning study will be

required and a new short circuit analyses will be required annually.

30,000-50,0000 15,000-20,000TPL-001-4 R1










TP, PC




October 23, 2013





applicable)

FERC Approved

New/Revised




Standard Name and Description


Standards to be

Superseded

FERC Approved Revision(s) to Standard/Requirement listed in

Standard Version History


Approved





FERC Order Ruling




dates of the FERC

Approval Ruling if

applicable)

FERC Approved Standard/Requirement Implementation Time Provided and US Enforcement

Date


Stakeholder Comments Organizational Activities and




Revision/New Standard/Requirement, if any ($)

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

See TPL-001-4, R1.23-Dec-2013












- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

See TPL-001-4, R1. See TPL-001-4, R1. See TPL-001-4, R1.TPL-001-4 R8










TP, PC




October 23, 2013

Appendix B-3


Page 5 of 12







































Cost

One Time ($)

Cost

Ongoing ($)

Bus-tie Breaker


N/A A circuit breaker that is positioned to connect two individual substation bus configurations. New N/A 17-Oct-13 01-Jan-15No additional comments. Please see comments provided to each respective

standard in the Standards feedback survey form.

No additional comments.

Please see comments

provided to each

respective standard in the

Standards feedback

survey form.


Please see comments

provided to each


Standards feedback

survey form.

No additional comments. Please see comments

provided to each respective standard in the

Standards feedback survey form.



N/A


Facilities being removed from service by a Protection System operation designed to isolate

the fault.

New N/A 17-Oct-13 01-Jan-15No additional comments. Please see comments provided to each respective



Please see comments

provided to each


Standards feedback

survey form.


Please see comments

provided to each


Standards feedback

survey form.






N/A



complete.




Please see comments

provided to each


Standards feedback

survey form.


Please see comments

provided to each


Standards feedback

survey form.






N/A



user equipment.




Please see comments

provided to each


Standards feedback

survey form.


Please see comments

provided to each


Standards feedback

survey form.




Planning Assessment




No additional comments. Please see comments provided to each respective



Please see comments

provided to each


Standards feedback

survey form.


Please see comments

provided to each


Standards feedback

survey form.





FortisBC Inc. (TO, TOP, GO, GOP, PSE, LSE, DP, RP, TP, TSP)



Estimated Incremental/New Costs Associated

with Revised/New Glossary Term and Definition

if any ($) FERC Approved New/Revised/Retired NERC Glossary of Terms from

the November 28, 2016 Glossary of Terms

Acronym

(If Available)






(Column "B")



Glossary of Terms


New/Revised/Retired NERC Term

and Definition

Effective Date of


Term and Definition in

United States



Appendix B-3


Page 6 of 12


Cost

One Time ($)

Cost

Ongoing ($)

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

N/A

TPL-001-4 R7



requirements within the planning horizon to develop a Bulk Electric

System (BES) that will operate reliably over a broad spectrum of

System conditions and following a wide range of probable

Contingencies.






PCDocket No. RM12-1-000 and RM13-9-000, Order 786;

Issue Date: October 17, 2013; Publication Date: October

23, 2013

23-Dec-2013Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first calendar

quarter, 12 months after applicable regulatory approval.

NOTE: This requirement applies to the PC role (not yet defined

in BC) in conjunction with the TP role. Only provide feedback

if necessary here. This standard was originally included for

assessment under Assessment Report No. 8, but adoption was

held by the BCUC pending reassessment per Order R-38-15. As

such, this standard is now up for reassessment.




with the TP role. Only

provide feedback if

necessary here.




conjunction with the TP role.

Only provide feedback if

necessary here.

NOTE: This requirement applies to the PC role (not yet

defined in BC) in conjunction with the TP role. Only

provide feedback if necessary here.

23-Dec-2013

Except as indicated below, Requirements R2 through R6 and Requirement R8 shall become effective on the first

day of the first calendar quarter, 24 months after applicable regulatory approval.


Corrective Action Plans applying to the following categories of Contingencies and events identified in TPL-001-4,

Table 1 are allowed to include Non-Consequential Load Loss and curtailment of Firm Transmission Service (in

accordance with Requirement R2, Part 2.7.3.) that would not otherwise be permitted by the requirements of TPL-

001-4:

- P1-2 (for controlled interruption of electric supply to local network customers connected to or supplied by the

Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)

NOTE: This standard was originally included for assessment

under Assessment Report No. 8, but adoption was held by the

BCUC pending reassessment per Order R-38-15. As such, this

standard is now up for reassessment. N/A to DP

0 0






Contingencies.

TPL-001-4 R6






TP, PCDocket No. RM12-1-000 and RM13-9-000, Order 786;


23, 2013

0 0

00TPL-001-4 R5






Contingencies.






TP, PC 23-Dec-2013







001-4:


Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)





23-Dec-2013







001-4:


Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)





TPL-001-4 R4






Contingencies.






TP, PC

N/A

TPL-001-4 R3






Contingencies.








23, 2013

23-Dec-2013







001-4:


Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)





0 0

NOTE: This requirement applies to the PC role (not yet

defined in BC). Only provide feedback if necessary

here.

23-Dec-2013







001-4:


Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)





0 0TPL-001-4 R2






Contingencies.








23, 2013

N/A23-Dec-2013Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first calendar






0 0TPL-001-4 R1






Contingencies.








23, 2013

N/A

N/A

Docket No. RM12-1-000 and RM13-9-000, Order 786;


23, 2013


Docket No. RM12-1-000 and RM13-9-000

145 FERC ¶ 61,051

NORTHWOOD PULP MILL - CANFOR PULP LIMITED PARTNERSHIP (DP)



US Effective Date of FERC Order Ruling


(Each cell is linked to the respective effective

dates of the FERC Approval Ruling if

applicable)


(Each cell is linked to the respective implementation plan and effective dates if applicable)Stakeholder Comments Organizational Activities and




Revision/New Standard/Requirement, if any ($) FERC Order No., Order Date and Order Publication

Date

(Each cell is linked to the respective FERC Order if

applicable)

FERC Approved

New/Revised





be Superseded



History


Approved


Appendix B-3


Page 7 of 12






































































































































































Cost

One Time ($)

Cost

Ongoing ($)

N/A23-Dec-2013Requirements R1 and R7 as well as the definitions shall become effective on the first day of the first calendar






0 0TPL-001-4 R1






Contingencies.








23, 2013



US Effective Date of FERC Order Ruling


(Each cell is linked to the respective effective

dates of the FERC Approval Ruling if

applicable)


(Each cell is linked to the respective implementation plan and effective dates if applicable)Stakeholder Comments Organizational Activities and





Date


applicable)

FERC Approved

New/Revised





be Superseded



History


Approved


TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

N/A23-Dec-2013







001-4:


Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)





0 0TPL-001-4 R8






Contingencies.








23, 2013

Appendix B-3


Page 8 of 12






































Cost

One Time ($)

Cost

Ongoing ($)

Bus-tie Breaker



NOTE: This Glossary Term was included initially under Assessment Report No. 8,

however, adoption was held by the BCUC pending further reassessment per Order R-

38-15. As such, this Glossary Term is now up for reassessment. A separate TPL-001-

4 specific report will be filed per the BCUC's request. Please provide any feedback

here.

N/A to DP

0 0 N/A



N/A



fault.






here.



N/A



complete.






here.

N/A to DP

0 0 N/A



N/A



user equipment.






here. No change

0 0 Immediately after

adoption

Planning Assessment








here.

N/A to DP

0 0 N/A

BCUC

Implementation Time

(Press Alt-Enter to

insert a carriage return

in a cell)

NORTHWOOD PULP MILL - CANFOR PULP LIMITED PARTNERSHIP (DP)

Estimated Incremental/New Costs

Associated with Revised/New Glossary

Term and Definition if any ($) FERC Approved New/Revised/Retired NERC Glossary of Terms from the


Acronym

(If Available)





December 7, 2015

Glossary of Terms

(Column "B")



Glossary of Terms


New/Revised/Retired NERC Term

and Definition

Effective Date of


Term and Definition in United

States



Appendix B-3


Page 9 of 12


Cost

One Time ($)

Cost

Ongoing ($)

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

Docket No. RM12-1-000 and RM13-9-000, Order 786;

Issue Date: October 17, 2013; Publication Date:

October 23, 2013


Docket No. RM12-1-000 and RM13-9-000

145 FERC ¶ 61,051

Teck Metals Ltd. (TO, TOP, GO, GOP)


(Press Alt-Enter to insert a

carriage return in a cell)

US Effective Date of FERC Order Ruling Approving

Standard(s)

(Each cell is linked to the respective effective dates

of the FERC Approval Ruling if applicable)



Stakeholder Comments Organizational

Activities and Reliability/Suitability Impact

(Press Alt-Enter to insert a carriage return

in a cell)



Date


applicable)

FERC Approved

New/Revised



link to open the

Standards)


be Superseded



History

Functional Applicability of FERC Approved


TPL-001-4 R1

Name: Transmission System Planning

Performance Requirements

Description: Establish Transmission system

planning performance requirements within the

planning horizon to develop a Bulk Electric System

(BES) that will operate reliably over a broad

spectrum of System conditions and following a

wide range of probable Contingencies.








October 23, 2013



NOTE: This standard was originally included

for assessment under Assessment Report No.

8, but adoption was held by the BCUC pending

reassessment per Order R-38-15. As such,

this standard is now up for reassessment.

TPL-001-4 R2
















October 23, 2013

23-Dec-2013

Except as indicated below, Requirements R2 through R6 and Requirement R8 shall become effective on the

first day of the first calendar quarter, 24 months after applicable regulatory approval.


approval, Corrective Action Plans applying to the following categories of Contingencies and events identified in

TPL-001-4, Table 1 are allowed to include Non-Consequential Load Loss and curtailment of Firm Transmission

Service (in accordance with Requirement R2, Part 2.7.3.) that would not otherwise be permitted by the



Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






TPL-001-4 R4














TP, PC

TPL-001-4 R3
















October 23, 2013

23-Dec-2013









Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)








defined in BC). Only provide










Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






23-Dec-2013









Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






TPL-001-4 R5














TP, PC 23-Dec-2013









TPL-001-4 R6








October 23, 2013

23-Dec-2013









Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






Appendix B-3


Page 10 of 12































































































































































Cost

One Time ($)

Cost

Ongoing ($)


(Press Alt-Enter to insert a

carriage return in a cell)

US Effective Date of FERC Order Ruling Approving

Standard(s)

(Each cell is linked to the respective effective dates

of the FERC Approval Ruling if applicable)



Stakeholder Comments Organizational

Activities and Reliability/Suitability Impact

(Press Alt-Enter to insert a carriage return

in a cell)



Date


applicable)

FERC Approved

New/Revised



link to open the

Standards)


be Superseded



History

Functional Applicability of FERC Approved


TPL-001-4 R1
















October 23, 2013








TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-0.1

TPL-002-0b

TPL-003-0b

TPL-004-0a

TPL-001-4 R7














PCDocket No. RM12-1-000 and RM13-9-000, Order 786;


October 23, 2013




(not yet defined in BC) in conjunction with the

TP role. Only provide feedback if necessary

here. This standard was originally included for

assessment under Assessment Report No. 8,

but adoption was held by the BCUC pending











with the TP role. Only

provide feedback if

necessary here.






TPL-001-4 R8
















October 23, 2013

23-Dec-2013









Faulted element)


Faulted element)

- P2-1

- P2-2 (above 300 kV)

- P2-3 (above 300 kV)

- P3-1 through P3-5


- P5 (above 300 kV)






Appendix B-3


Page 11 of 12


















































Cost

One Time ($)

Cost

Ongoing ($)

Bus-tie Breaker



NOTE: This Glossary Term was included initially under

Assessment Report No. 8, however, adoption was held by the

BCUC pending further reassessment per Order R-38-15. As

such, this Glossary Term is now up for reassessment. A

separate TPL-001-4 specific report will be filed per the BCUC's

request. Please provide any feedback here.

No comments.



N/A



fault.








No comments.



N/A



complete.








No comments.



N/A



user equipment.








No comments.

Planning Assessment










No comments.



Teck Metals Ltd. (TO, TOP, GO, GOP)


Revised/New Glossary Term and Definition if any ($) FERC Approved New/Revised/Retired NERC Glossary of Terms from the


Acronym

(If Available)






(Column "B")



Glossary of Terms

FERC Approval

Date of

New/Revised/Re

tired NERC

Term and

Definition

Effective Date of

New/Revised/Re

tired NERC Term

and Definition in

United States



Appendix B-3


Page 12 of 12


Appendix C

Draft Order

Sixth floor, 900 Howe Street Vancouver, BC Canada V6Z 2N3 TEL: (604) 660-4700 BC Toll Free: 1-800-663-1385 FAX: (604) 660-1102

…/2

ORDER NUMBER R-xx-xx

IN THE MATTER OF the Utilities Commission Act, RSBC 1996, Chapter 473

and

British Columbia Hydro and Power Authority (BC Hydro)

Mandatory Reliability Standards TPL-001-4 Assessment Report

BEFORE: Commissioner Commissioner Commissioner

on Date

ORDER

WHEREAS:

A. Pursuant to section 125.2(2) of the Utilities Commission Act (UCA) the British Columbia Utilities Commission (Commission) has exclusive jurisdiction to determine whether a “reliability standard” as defined in the UCA, is in the public interest and should be adopted in British Columbia (BC);

B. The Rules of Procedure for Reliability Standards in BC, adopted by Commission Order G-123-09, dated October 15, 2009, and amended by Commission Order R-12-17, states that a reliability standard does not include Compliance Provisions and defines Compliance Provisions as “the compliance-related provisions that accompany, but do not constitute part of, a Commission adopted Reliability Standard”;

C. In order to facilitate the Commission’s consideration of reliability standards, British Columbia Hydro and Power Authority (BC Hydro) is required under section 125.2(3) of the UCA to review each reliability standard established by a standard-making body such as the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC) and provide the Commission with a report (MRS Assessment Report) assessing:

(a) any adverse impact of the reliability standard on the reliability of electricity transmission in BC if the

reliability standard were adopted;

(b) the suitability of the reliability standard for B.C.;

(c) the potential cost of the reliability standard if it were adopted;

(c.1) the application of the reliability standard to persons or persons in respect of specified

equipment if the reliability standard were adopted; and

(d) any other matter prescribed by regulation or identified by order of the Commission;

Order R-xx-xx Page 2 of 4

Filepath

D. Compliance Provisions, including effective dates, are not assessed by BC Hydro. This approach is consistent with that taken in previous Mandatory Reliability Standards (MRS) Assessment Reports;

E. On May 3, 2017, BC Hydro filed the TPL-001-4 Assessment Report (Report) assessing the revised TPL-001-4 reliability standard. BC Hydro assessed the reliability standards excluding the accompanying Compliance Provision. If adopted, the TPL-001-4 revised reliability standard would supersede the existing reliability standards previously adopted by the Commission;

F. The TPL-001-4 reliability standard assessed by BC Hydro in the Report are based on defined terms contained in the NERC Glossary of Terms Used in Reliability Standards dated November 28, 2016 (NERC Glossary). The Report included an assessment of five new defined glossary terms intended for the TPL-001-4 reliability standard (Glossary Terms);

G. To date, BC Hydro has acted as the Planning Authority/Planning Coordinator (PA/PC) for the BC Hydro asset footprint only. The PA/PC responsibilities for the province require clarification at this time. TPL-001-4 considered in the Report contains requirement 7 that pertains to the PC function and BC Hydro recommends that requirement 7 of the revised TPL-001-4 reliability standard be held in abeyance and be of no force or effect in BC until the PC function is resolved;

H. In the Report, BC Hydro concludes that the TPL-001-4 reliability standard, with the exception of requirement 7, and five Glossary Terms are suitable for adoption in B.C. at this time;

I. By Commission Order R–xx-17 dated xxxx, 2017, BC Hydro was directed to publish a Notice of Mandatory Reliability Standard TPL-001-4 Assessment Report and Process for Public Comments and established the Regulatory Timetable for a public comment process;

J. Comments were received from xxxxxxxx;

K. On xxxx, 2017 BC Hydro provided comments in response;

L. Pursuant to section 125.2(6) of the UCA, the Commission must adopt the reliability standard(s) addressed in the Report if the Commission considers that the reliability sandard(s) are required to maintain or achieve consistency in BC with other jurisdictions that have adopted the reliablity standard(s);

M. The Commission has reviewed and considered the Report, the TPL-001-4 reliability standard and Glossary Terms assessed therein, as well as the comments received and considers that the adoption of the recommendations in the Report is warranted; and

N. Although not assessed by BC Hydro, the Commission considers that the Compliance Provisions of the reliability standards should be adopted to maintain compliance monitoring consistency with other jurisdictions that have adopted the reliability standards with the Compliance Provisions and finds it appropriate to provide effective dates for entities to come into compliance with the TPL-001-4 reliability standard and Glossary Terms adopted in this order.


Filepath

NOW THEREFORE pursuant to subsections 125.2(6) and 125.2(10) of the Utilities Commission Act, the British Columbia Utilities Commission (Commission) orders as follows:

1. The Commission adopts the TPL-001-4 reliability standard recommended for adoption in the British Columbia Hydro and Power Authority Mandatory Reliability Standard TPL-001-4 Assessment Report with effective dates in Table 1 of Attachment A to this order and each reliability standard to be superseded by the TPL-001-4 reliability standard adopted in this order shall remain in effect until the effective date of the TPL-001-4 reliability standard superseding it.

2. As a result of this order and previous Commission orders, all the reliability standards listed in Attachment B to this order are in effect in British Columbia (BC) as of the dates shown. The effective dates for the reliability standards listed in Attachment B supersede the effective dates that were included in any similar list appended to any previous order. Attachment B to this order also includes those reliability standards with effective dates held in abeyance to be assessed at a later date.

3. Individual requirements within reliability standards that incorporate, by reference, reliability standards that have not been adopted by the Commission, are of no force and effect in BC.

4. Individual requirements or sub-requirements within reliability standards, which the Commission has adopted but for which the Commission has not determined an effective date, are of no force and effect in BC.

5. The Commission adopts the North American Electric Reliability Corporation (NERC) Glossary of Terms Used in TPL-001-4 reliability standard, found in Attachment C to this order, to define terms employed in the TPL-001-4 reliability standard (Glossary Terms). The effective date of each of the new Glossary Terms adopted in this order is the date in Table 2 of Attachment A to this order.

6. As a result of this order and previous Commission orders, the Glossary Terms listed in Attachment D to this order are Glossary Terms in effect in BC as of the effective dates indicated. The effective dates for the Glossary Terms listed in Attachment D supersede the effective dates that were included in any similar list appended to any previous order.

7. The Commission adopts the Compliance Provisions as defined in the Rules of Procedure for Reliability Standards in British Columbia, that accompany each of the adopted reliability standards, in the form directed by the Commission and as amended from time to time.

8. The reliability standards adopted in BC by the Commission will be posted on the Western Electricity Coordinating Council website with a link from the Commission website.

9. The Commission confirms that entities subject to Mandatory Reliability Standards are required to report to the Commission and may, on a voluntary basis, report to NERC as an Electric Reliability Organization or to the Federal Energy Regulatory Commission.

10. The reliability standards are adopted as set out in Attachment X to this order.


Filepath

DATED at the City of Vancouver, in the Province of British Columbia, this (XX) day of (Month Year).

BY ORDER

(X. X. last name) Commissioner

Attachment Options

Ta

ble

1

Bri

tis

h C

olu

mb

ia U

tiliti

es

Co

mm

iss

ion

Re

lia

bilit

y

Sta

nd

ard

s w

ith

Eff

ec

tive

Da

tes

as

Ad

op

ted

Sta

nd

ard

S

tan

dar

d N

ame

Eff

ecti

ve D

ate

Typ

e C

om

mis

sio

n A

pp

rove

d

Sta

nd

ard

(s)

Bei

ng

S

up

erse

ded

1

TP

L-00

1-4

Tra

nsm

issi

on S

yste

m P

lann

ing

Per

form

ance

Req

uire

men

ts

R1:

Firs

t day

of f

irst c

alen

dar

quar

ter,

two

year

s af

ter

BC

UC

ado

ptio

n.

R2-

R6,

R8:

Firs

t day

of f

irst c

alen

dar

quar

ter,

thre

e ye

ars

afte

r B

CU

C

adop

tion.

For

84

cale

ndar

mon

ths

begi

nnin

g th

e fir

st d

ay o

f the

firs

t cal

enda

r qu

arte

r fo

llow

ing

BC

UC

app

rova

l, C

orre

ctiv

e A

ctio

n P

lans

app

lyin

g to

th

e fo

llow

ing

cate

gorie

s of

Con

tinge

ncie

s an

d ev

ents

iden

tifie

d in

T

PL-

001-

4, T

able

1 a

re a

llow

ed to

incl

ude

Non

-Con

sequ

entia

l Loa

d Lo

ss a

nd c

urta

ilmen

t of F

irm T

rans

mis

sion

Ser

vice

(in

acc

orda

nce

with

R

equi

rem

ent R

2, P

art 2

.7.3

.) th

at w

ould

not

oth

erw

ise

be p

erm

itted

by

the

requ

irem

ents

of T

PL-

001-

4:

- P

1-2

(for

con

trol

led

inte

rrup

tion

of e

lect

ric s

uppl

y to

loca

l net

wor

k cu

stom

ers

conn

ecte

d to

or

supp

lied

by th

e F

aulte

d el

emen

t)

- P

1-3

(for

con

trol

led

inte

rrup

tion

of e

lect

ric s

uppl

y to

loca

l net

wor

k cu

stom

ers

conn

ecte

d to

or

supp

lied

by th

e F

aulte

d el

emen

t)

- P

2-1

- P

2-2

(abo

ve 3

00 k

V)

- P

2-3

(abo

ve 3

00 k

V)

- P

3-1

thro

ugh

P3-

5

- P

4-1

thro

ugh

P4-

5 (a

bove

300

kV

)

- P

5 (a

bove

300

kV

)

R7:

Ado

ptio

n he

ld in

abe

yanc

e at

this

tim

e.2

Rev

ised

TP

L-00

1-0.

1

TP

L-00

2-0b

TP

L-00

3-0b

TP

L-00

4-0a

1

Com

mis

sio

n a

ppro

ved r

elia

bili

ty s

tandard

(s)

to b

e s

up

ers

ed

ed b

y t

he r

evis

ed r

elia

bili

ty s

tand

ard

assesse

d.

2

Una

ble

to a

sse

ss b

ased o

n u

ndefin

ed P

lann

ing C

oord

inato

r/P

lannin

g A

uth

ority

fo

otp

rints

and e

ntities r

esp

on

sib

le.

Ta

ble

2

Bri

tis

h C

olu

mb

ia U

tiliti

es

Co

mm

iss

ion

NE

RC

G

los

sa

ry T

erm

s w

ith

Eff

ec

tive

Da

tes

as

Ad

op

ted

NE

RC

Glo

ssar

y T

erm

1 E

ffec

tive

Dat

e C

om

mis

sio

n A

pp

rove

d T

erm

to

be

Rep

lace

d o

r R

etir

ed

Bus

-tie

Bre

aker

A

lign

with

the

earli

est e

ffect

ive

date

of

TP

L-00

1-4

New

Ter

m

Con

sequ

entia

l Loa

d Lo

ss

Alig

n w

ith th

e ea

rlies

t effe

ctiv

e da

te o

f T

PL-

001-

4 N

ew T

erm

Long

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B.C. Reliability Standards

Standard Name Commission

Order Adopting Effective Date

BAL-001-2 Real Power Balancing Control Performance

R-14-16 July 1, 2016

BAL-002-11 Disturbance Control Performance R-41-13 December 12, 2013

BAL-002-2

Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

BAL-002-WECC-21 Contingency Reserve R-32-14 October 1, 2014

BAL-002-WECC-2a Contingency Reserve

BAL-003-1.1 Frequency Response and Frequency Bias Setting

R-32-16 October 1, 2016

BAL-004-0 Time Error Correction G-67-09 November 1, 2010

BAL-004-WECC-2 Automatic Time Error Correction R-32-14 October 1, 2014

BAL-005-0.2b Automatic Generation Control R-41-13 December 12, 2013 R2: Retired January 21, 20142

BAL-006-2 Inadvertent Interchange R-1-13 April 15, 2013

CIP-002-31 Cyber Security – Critical Cyber Asset Identification

G-162-11 July 1, 2012

CIP-002-5.1 Cyber Security – BES Cyber System Categorization

R-38-15 October 1, 2018

CIP-003-31, 3, 4 Cyber Security – Security Management Controls

G-162-11

July 1, 2012 R1.2, R3, R3.1, R3.2, R3.3, and R4.2: Retired January 21, 20142

CIP-003-51 Cyber Security – Security Management Controls

R-38-15 October 1, 2018

1 Reliability standard is superseded by the revised/replacement reliability standard listed immediately below it as of the

effective date(s) of the revised/replacement reliability standard. 2 On November 21, 2013, FERC Order 788 (referred to as Paragraph 81) approved the retiring of the reliability standard

requirements. 3 Reliability standard is superseded by CIP-010-1 as of the CIP-010-1 effective date. 4 Reliability standard is superseded by CIP-011-1 as of the CIP-011-1 effective date.




CIP-003-6 Cyber Security — Security Management Controls

Adoption held in abeyance at this time5

CIP-004-3a1 Cyber Security - Personnel & Training

R-32-14 August 1, 2014

CIP-004-5.11 Cyber Security – Personnel & Training

R-38-15 October 1, 2018

CIP-004-6 Cyber Security — Personnel & Training

CIP-005-3a1, 3 Cyber Security – Electronic Security Perimeter(s)

R-1-13 July 15, 2013 R2.6: Retired January 21, 20142

CIP-005-5 Cyber Security – Electronic Security Perimeter(s)

R-38-15 October 1, 2018

CIP-006-3c1 Cyber Security – Physical Security of Critical Cyber Assets

G-162-11 July 1, 2012

CIP-006-51 Cyber Security – Physical Security of BES Cyber Systems

R-38-15 October 1, 2018

CIP-006-6 Cyber Security — Physical Security of BES Cyber Systems

CIP-007-3a1, 3, 4 Cyber Security - Systems Security Management

R-32-14 August 1, 2014 R7.3: Retired January 21, 20142

CIP-007-51 Cyber Security – System Security Management

R-38-15 October 1, 2018

CIP-007-6 Cyber Security — System Security Management

CIP-008-31 Cyber Security – Incident Reporting and Response Planning

G-162-11 July 1, 2012

CIP-008-5 Cyber Security – Incident Reporting and Response Planning

R-38-15 October 1, 2018

CIP-009-31 Cyber Security – Recovery Plans for Critical Cyber Assets

G-162-11 July 1, 2012

CIP-009-51 Cyber Security – Recovery Plans for BES Cyber Systems

R-38-15 October 1, 2018

CIP-009-6 Cyber Security — Recovery Plans for BES Cyber Systems

5 BC Hydro recommends that the CIP-003-6 reliability standard be held in abeyance and be of no force or effect in BC due to

technical suitability issues that will not improve reliability and instead place undue burden on responsible entities. When adopted by FERC, the NERC approved CIP-003-7(i) reliability standard will retire CIP-003-6. CIP-003-7(i) is anticipated to be assessed in the next MRS Assessment Report.




CIP-010-11 Cyber Security – Configuration Change Management and Vulnerability Assessments

R-38-15 October 1, 2018

CIP-010-2 Cyber Security – Configuration Change Management and Vulnerability Assessments

CIP-011-11 Cyber Security – Information Protection

R-38-15 October 1, 2018

CIP-011-2 Cyber Security – Information Protection

CIP-014-2 Physical Security R-32-16 October 1, 2017 and as per BC-specific Implementation Plan

COM-001-1.11, 6 Telecommunications G-167-10 January 1, 2011

COM-001-2.11 Communications R-32-16 October 1, 2017

COM-001-3 Communications

COM-002-4 Operating Personnel Communications Protocols

R-32-16 April 1, 2017

EOP-001-2.1b7 Emergency Operations Planning R-32-14 August 1, 2014

EOP-002-3.17 Capacity and Energy Emergencies R-32-14 August 1, 2014

EOP-003-18 Load Shedding Plans G-67-09 November 1, 2010

EOP-003-29 Load Shedding Plans Adoption held in abeyance at this time10

EOP-004-21 Event Reporting R-32-14 August 1, 2015

EOP-004-3 Event Reporting

EOP-005-2 System Restoration and Blackstart Resources

R-32-14 August 1, 2015 R3.1: Retired January 21, 20142

EOP-006-2 System Restoration Coordination R-32-14 August 1, 2014

6 Requirement 4 of the reliability standard is superseded by COM-002-4 as of the COM-002-4 effective date. 7 Reliability standard is superseded by EOP-011-1 as of the EOP-011-1 effective date. 8 Reliability standard would be superseded by EOP-003-2 if adopted in B.C. Adoption of EOP-003-2 pending reassessment. 9 Reliability standard is superseded by EOP-011-1 as of the EOP-011-1 effective date in conjunction with PRC-010-2

Requirement 1 if adopted in B.C. Adoption of PRC-010-2 pending reassessment. 10 Unable to assess based on undefined Planning Coordinator/Planning Authority footprints and entities responsible. The

Commission Reasons for Decision for Order No. R-41-13 (page 20), indicated that a separate process would be established to consider this matter as it pertains to B.C.




EOP-008-1 Loss of Control Center Functionality

R-32-14 August 1, 2015

EOP-010-111 Geomagnetic Disturbance Operations

R-38-15 R1, R3: October 1, 2016

R2:

EOP-011-1 Emergency Operations

FAC-001-2 Facility Interconnection Requirements

R-38-15 October 1, 2016

FAC-002-2 Facility Interconnection Studies R-38-15 October 1, 2015

FAC-003-31 Transmission Vegetation Management

R-32-14 August 1, 2015

FAC-003-4 Transmission Vegetation Management

FAC-501-WECC-1 Transmission Maintenance R-1-13 April 15, 2013

FAC-008-3 Facility Ratings R-32-14 August 1, 2015 R4 and R5: Retired January 21, 20142

FAC-010-2.11 System Operating Limits Methodology for the Planning Horizon

G-162-11 October 30, 2011 R5: Retired January 21, 20142

FAC-010-3 System Operating Limits Methodology for the Planning Horizon

FAC-011-21 System Operating Limits Methodology for the Operations Horizon

G-167-10 January 1, 2011 R5: Retired January 21, 20142

FAC-011-3 System Operating Limits Methodology for the Operations Horizon

FAC-013-112 Establish and Communicate Transfer Capability

G-67-09 November 1, 2010

FAC-013-2

Assessment of Transfer Capability

for the Near-Term Transmission

Planning Horizon


11 Requirement 2 of the reliability standard will be effective upon the retirement of IRO-005-3.1a Requirement 3 which follows

the effective date of IRO-002-4. 12 Reliability standard would be superseded by the FAC-013-2 if adopted in B.C. Adoption of FAC-013-2 pending

reassessment.




FAC-014-2 Establish and Communicate System Operating Limits

G-167-10 January 1, 2011

INT-004-3.1 Dynamic Transfers R-38-15 R1, R2: October 1, 2015

R3: January 1, 2016

INT-006-4 Evaluation of Interchange Transactions

R-38-15 October 1, 2015

INT-009-2.1 Implementation of Interchange R-38-15 October 1, 2015

INT-010-2.1 Interchange Initiation and Modification for Reliability

R-38-15 October 1, 2015

INT-011-1.1 Intra-Balancing Authority Transaction Identification

R-38-15 October 1, 2015

IRO-001-1.113 Reliability Coordination Responsibilities and Authorities

G-167-10 January 1, 2011

IRO-001-4 Reliability Coordination – Responsibilities

IRO-002-213 Reliability Coordination – Facilities R-1-13 April 15, 2013

IRO-002-4 Reliability Coordination – Monitoring and Analysis

IRO-003-213 Reliability Coordination – Wide Area View

G-67-09 November 1, 2010

IRO-004-213 Reliability Coordination – Operations planning

R-1-13 April 15, 2013

IRO-005-3.1a13,14 Reliability Coordination - Current Day Operations

R-32-14 August 1, 2014

IRO-006-5 Reliability Coordination – Transmission Loading Relief

R-1-13 April 15, 2013

IRO-006-WECC-2 Qualified Transfer Path Unscheduled Flow (USF) Relief

R-38-15 October 1, 2015

IRO-008-113 Reliability Coordinator Operational Analyses and Real-time Assessments

R-1-13 April 15, 2013

IRO-008-2 Reliability Coordinator Operational Analyses and Real-time Assessments

13 See “IRO and TOP Reliability Standards Supersession Mapping” section below. 14 Requirement 3 of the reliability standard is superseded by EOP-010-1 Requirement 2 as of the IRO-002-4 effective date.




IRO-009-11 Reliability Coordinator Actions to Operate Within IROLs

R-1-13 April 15, 2013

IRO-009-2 Reliability Coordinator Actions to Operate Within IROLs

IRO-010-1a13 Reliability Coordinator Data Specification and Collection

R-1-13 April 15, 2013

IRO-010-2 Reliability Coordinator Data Specification and Collection

IRO-014-113 Procedures, Processes, or Plans to Support Coordination Between Reliability coordinators

G-67-09 November 1, 2010

IRO-014-3 Coordination Among Reliability Coordinators

IRO-015-113 Notification and Information Exchange

G-67-09 November 1, 2010

IRO-016-113 Coordination of Real-Time Activities

G-67-09 November 1, 2010 R2: Retired January 21, 20142

IRO-017-1 Outage Coordination

IRO-018-1 Reliability Coordinator Real-time Reliability Monitoring and Analysis Capabilities

MOD-001-1a Available Transmission System Capability

G-175-11 November 30, 2011

MOD-004-1 Capacity Benefit Margin G-175-11 November 30, 2011

MOD-008-1 Transmission Reliability Margin Calculation Methodology

G-175-11 November 30, 2011

MOD-010-015

Steady-State Data for Modeling and Simulation for the Interconnected Transmission System

G-67-09 November 1, 2010

15 Reliability standard will be superseded by MOD-032-1 and MOD-033-1 if adopted in B.C. Adoption of MOD-032-1 and

MOD-033-1 pending reassessment.




MOD-012-015 Dynamics Data for Modeling and Simulation of the Interconnected Transmission System

G-67-09 November 1, 2010

MOD-020-0

Providing Interruptible Demands and Direct Control Load management Data to System Operators and Reliability Coordinators

G-67-09 November 1, 2010

MOD-025-2

Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability

R-38-15

40% by October 1, 2017



100% by October 1, 2020

MOD-026-1

Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions

R-38-15

R1: October 1, 2016

R2: 30% by October 1, 2019


100% by October 1, 2025

R3-R6: October 1, 2015

MOD-027-1

Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions

R-38-15

R1: October 1, 2016

R2: 30% by October 1, 2019


100% by October 1, 2025

R3-R5: October 1, 2015

MOD-028-2 Area Interchange Methodology R-32-14 August 1, 2014

MOD-029-1a1 Rated System Path Methodology G-175-11 November 30, 2011

MOD-029-2a Rated System Path Methodology

MOD-030-21 Flowgate Methodology G-175-11 November 30, 2011

MOD-030-3 Flowgate Methodology

MOD-031-11 Demand and Energy Data R-32-16 October 1, 2016

MOD-031-2 Demand and Energy Data

MOD-032-1 Data for Power System Modeling and Analysis

R-38-15 Effective date held in abeyance10

MOD-033-1 Steady-State and Dynamic System Model Validation

R-38-15 Effective date held in abeyance10

NUC-001-3 Nuclear Plant Interface Coordination

R-38-15 January 1, 2016




PER-001-0.213 Operating Personnel Responsibility and Authority

R-41-13 December 12, 2013

PER-002-0 Operating Personnel Training G-67-09 November 1, 2010

PER-003-1 Operating Personnel Credentials R-41-13 January 1, 2015

PER-004-2 Reliability Coordination – Staffing R-1-13 January 15, 2013

PER-005-2 Operations Personnel Training R-38-15 R1-R4, R6: October 1, 2016

R5: October 1, 2017

PRC-001-1.1(ii) System Protection Coordination R-32-16 October 1, 2016

PRC-002-2 Disturbance Monitoring and Reporting Requirements

R-32-16

R1, R5: April 1, 2017

R2-R4, R6-R11: staged as per BC-specific Implementation Plan

R12: July 1, 2017

PRC-004-2.1a1 Analysis and Mitigation of Transmission and Generation Protection System Misoperations

R-32-14 August 1, 2014

PRC-004-5(i) Protection System Misoperation Identification and Correction

R-32-16 October 1, 2017

PRC-004-WECC-11 Protection System and Remedial Action Scheme Misoperation

R-1-13 July 15, 2013

PRC-004-WECC-2 Protection System and Remedial Action Scheme Misoperation

PRC-005-1.1b1,18 Transmission and Generation Protection System Maintenance and Testing

R-32-14 January 1, 2015

PRC-005-21 Protection System Maintenance R-38-15

R1, R2, R5: October 1, 2017

R3, R4: staged as per BC-specific Implementation Plan

PRC-005-2(i)1 Protection System Maintenance R-32-16

R1, R2, R5: October 1, 2017

R3, R4: staged as per BC-specific Implementation Plan

PRC-005-6 Protection System, Automatic Reclosing, and Sudden Pressure Relaying Maintenance




PRC-006-216 Automatic Underfrequency Load Shedding


PRC-007-017 Assuring consistency of entity Underfrequency Load Shedding Program Requirements

G-67-09 November 1, 2010

PRC-008-018

Implementation and Documentation of Underfrequency Load Shedding Equipment Maintenance Program

G-67-09 November 1, 2010

PRC-009-017

Analysis and Documentation of Underfrequency Load Shedding Performance Following an Underfrequency Event

G-67-09 November 1, 2010

PRC-010-01

Technical Assessment of the Design and Effectiveness of Undervoltage Load Shedding Program


PRC-010-2 Under Voltage Load Shedding Adoption held in abeyance at this time10

PRC-011-018 Undervoltage Load Shedding system Maintenance and Testing

G-67-09 November 1, 2010

PRC-015-01 Special Protection System Data and Documentation

G-67-09 November 1, 2010

PRC-015-1 Remedial Action Scheme Data and Documentation

PRC-016-0.11 Special Protection System Misoperations

G-167-10 January 1, 2011

PRC-016-1 Remedial Action Scheme Misoperations

PRC-017-01,18 Special Protection System Maintenance and Testing

G-67-09 November 1, 2010

PRC-017-118 Remedial Action Scheme Maintenance and Testing

PRC-018-119 Disturbance Monitoring Equipment Installation and Data Reporting

G-67-09 November 1, 2010

16 Reliability standard supersedes PRC-006-1 which has been held in abeyance due to the undefined Planning

Coordinator/Planning Authority footprints and entities responsible. 17 Reliability standard will be superseded by PRC-006-2 if adopted in B.C. Adoption of PRC-006-2 pending reassessment. 18 Reliability standard is superseded by PRC-005-6 as per the PRC-005-6 BC specific Implementation Plan. 19 Reliability standard is superseded by PRC-002-2 as of the PRC-002-2 effective date.




PRC-019-2

Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection

R-32-16




100% by October 1, 2020

PRC-021-120 Under Voltage Load Shedding Program Data

G-67-09 November 1, 2010

PRC-022-120 Under Voltage Load Shedding Program Performance


PRC-023-21,21 Transmission Relay Loadability R-41-13

R1-R5: For circuits identified by sections 4.2.1.1 and 4.2.1.4: January 1, 2016 For circuits identified by sections 4.2.1.2, 4.2.1.3, 4.2.1.5, and 4.2.1.6: To be determined10 R6: To be determined10

PRC-023-31 Transmission Relay Loadability R-38-15

R1-R5: regarding circuits 4.2.1.1 and 4.2.1.4 January 1, 2016

R1-R5: Circuits 4.2.1.2, 4.2.1.3, 4.2.1.5 and 4.2.1.6: To be determined7

R6: To be determined10

PRC-023-4 Transmission Relay Loadability

PRC-024-2 Generator Frequency and Voltage Protective Relay Settings

R-32-16




100% by October 1, 2020

PRC-025-1 Generator Relay Loadability R-38-15




100% by October 1, 2020

PRC-026-1 Relay Performance During Stable Power Swings


TOP-001-1a13 Reliability Responsibilities and Authorities

R-1-13 January 15, 2013

20 Reliability standard is superseded by PRC‐010‐2 if adopted in B.C. Adoption of PRC-010-2 pending reassessment. 21 PRC-023-2 Requirement 1, Criterion 6 only is superseded by PRC-025-1 as of PRC-025-1’s 100 per cent Effective Date.




TOP-001-3 Transmission Operations

TOP-002-2.1b13 Normal Operations Planning R-41-13 December 12, 2013

TOP-002-4 Operations Planning

TOP-003-113 Planned Outage Coordination R-1-13 April 15, 2013

TOP-003-3 Operational Reliability Data

TOP-004-213 Transmission Operations G-167-10 January 1, 2011

TOP-005-2a13 Operational Reliability Information R-1-13 April 15, 2013

TOP-006-213 Monitoring System Conditions R-1-13 April 15, 2013

TOP-007-013

Reporting System Operating Unit (SOL) and Interconnection Reliability Operating Limit (IROL) Violations

G-67-09 November 1, 2010

TOP-007-WECC-1a System Operating Limits R-38-15 October 1, 2015

TOP-008-113 Response to Transmission Limit Violations

G-67-09 November 1, 2010

TOP-010-1 Real-time Reliability Monitoring and Analysis Capabilities

TPL-001-0.122 System Performance Under Normal (No Contingency) Conditions (Category A)

G-167-10 January 1, 2011

TPL-001-4 Transmission System Planning Performance Requirements

TPL-002-0b22 System Performance Following Loss of a Single Bulk Electric System Element (Category B)

R-1-13 January 15, 2013

TPL-003-0b22

System Performance Following Loss of Two or More Bulk Electric System Elements (Category C)

R-32-14 August 1, 2014

TPL-004-0a22

System Performance Following Extreme Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D)

R-32-14 August 1, 2014

22 Reliability standard will be superseded by TPL‑001‑4 Requirements 2-6, and 8 as of their effective dates.




TPL-007-1 Transmission System Planned Performance for Geomagnetic Disturbance Events


VAR-001-4.1 Voltage and Reactive Control R-32-16 October 1, 2016

VAR-002-4 Generator Operation for Maintaining Network Voltage Schedules

R-32-16 October 1, 2016

VAR-002-WECC-2 Automatic Voltage Regulators (AVR)

R-32-16 October 1, 2016

VAR-501-WECC-2 Power System Stabilizer (PSS) R-32-16 October 1, 2016

IRO and TOP Reliability Standards

Supersession Mapping

This following mapping shows the supersession of Requirements for the following IRO, TOP, and PER reliability standards

by the revised/replacement IRO and TOP reliability standards adopted or yet to be adopted in B.C. as of the effective date in

the “B.C. Reliability Standards” section above:

IRO-001-1.1 — Reliability Coordination - Responsibilities and Authorities

IRO-002-2 — Reliability Coordination - Facilities

IRO-003-2 — Reliability Coordination - Wide-Area View

IRO-004-2 — Reliability Coordination - Operations Planning

IRO-005-3.1a — Reliability Coordination - Current Day Operations

IRO-008-1 — Reliability Coordinator Operational Analyses and Real-time Assessments

IRO-010-1a — Reliability Coordinator Data Specification and Collection

IRO-014-1 — Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators

IRO-015-1 — Notifications and Information Exchange Between Reliability Coordinators

IRO-016-1 — Coordination of Real-time Activities Between Reliability Coordinators

PER-001-0.2 — Operating Personnel Responsibility and Authority

TOP-001-1a — Reliability Responsibilities and Authorities

TOP-002-2.1b — Normal Operations Planning

TOP-003-1 — Planned Outage Coordination

TOP-004-2 — Transmission Operations

TOP-005-2a — Operational Reliability Information

TOP-006-2 — Monitoring System Conditions

TOP-007-0 — Reporting System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL)

Violations

TOP-008-1 — Response to Transmission Limit Violations

Standard IRO-001-1.1 — Reliability Coordination - Responsibilities and Authorities

Requirement Being Superseded Superseding BCUC Approved Standard(s)

Requirements R1-R6, R8, R9 IRO-001-4

Requirement R7 IRO-014-3

Standard IRO-002-2 — Reliability Coordination – Facilities


Requirements R1, R3-R5, R7, and R8 IRO-002-4



Standard IRO-003-2 — Reliability Coordination - Wide-Area View


All Requirements IRO-002-4

http://www.nerc.com/files/PER-001-0_2.pdf

http://www.nerc.com/files/PER-001-0_2.pdf



Standard IRO-004-2 — Reliability Coordination - Operations Planning



IRO-008-2

Standard IRO-005-3.1a — Reliability Coordination - Current Day Operations


Requirements R1-R3 IRO-002-4


Requirements R5 and R8 IRO-001-4

IRO-002-4


IRO-017-1


IRO-002-4


IRO-010-2


TOP-001-3

Requirement R11 MOD-001-2, Requirement R2 (pending FERC adoption in the

U.S. and subsequent assessment and adoption in B.C.)


Standard IRO-008-1 — Reliability Coordination - Current Day Operations



Standard IRO-010-1a — Reliability Coordinator Data Specification and Collection



Standard IRO-014-1 — Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators



IRO-010-2

Requirements R2-R4 IRO-014-3



Standard IRO-015-1 — Notifications and Information Exchange Between Reliability Coordinators




Standard IRO-016-1 — Coordination of Real-time Activities Between Reliability Coordinators



Standard PER-001-0.2 — Operating Personnel Responsibility and Authority


All Requirements TOP-001-3

Standard TOP-001-1a — Reliability Responsibilities and Authorities


Requirements R1, R2, R4, R5, R6 TOP-001-3


TOP-001-3

Requirement R7 TOP-001-3

TOP-003-3

IRO-010-2

Requirement R8 EOP-003-2, Requirement 1 (adoption held in abeyance in B.C.

due to PA/PC dependencies)

IRO-009-1



Standard TOP-003-1 — Planned Outage Coordination



TOP-003-3


TOP-003-3



IRO-017-1

Standard TOP-002-2.1b — Normal Operations Planning



TOP-002-4

Requirements R2, R5-R9, R12 TOP-002-4


TOP-003-3


IRO-008-2


TOP-001-3

TOP-002-4

TOP-003-3


TOP-002-4


TOP-003-3

Requirements R14, R15, and R19 TOP-003-3

Requirements R16, R17, and R18 IRO-010-2



Standard TOP-004-2 — Transmission Operations




TOP-002-4

Requirements R3 and R4 TOP-001-3

Requirement R5 Retired


TOP-001-3

Standard TOP-005-2a — Operational Reliability Information



TOP-003-3


Requirement R3 Retired

Standard TOP-006-2 — Monitoring System Conditions



TOP-001-3

TOP-003-3


TOP-001-3


TOP-003-3



TOP-001-3



TOP-001-3



Standard TOP-007-0 — Reporting System Operating Limit (SOL) and Interconnection Reliability Operating Limit

(IROL) Violations



TOP-001-3


TOP-001-3

Requirement R3 EOP-003-2, Requirement 1 (adoption held in abeyance in B.C.


IRO-009-1


Standard TOP-008-1 — Response to Transmission Limit Violations


Requirements R1 EOP-003-2, Requirement 1 (adoption held in abeyance in B.C.


TOP-001-3

Requirements R2 and R3 TOP-001-3


TOP-002-4

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thro

ugh

ten

or b

eyon

d w

hen

requ

ired

to

acco

mm

odat

e an

y kn

own

long

er le

ad ti

me

proj

ects

that

may

take

long

er th

an te

n ye

ars

to c

ompl

ete.

Non

-Con

sequ

entia

l Loa

d Lo

ss

8/4/

2011

10

/17/

2013

(B

ecom

es

effe

ctiv

e 1/

1/15

)

Non

-Int

erru

ptib

le L

oad

loss

that

doe

s no

t inc

lude

: (1)

Con

sequ

entia

l Loa

d Lo

ss, (

2) th

e re

spon

se o

f vo

ltage

sen

sitiv

e Lo

ad, o

r (3

) Lo

ad th

at is

dis

conn

ecte

d fr

om th

e S

yste

m b

y en

d-us

er e

quip

men

t.

Pla

nnin

g A

sses

smen

t 8/

4/20

11

10/1

7/20

13

(Bec

omes

ef

fect

ive

1/1/

15)

Doc

umen

ted

eval

uatio

n of

futu

re T

rans

mis

sion

Sys

tem

per

form

ance

and

Cor

rect

ive

Act

ion

Pla

ns to

re

med

y id

entif

ied

defic

ienc

ies.

Bri

tish

Co

lum

bia

(B

.C.)

Excep

tio

ns t

o t

he

Glo

ssary

of

Term

s U

se

d i

n N

ort

h

Am

eri

can

Ele

ctr

ic R

elia

bilit

y C

orp

ora

tio

n (

NE

RC

) R

eli

ab

ilit

y S

tan

dard

s

(NE

RC

Glo

ss

ary

) U

pdate

d

,

2017

Intr

od

ucti

on

:

This

docu

ment

is to b

e u

sed in c

onju

nction

with t

he N

ER

C G

lossary

date

d N

ovem

ber

28,

2016.

The N

ER

C G

lossary

term

s lis

ted in T

able

1 b

elo

w a

re e

ffective in B

.C.

on the d

ate

specifie

d in t

he “

Effective D

ate”

colu

mn

.

Table

2 b

elo

w o

utlin

es t

he a

doption h

isto

ry b

y t

he C

om

mis

sio

n o

f th

e N

ER

C G

lossar ies in B

.C.

Any N

ER

C G

lossary

term

s a

nd

definitio

ns in t

he N

ER

C G

lossary

that

are

not

appro

ved b

y F

ER

C o

n o

r befo

re

Novem

ber

30,

2016 a

re o

f no f

orc

e o

r eff

ect

in B

.C.

With t

he e

xce

ptions o

f eig

ht

NE

RC

Glo

ssary

term

s a

nd

definitio

ns inte

nded f

or

the B

AL-0

02-2

relia

bili

ty s

tandard

that

were

FE

RC

app

roved in the N

ER

C G

lossary

of

Term

s

as o

f F

ebru

ary

7,

2017

and a

ssessed in M

RS

Assessm

ent

Report

No.

10. T

hese e

ight N

ER

C G

lossary

term

s a

re

inclu

de

d in T

able

1 b

elo

w.

Any N

ER

C G

lossary

term

s that

have b

een r

em

anded o

r re

tire

d b

y N

ER

C a

re o

f no forc

e o

r eff

ect in

B.C

., w

ith the

exce

ption o

f th

ose r

em

anded o

r re

tire

d N

ER

C G

lossary

term

s w

hic

h h

ave n

ot

yet

been r

etire

d in B

.C.

The E

lectr

ic R

elia

bili

ty C

ouncil

of T

exas, N

ort

heast

Pow

er

Coord

inating C

oun

cil

and R

elia

bili

ty F

irst re

gio

na

l definitio

ns lis

ted a

t th

e e

nd o

f th

e N

ER

C G

lossary

have b

een a

dopte

d b

y t

he N

ER

C B

oard

of

Tru

ste

es f

or

use in

regio

na

l sta

ndard

s a

nd a

re o

f no forc

e o

r effect in

B.C

.

Ta

ble

1

B.C

. E

ffe

cti

ve

Da

te E

xc

ep

tio

ns

to

De

fin

itio

ns

in

th

e N

ove

mb

er

2

8, 2

01

6 V

ers

ion

of

the

NE

RC

Glo

ss

ary

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Adj

acen

t Bal

anci

ng A

utho

rity

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Oct

ober

1, 2

015

Alte

rnat

ive

Inte

rper

sona

l C

omm

unic

atio

n -

Rep

ort N

o. 9

R

-32-

16

Ado

ptio

n O

ctob

er 1

, 201

7

Are

a C

ontr

ol E

rror

(fro

m N

ER

C s

ectio

n of

the

Glo

ssar

y)

AC

E

Rep

ort N

o. 7

R

-32-

14

Ado

ptio

n O

ctob

er 1

, 201

4

Are

a C

ontr

ol E

rror

(fro

m th

e W

EC

C R

egio

nal D

efin

ition

s se

ctio

n of

the

Glo

ssar

y)

AC

E

Rep

ort N

o. 7

R

-32-

14

Ret

irem

ent

Oct

ober

1, 2

014

Arr

ange

d In

terc

hang

e -

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n O

ctob

er 1

, 201

5

Atta

inin

g B

alan

cing

Aut

horit

y -

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n O

ctob

er 1

, 201

5

Aut

omat

ic T

ime

Err

or C

orre

ctio

n -

Rep

ort N

o. 7

R

-32-

14

Ado

ptio

n O

ctob

er 1

, 201

4

Bal

anci

ng C

ontin

genc

y E

vent

1 -

Rep

ort N

o. 1

0

Ado

ptio

n

BE

S C

yber

Ass

et2

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

BE

S C

yber

Ass

et

BC

A

Rep

ort N

o. 1

0

Ado

ptio

n

BE

S C

yber

Sys

tem

-

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

1

FE

RC

app

rove

d te

rms

in th

e N

ER

C G

loss

ary

of T

erm

s as

of F

ebru

ary

7, 2

017;

inte

nded

for

BA

L-00

2-2.

2

N

ER

C G

loss

ary

term

def

initi

on is

sup

erse

ded

by th

e re

vise

d N

ER

C G

loss

ary

term

def

initi

on li

sted

imm

edia

tely

bel

ow it

as

of th

e ef

fect

ive

date

(s)

of th

e re

vise

d N

ER

C

Glo

ssar

y te

rm d

efin

ition

.

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

BE

S C

yber

Sys

tem

Info

rmat

ion

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Bla

ckst

art C

apab

ility

Pla

n -

Rep

ort N

o. 7

R

-32-

14

Ret

irem

ent

Aug

ust 1

, 201

5

Bla

ckst

art R

esou

rce2

- R

epor

t No.

6

R-4

1-13

A

dopt

ion

Dec

embe

r 12

, 201

3

Bla

ckst

art R

esou

rce

- R

epor

t No.

10

A

dopt

ion

Bul

k E

lect

ric S

yste

m

BE

S

Rep

ort N

o. 8

R

-38-

15

- O

ctob

er 1

, 201

5

Bul

k-P

ower

Sys

tem

2 -

Rep

ort N

o. 8

R

-38-

15

- O

ctob

er 1

, 201

5

Bul

k-P

ower

Sys

tem

-

Rep

ort N

o. 1

0

Ado

ptio

n

Bus

-tie

Bre

aker

-

TP

L-00

1-4

Rep

ort

A

dopt

ion

Cas

cadi

ng

- R

epor

t No.

10

A

dopt

ion

CIP

Exc

eptio

nal C

ircum

stan

ce

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

CIP

Sen

ior

Man

ager

-

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Com

posi

te C

onfir

med

Inte

rcha

nge

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Oct

ober

1, 2

015

Con

firm

ed In

terc

hang

e -

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n O

ctob

er 1

, 201

5

Com

posi

te P

rote

ctio

n S

yste

m

- R

epor

t No.

9

R-3

2-16

A

dopt

ion

Oct

ober

1, 2

017

Con

sequ

entia

l Loa

d Lo

ss

- T

PL-

001-

4 R

epor

t

Ado

ptio

n

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Con

tinge

ncy

Eve

nt R

ecov

ery

Per

iod1

- R

epor

t No.

10

A

dopt

ion

Con

tinge

ncy

Res

erve

1 -

Rep

ort N

o. 1

0

Ado

ptio

n

Con

tinge

ncy

Res

erve

Res

tora

tion

Per

iod1

- R

epor

t No.

10

A

dopt

ion

Con

trol

Cen

ter

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Crit

ical

Ass

ets

- R

epor

t No.

9

R-3

2-16

R

etire

men

t S

epte

mbe

r 30

, 201

8

Crit

ical

Cyb

er A

sset

s -

Rep

ort N

o. 9

R

-32-

16

Ret

irem

ent

Sep

tem

ber

30, 2

018

Cyb

er A

sset

s -

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Cyb

er S

ecur

ity In

cide

nt

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Dem

and-

Sid

e M

anag

emen

t D

SM

R

epor

t No.

9

R-3

2-16

A

dopt

ion

Oct

ober

1, 2

016

Dia

l-up

Con

nect

ivity

-

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Dis

trib

utio

n P

rovi

der

DP

R

epor

t No.

10

A

dopt

ion

Dyn

amic

Inte

rcha

nge

Sch

edul

e or

D

ynam

ic S

ched

ule

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Oct

ober

1, 2

015

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Ele

ctro

nic

Acc

ess

Con

trol

or

Mon

itorin

g S

yste

ms

EA

CM

S

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Ele

ctro

nic

Acc

ess

Poi

nt

EA

P

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Ele

ctro

nic

Sec

urity

Per

imet

er

ES

P

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Ele

men

t -

Rep

ort N

o. 1

0

Ado

ptio

n

Ene

rgy

Em

erge

ncy

- R

epor

t No.

9

R-3

2-16

A

dopt

ion

Oct

ober

1, 2

016

Ext

erna

l Rou

tabl

e C

onne

ctiv

ity

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Fre

quen

cy B

ias

Set

ting

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

arlie

st e

ffect

ive

date

of B

AL-

003-

1 st

anda

rd

whe

re th

is te

rm is

ref

eren

ced

Fre

quen

cy R

espo

nse

Mea

sure

F

RM

R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

arlie

st e

ffect

ive

date

of B

AL-

003-

1 st

anda

rd

whe

re th

is te

rm is

ref

eren

ced

Fre

quen

cy R

espo

nse

Obl

igat

ion

FR

O

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n A

lign

with

ear

liest

effe

ctiv

e da

te o

f BA

L-00

3-1

stan

dard

w

here

this

term

is r

efer

ence

d

Fre

quen

cy R

espo

nse

Sha

ring

Gro

up

FR

SG

R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

arlie

st e

ffect

ive

date

of B

AL-

003-

1 st

anda

rd

whe

re th

is te

rm is

ref

eren

ced

Gen

erat

or O

pera

tor

GO

P

Rep

ort N

o. 1

0

Ado

ptio

n

Gen

erat

or O

wne

r G

O

Rep

ort N

o. 1

0

Ado

ptio

n

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Geo

mag

netic

Dis

turb

ance

Vul

nera

bilit

y A

sses

smen

t or

GM

D V

ulne

rabi

lity

Ass

essm

ent

GM

D

Rep

ort N

o. 1

0

Ado

ptio

n T

o be

det

erm

ined

3

Inte

ract

ive

Rem

ote

Acc

ess

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Inte

rcha

nge

Aut

horit

y IA

R

epor

t No.

10

A

dopt

ion

Inte

rcon

nect

ed O

pera

tions

Ser

vice

-

Rep

ort N

o. 1

0

Ado

ptio

n

Inte

rcon

nect

ion

- R

epor

t No.

10

A

dopt

ion

Inte

rcon

nect

ion

Rel

iabi

lity

Ope

ratin

g Li

mit

IRO

L R

epor

t No.

6

R-4

1-13

A

dopt

ion

Dec

embe

r 12

, 201

3

Inte

rmed

iate

Bal

anci

ng A

utho

rity

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Oct

ober

1, 2

015

Inte

rmed

iate

Sys

tem

-

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Inte

rper

sona

l Com

mun

icat

ion

- R

epor

t No.

9

R-3

2-16

A

dopt

ion

Oct

ober

1, 2

017

Load

-Ser

ving

Ent

ity

LSE

R

epor

t No.

10

A

dopt

ion

Long

-Ter

m T

rans

mis

sion

Pla

nnin

g H

oriz

on

- T

PL-

001-

4 R

epor

t

Ado

ptio

n

Low

Impa

ct B

ES

Cyb

er S

yste

m

Ele

ctro

nic

Acc

ess

Poi

nt4

LEA

P

Rep

ort N

o. 1

0

Ado

ptio

n N

ot r

ecom

men

ded

for

adop

tion

in B

.C a

t thi

s tim

e.

3

The

NE

RC

Glo

ssar

y te

rm is

ass

ocia

ted

with

rel

iabi

lity

stan

dard

that

is d

epen

dent

on

the

Pla

nnin

g A

utho

rity/

Pla

nnin

g C

oord

inat

or fu

nctio

n. T

he B

CU

C R

easo

ns fo

r D

ecis

ion

for

Ord

er N

o. R

-41-

13 (

page

20)

, ind

icat

ed th

at a

sep

arat

e pr

oces

s w

ould

be

esta

blis

hed

to c

onsi

der

this

mat

ter

as it

per

tain

s to

BC

. 4

Inte

nded

for

CIP

-003

-6 a

nd to

be

held

in a

beya

nce

and

be o

f no

forc

e or

effe

ct in

B.C

. due

to te

chni

cal s

uita

bilit

y is

sues

. Whe

n ad

opte

d by

FE

RC

, the

NE

RC

app

rove

d

CIP

-003

-7(i)

will

ret

ire th

e N

ER

C G

loss

ary

term

s. C

IP-0

03-7

(i) is

ant

icip

ated

to b

e as

sess

ed in

the

next

MR

S A

sses

smen

t Rep

ort.

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Low

Impa

ct E

xter

nal R

outa

ble

Con

nect

ivity

4 LE

RC

R

epor

t No.

10

A

dopt

ion

Not

rec

omm

ende

d fo

r ad

optio

n in

B.C

at t

his

time.

Min

imum

Veg

etat

ion

Cle

aran

ce

Dis

tanc

e M

VC

D

Rep

ort N

o. 7

R

-32-

14

Ado

ptio

n A

ugus

t 1, 2

015

Mis

oper

atio

n -

Rep

ort N

o. 9

R

-32-

16

Ado

ptio

n O

ctob

er 1

, 201

7

Mos

t Sev

ere

Sin

gle

Con

tinge

ncy1

MS

SC

R

epor

t No.

10

A

dopt

ion

Nat

ive

Bal

anci

ng A

utho

rity

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Oct

ober

1, 2

015

Non

-Con

sequ

entia

l Loa

d Lo

ss

- T

PL-

001-

4 R

epor

t

Ado

ptio

n

Ope

ratin

g In

stru

ctio

n -

Rep

ort N

o. 9

R

-32-

16

Ado

ptio

n A

pril

1, 2

017

Ope

ratio

nal P

lann

ing

Ana

lysi

s2 -

Rep

ort N

o. 6

R

-41-

13

Ado

ptio

n D

ecem

ber

12, 2

013

Ope

ratio

nal P

lann

ing

Ana

lysi

s2 -

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n O

ctob

er 1

, 201

5

Ope

ratio

nal P

lann

ing

Ana

lysi

s -

Rep

ort N

o. 9

R

-32-

16

Ado

ptio

n O

ctob

er 1

, 201

6

Ope

ratio

ns S

uppo

rt P

erso

nnel

-

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n A

lign

with

effe

ctiv

e da

te o

f Req

uire

men

t 5 o

f the

P

ER

-005

-2 s

tand

ard

whe

re th

is te

rm is

ref

eren

ced

Phy

sica

l Acc

ess

Con

trol

Sys

tem

s P

AC

S

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Phy

sica

l Sec

urity

Per

imet

er

PS

P

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Pla

nnin

g A

sses

smen

t -

TP

L-00

1-4

Rep

ort

A

dopt

ion

Pla

nnin

g A

utho

rity

PA

R

epor

t No.

10

A

dopt

ion

Poi

nt o

f Rec

eipt

P

OR

R

epor

t No.

10

A

dopt

ion

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Pre

-Rep

ortin

g C

ontin

genc

y E

vent

AC

E

Val

ue1

- R

epor

t No.

10

A

dopt

ion

Pro

tect

ed C

yber

Ass

ets2

PC

A

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Pro

tect

ed C

yber

Ass

ets

PC

A

Rep

ort N

o. 1

0

Ado

ptio

n

Pro

tect

ion

Sys

tem

-

R

epor

t No.

6

R-4

1-13

A

dopt

ion

Janu

ary

1, 2

015

for

each

ent

ity to

mod

ify it

s pr

otec

tion

syst

em m

aint

enan

ce a

nd te

stin

g pr

ogra

m to

ref

lect

the

new

def

initi

on (

to c

oinc

ide

with

rec

omm

ende

d ef

fect

ive

date

of P

RC

-005

-1b)

and

unt

il th

e en

d of

the

first

co

mpl

ete

mai

nten

ance

and

test

ing

cycl

e to

impl

emen

t any

ad

ditio

nal m

aint

enan

ce a

nd te

stin

g fo

r ba

ttery

cha

rger

s as

re

quire

d by

that

ent

ity’s

pro

gram

.

Pro

tect

ion

Sys

tem

Mai

nten

ance

P

rogr

am

PS

MP

R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of R

equi

rem

ent 1

of t

he

PR

C-0

05-2

sta

ndar

d w

here

this

term

is r

efer

ence

d

Pro

tect

ion

Sys

tem

Mai

nten

ance

P

rogr

am (

PR

C-0

05-4

)5 P

SM

P

Rep

ort N

o. 9

- N

ot r

ecom

men

ded

for

adop

tion

in B

.C a

t thi

s tim

e.

Pro

tect

ion

Sys

tem

Mai

nten

ance

P

rogr

am (

PR

C-0

05-6

) P

SM

P

Rep

ort N

o. 1

0

Ado

ptio

n

Pse

udo-

Tie

-

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n O

ctob

er 1

, 201

5

Rea

ctiv

e P

ower

-

Rep

ort N

o. 1

0

Ado

ptio

n

Rea

l Pow

er

- R

epor

t No.

10

A

dopt

ion

Rea

l-tim

e A

sses

smen

t2 -

Rep

ort N

o. 6

R

-41-

13

Ado

ptio

n Ja

nuar

y 1

, 201

4

Rea

l-tim

e A

sses

smen

t -

Rep

ort N

o. 9

R

-32-

16

Ado

ptio

n O

ctob

er 1

, 201

6

5

Inte

nded

for

relia

bilit

y st

anda

rd P

RC

-005

-4 w

hich

was

def

erre

d by

FE

RC

and

is n

ot in

clud

ed in

Ass

essm

ent R

epor

t No.

9.

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Rel

iabi

lity

Adj

ustm

ent A

rran

ged

Inte

rcha

nge

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Oct

ober

1, 2

015

Rel

iabi

lity

Coo

rdin

ator

R

C

Rep

ort N

o. 1

0

Ado

ptio

n

Rel

iabi

lity

Dire

ctiv

e -

Rep

ort N

o. 9

R

-32-

16

Ret

irem

ent

Juky

18,

201

6

Rel

iabi

lity

Sta

ndar

d2 -

Rep

ort N

o. 8

R

-32-

14

Ado

ptio

n O

ctob

er 1

, 201

5

Rel

iabi

lity

Sta

ndar

d -

Rep

ort N

o. 1

0

Ado

ptio

n

Rel

iabl

e O

pera

tion2

- R

epor

t No.

8

R-3

2-14

A

dopt

ion

Oct

ober

1, 2

015

Rel

iabl

e O

pera

tion

- R

epor

t No.

10

A

dopt

ion

Rel

ief R

equi

rem

ent (

WE

CC

Reg

iona

l T

erm

) -

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n A

lign

with

effe

ctiv

e da

te o

f IR

O-0

06-W

EC

C-2

sta

ndar

d w

here

this

term

is r

efer

ence

d

Rem

edia

l Act

ion

Sch

eme

R

AS

R

epor

t No.

1

G-6

7-09

A

dopt

ion

June

4, 2

009

Rem

edia

l Act

ion

Sch

eme

RA

S

Rep

ort N

o. 9

- T

o be

det

erm

ined

3

Rem

ovab

le M

edia

-

Rep

ort N

o. 1

0

Ado

ptio

n

Rep

orta

ble

Bal

anci

ng C

ontin

genc

y E

vent

1 -

Rep

ort N

o. 1

0

Ado

ptio

n

Rep

orta

ble

Cyb

er S

ecur

ity In

cide

nt

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

whe

re th

is te

rm is

ref

eren

ced.

Req

uest

for

Inte

rcha

nge

RF

I R

epor

t No.

8

R-3

8-15

A

dopt

ion

Oct

ober

1, 2

015

Res

erve

Sha

ring

Gro

up

- R

epor

t No.

10

A

dopt

ion

Res

erve

Sha

ring

Gro

up R

epor

ting

AC

E1

- R

epor

t No.

10

A

dopt

ion

Res

ourc

e P

lann

er

RP

R

epor

t No.

10

A

dopt

ion

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Sin

k B

alan

cing

Aut

horit

y -

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n O

ctob

er 1

, 201

5

Sou

rce

Bal

anci

ng A

utho

rity

- R

epor

t No.

8

R-3

8-15

A

dopt

ion

Oct

ober

1, 2

015

Spe

cial

Pro

tect

ion

Sys

tem

(R

emed

ial

Act

ion

Sch

eme)

S

PS

R

epor

t No.

1

G-6

7-09

A

dopt

ion

June

4, 2

009

Spe

cial

Pro

tect

ion

Sys

tem

(R

emed

ial

Act

ion

Sch

eme)

S

PS

R

epor

t No.

10

A

dopt

ion

Sys

tem

Ope

ratin

g Li

mit

- R

epor

t No.

10

A

dopt

ion

Sys

tem

Ope

rato

r -

Rep

ort N

o. 8

R

-38-

15

Ado

ptio

n

Alig

n w

ith e

ffect

ive

date

of C

IP V

ersi

on 5

sta

ndar

ds

(CIP

-002

-5.1

, CIP

-003

-5, C

IP-0

04-5

, CIP

-005

-5,

CIP

-006

-5, C

IP-0

07-5

, CIP

-008

-5, C

IP-0

09-5

, CIP

-010

-1,

and

CIP

-011

-1)

as r

efer

ence

is m

ade

to th

e te

rm C

ontr

ol

Cen

ter

as p

art o

f the

def

initi

on o

f Sys

tem

Ope

rato

r. T

he

term

Con

trol

Cen

ter

is in

turn

ref

eren

ced

from

the

CIP

V

ersi

on 5

sta

ndar

ds.

Tot

al In

tern

al D

eman

d -

Rep

ort N

o. 9

R

-32-

16

Ado

ptio

n O

ctob

er 1

, 201

6

Tra

nsie

nt C

yber

Ass

et

- R

epor

t No.

10

A

dopt

ion

Tra

nsm

issi

on C

usto

mer

-

Rep

ort N

o. 1

0

Ado

ptio

n

Tra

nsm

issi

on O

pera

tor

TO

P

Rep

ort N

o. 1

0

Ado

ptio

n

Tra

nsm

issi

on O

wne

r T

O

Rep

ort N

o. 1

0

Ado

ptio

n

Tra

nsm

issi

on P

lann

er

TP

R

epor

t No.

10

A

dopt

ion

Tra

nsm

issi

on S

ervi

ce P

rovi

der

TS

P

Rep

ort N

o. 1

0

Ado

ptio

n

Und

er V

olta

ge L

oad

She

ddin

g P

rogr

am

- R

epor

t No.

9

-

To

be d

eter

min

ed3

Rig

ht-o

f-W

ay

RO

W

Rep

ort N

o. 7

R

-32-

14

Ado

ptio

n A

ugus

t 1, 2

015

TLR

(T

rans

mis

sion

Loa

ding

Rel

ief)

Log

-

Rep

ort N

o. 7

R

-32-

14

Ado

ptio

n A

ugus

t 1, 2

014

NE

RC

Glo

ssar

y T

erm

A

cro

nym

A

sses

smen

t R

epo

rt N

um

ber

C

om

mis

sio

n

Ord

er

Nu

mb

er

Co

mm

issi

on

A

do

pti

on

or

Ret

irem

ent

Eff

ecti

ve D

ate

Veg

etat

ion

Insp

ectio

n -

Rep

ort N

o. 7

R

-32-

14

Ado

ptio

n A

ugus

t 1, 2

015

Ta

ble

2

NE

RC

Glo

ssa

ry A

do

pti

on

His

tory

in

B.C

.

NE

RC

Glo

ssar

y o

f T

erm

s V

ersi

on

Dat

e

Ass

essm

ent

Rep

ort

N

um

ber

Co

mm

issi

on

Ord

er

Ad

op

tio

n D

ate

Co

mm

issi

on

O

rder

A

do

pti

ng

Eff

ecti

ve D

ate

Feb

ruar

y 12

, 200

8 R

epor

t No.

1

June

4, 2

009

G‐6

7‐09

T

he N

ER

C G

loss

ary

is e

ffect

ive

as

of th

e da

te o

f the

Ord

er (

June

4, 2

009)

Apr

il 20

, 201

0 R

epor

t No.

2

Nov

embe

r 10

, 201

0 G

-167

-10

The

NE

RC

Glo

ssar

y is

effe

ctiv

e a

s of

the

date

of t

he O

rder

(N

ovem

ber

10, 2

010)

Aug

ust 4

, 201

1 R

epor

t No.

3

Sep

tem

ber

1, 2

011

G-1

62-1

1 R

epla

cing

G‐1

51‐1

1 T

he N

ER

C G

loss

ary

is e

ffect

ive

as o

f the

dat

e of

the

Ord

er (

Sep

tem

ber

1, 2

011)

Dec

embe

r 13

, 201

1 R

epor

t No.

5

Janu

ary

15, 2

013

R-1

-13

The

NE

RC

Glo

ssar

y is

effe

ctiv

e as

of t

he d

ate

of th

e O

rder

(Ja

nuar

y 15

, 201

3)

NE

RC

Glo

ssar

y te

rms

whi

ch h

ave

not b

een

appr

oved

by

FE

RC

are

of n

o fo

rce

or

effe

ct

Dec

embe

r 5,

201

2 R

epor

t No.

6

Dec

embe

r 12

, 201

3 R

-41-

13

The

NE

RC

Glo

ssar

y is

effe

ctiv

e as

of t

he d

ate

of th

e O

rder

(D

ecem

ber

12, 2

013)

The

effe

ctiv

e da

te o

f the

new

and

rev

ised

NE

RC

Glo

ssar

y te

rms

adop

ted

in th

e O

rder

is

the

date

app

earin

g in

the

tabl

e fo

und

in A

ttach

men

t A to

the

Ord

er

NE

RC

Glo

ssar

y te

rms

whi

ch h

ave

not b

een

appr

oved

by

FE

RC

are

of n

o fo

rce

or

effe

ct

NE

RC

Glo

ssar

y o

f T

erm

s V

ersi

on

Dat

e

Ass

essm

ent

Rep

ort

N

um

ber

Co

mm

issi

on

Ord

er

Ad

op

tio

n D

ate

Co

mm

issi

on

O

rder

A

do

pti

ng

Eff

ecti

ve D

ate

Janu

ary

2, 2

014

Rep

ort N

o. 7

Ju

ly 1

7, 2

014

R-3

2-14

The

NE

RC

Glo

ssar

y is

effe

ctiv

e as

of t

he d

ate

of th

e O

rder

(Ju

ly 1

7, 2

014)

The

effe

ctiv

e da

te o

f the

new

and

rev

ised

NE

RC

Glo

ssar

y te

rms

adop

ted

in th

e O

rder

is

the

date

app

earin

g in

the

tabl

e fo

und

in A

ttach

men

t A to

the

Ord

er. E

ach

Glo

ssar

y te

rm to

be

supe

rsed

ed b

y a

revi

sed

Glo

ssar

y te

rm a

dopt

ed in

the

Ord

er s

hall

rem

ain

in e

ffect

unt

il th

e ef

fect

ive

date

of t

he G

loss

ary

term

sup

erse

ding

it.

The

NE

RC

Glo

ssar

y te

rms

liste

d in

the

tabl

es fo

und

in A

ttach

men

t C to

the

Ord

er a

re

all o

f the

NE

RC

Glo

ssar

y te

rms

in e

ffect

in B

.C. a

s of

the

effe

ctiv

e da

tes

liste

d in

the

tabl

es o

f Atta

chm

ent C

to th

e O

rder

. T

he e

ffect

ive

date

s fo

r th

e N

ER

C G

loss

ary

term

s th

at a

re li

sted

in th

e ta

bles

foun

d in

Atta

chm

ent C

sup

erse

de th

e ef

fect

ive

date

s th

at w

ere

incl

uded

in a

ny s

imila

r lis

t app

ende

d to

any

pre

viou

s or

der.

NE

RC

Glo

ssar

y te

rms

whi

ch h

ave

not b

een

appr

oved

by

FE

RC

are

of n

o fo

rce

or

effe

ct.

The

Ele

ctric

Rel

iabi

lity

Cou

ncil

of T

exas

, Nor

thea

st P

ower

Coo

rdin

atin

g C

ounc

il an

d R

elia

bilit

y F

irst r

egio

nal d

efin

ition

s lis

ted

at th

e en

d of

the

NE

RC

Glo

ssar

y of

Ter

ms

are

of n

o fo

rce

or e

ffect

in B

.C.

Oct

ober

1, 2

014

Rep

ort N

o. 8

Ju

ly 2

4, 2

015

R-3

8-15

T

he N

ER

C G

loss

ary

is e

ffect

ive

as o

f the

dat

e of

Com

mis

sion

Ord

er R

-38-

15.

Dec

embe

r 7,

201

5 B

AL-

001-

2 A

pril

21, 2

016

R-1

4-16

The

BA

L-00

1-2

Glo

ssar

y T

erm

s (I

nter

conn

ectio

n, R

egul

atio

n R

eser

ve S

harin

g G

roup

, R

epor

ting

Ace

and

Res

erve

Sha

ring

Gro

up R

epor

ting

Ace

) ar

e ef

fect

ive

as o

f Ju

ly 1

, 201

6.1

Dec

embe

r 7,

201

5 R

epor

t No.

9

July

18,

201

6 R

-32-

16

The

NE

RC

Glo

ssar

y is

effe

ctiv

e as

of J

uly

18, 2

016.

The

effe

ctiv

e da

te o

f the

new

and

rev

ised

NE

RC

Glo

ssar

y te

rms

adop

ted

in th

e O

rder

is

the

date

app

earin

g in

the

tabl

e fo

und

in A

ttach

men

t A to

the

Ord

er.

Nov

embe

r 2

8, 2

016

Rep

ort N

o. 1

0

1

With

the

adop

tion

of th

e N

ER

C G

loss

ary

as p

art o

f MR

S A

sses

smen

t Rep

ort N

o. 9

, the

BA

L-00

1-2

Glo

ssar

y T

erm

s ar

e no

long

er e

xcep

tions

to th

e N

ER

C G

loss

ary

and

so a

re

not i

nclu

ded

in T

able

1.

Documents

Utilities Commission Act...10 (ii) However, when NCLL is utilized under footnote 12 within the Near-Term 11 Transmission Planning Horizon to address BES performance requirements, 12