Discussion Items – February 11, 2013
Antitrust Admonition
Announcements/FERC/NERC Developments
Texas RE Report (Don Jones)
Recent FERC Actions (Don Jones)
Standards Committee – Special Election Update (All)
Recent Ballot Results
Standard Process Manual
Revisions to Implement SPIG
Interpretation of TPL-003 and TPL2012-INT004 for System Protection and
Control Subcommittee
TPL Table 1 Order
TPL-002-2b, footnote ‘b’ and TPL001-3, footnote 12
* Proceeded to Recirculation Ballot
End Date
Standards Under Development - Ballots/Comments
1. Ballots/Comment Periods
Primary Frequency Response in the ERCOT
Protection Systems: Phase 1
Non-Binding Poll
Successive Ballot
Non-Binding Poll
End Date
Successive Ballot
Generator Verification
Non-Binding Poll
Phase 2 of Relay Loadability: Generation
Initial Ballot
Non-Binding Poll
PRC-025-1 Comment
PRC-025-1 RSAW Comment
Interpretation for ITC
Interpretation for Consumers Energy
Cost Effectiveness Analysis
Supplemental SAR Comment
Initial Ballot
Initial Ballot
A. Primary Frequency Response in the ERCOT Region BAL-001-TRE-1 – Second Ballot, NonBinding Poll & Comment Period – February 15, 2013
Background: The ERCOT Interconnection was initially given a waiver of BAL-001 R2 (Control
Performance Standard CPS2). In FERC Order 693, NERC was directed to develop a Regional Standard
as an alternate means of assuring frequency performance in the ERCOT Interconnection. NERC was
explicitly directed to incorporate key elements of the existing Protocols, Section 5.9. This required
governors to be in service and performing with an un-muted response to assure an Interconnection
minimum Frequency Response to a Frequency Measurable Event (that starts at t(0)).
This regional standard provides requirements related to identifying Frequency Measureable Events
(FME), calculating the Primary Frequency Response of each resource in the Region, calculating the
Interconnection minimum Frequency Response and monitoring the actual Frequency Response of the
Interconnection, setting Governor deadband and droop parameters, and providing Primary Frequency
Response performance requirements.
The drafting team has revised the draft based on comments received with the first ballot and Field Trial
results. In particular the sustained performance measure was changed to examine a point in time about
one minute following the FME, rather than a period covering several minutes after the FME.
Industry volunteer discussion
B. Project 2010-05.1 – Protection Systems: Phase 1 (Misoperations) PRC-004-3 – Successive
Ballot, Non-Binding Poll & Formal Comment Period – February 20, 2013
Background: PRC-004-3, Protection System Misoperations is a revision of PRC-004-2a, Analysis and
Mitigation of Transmission and Generation Protection System Misoperations. This revision combines the
reliability intent of the two legacy standards PRC-003-1 and PRC-004-2a. PRC-003-1 required the
Regions to establish procedures for analysis of Misoperations but is not currently enforceable, creating a
potential reliability gap.
During the initial ballot, PRC-004-3 received 38% approval. Changes to the standard in this third draft
Revisions to the definition of Protection System Misoperation.
Revisions to the Applicability ‘Facilities’ section
 Applies to Protection Systems for BES Elements
 Applies to UFLS that trips a BES Element
Excludes SPS, RAS and UVLS
Excludes non-protective functions that may be imbedded within a Protection System
Revisions to the Requirements and Measures.
Modifications to the VSLs to reflect the changes in the requirements.
Revisions to the Implementation Plan including extending the Effective Date from six months to
twelve months following applicable regulatory approvals.
Removal of the Misoperations reporting aspects from the standard
 SDT is developing a Data Request under ROP 1600
Modifications to the Guidelines and Technical Basis section to include more explanation and
Industry volunteer discussion (Oncor, Texas RE, others)
C. Project 2007-09 Generator Verification PRC-024-1 – Successive Ballot, Non-Binding Poll &
Formal Comment Period – February 25, 2013
Background: PRC-024-1 addresses Generator Frequency and Voltage Protective Relay Settings. The
other standards in this project (MOD-025-2, MOD-026-1, MOD-027-1 and PRC-019-1) received NERC
BOT approval on February 7, 2013.
Draft 5 of PRC-024-1 received 60% approval in a successive ballot that closed on January 11, 2013. The
SDT received valuable feedback from stakeholders regarding improvements to the standard. Many of the
suggested edits were incorporated into the revised standard. Based on industry comments, the following
improvements were made in Draft 6:
Removed R4 from the standards because of ambiguous language and dubious reliability benefit.
Revised the title of the standard to “Generator Frequency and Voltage Protective Relay Settings”
and the Purpose Statement to “Ensure Generator Owners set their generator protective relays
such that generating units remain connected during defined frequency and voltage excursions.
Revised “generating unit(s)” to “applicable generating unit(s)” to reflect that the standard only
applies to units that meet the registry criteria.
Revised language of R1 to match that of R2.
Added “regulatory or” language regarding limitations to reflect that NERC, environmental or
regulatory requirements may cause a limitation in generator performance.
Revised R2 so that the sentences were shorter and easier to read.
Removed the last bullet from R3 and added and new bullet referencing frequency impacts on
turbines as follows: “Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.”
Revised R5 (now R4) to indicate that the trip settings to be provided are only those “associated
with Requirements R1 and R2” and not all relays.
Revised the measures based on requirement revisions.
Updated the VSLs for R3 and R4 to allow 30 day increments between levels rather than the
original 10 days. This comports with other standards developed under this project.
Updated the table in Attachment 2 (this was missed in the previous revision).
Made clarifying revisions to “Voltage Ride-Through Curve Clarifications” on the last page of the
Clarified Footnote 3 to: “Excludes limitations that are caused by the setting capability of the
generator frequency and voltage protective relays themselves but does not exclude limitations
originating in the equipment that they protect.”
Industry volunteer discussion (Brazos, CenterPoint, others)
D. Project 2010-13.2 Phase 2 of Relay Loadability: Generation – Initial Ballot, Non-Binding Poll &
Formal Comment Period – March 11, 2013
Ballot Pools Forming: January 25 – February 25, 2013
Alongside the comment period, three additional documents will be posted for industry comment: a draft
cost effective analysis (CEA), a supplemental SAR, and a draft Reliability Standard Audit Worksheet
Background: FERC Order No. 733 approved PRC-023-1 and directed NERC to address three areas of
relay loadability that include (i) modifications to the approved PRC-023-1, (ii) developing a new Reliability
Standard to address generator protective relay loadability, and (iii) developing another Reliability
Standard to address the operation of protective relays due to power swings.
The current phase of this project, Phase II, is focused on developing a new Reliability Standard,
PRC-025-1 – Generator Relay Loadability, to address generator protective relay loadability. This
Reliability Standard establishes requirements for the Generator Operator Owner functional entity to set
protective relays at a level such that generating units do not trip during system disturbances that are not
damaging to the generator thereby unnecessarily removing the generator from service. Phase III will
follow this project.
Industry volunteer discussion (Luminant, others)
E. “Pilot” of the NERC CEAP regarding Project 2010-13.2 Phase 2 of Relay Loadability:
Generation – March 11, 2013
Background: The NERC Cost Effective Analysis Process (CEAP) introduces cost consideration to the
standards development process in two phases.
The first phase, Cost Impact Assessment (CIA), will be implemented during the SAR stage to
determine cost impact and identify “order of magnitude” or potentially egregious costs, to
determine if a proposed standard will meet or exceed an adequate level of reliability, and what
potential risks are being mitigated.
Project 2010-13.2 has already been deemed to be required to meet an adequate level of
reliability, therefore Phase One is unnecessary.
The second phase, Cost Effectiveness Analysis (CEA), will be done later in the standard
development process and afford the industry the opportunity to offer more cost efficient solutions
that may be equally effective to achieving the reliability intent of the draft standard. Upon
completion of both phases of the CEAP a report will be prepared by the Standards Committee
Process Subcommittee Subgroup and then posted at the time the standard is balloted to allow a
more informed choice during balloting.
Phase Two involves two sets of survey questions, asked concurrently. For this pilot,
NERC will only be soliciting a subset of the total CEA questions envisioned.
The first set relates to technical feasibility and effectiveness of the proposed
requirements as well as soliciting possible more cost effective alternatives to
achieve the reliability objectives.
The second set of questions will solicit cost impacts (e.g., implementation,
maintenance, and ongoing compliance resource requirements) and any related
implementation information.
Instructions: For each question that you provide a comment, please provide specific suggestions that
would eliminate or minimize any concerns you have with the item in question. A comment or response to
every question is not required. Respondents should identify their responses they believe to be CEII,
market sensitive, or otherwise confidential.
Describe the size of your organization in broad general terms, e.g. GO‐Total installed MWs, TOs
circuit miles by kV and total load served, etc.
Please answer the following regarding the estimated costs and benefits of each of the proposed
CI-2a. What are the initial one time, ongoing, implementation, and maintenance costs of
complying with the requirements?
CI-2b. What is the on‐going long term cost impact (after implementation) of complying with the
requirements in terms of equivalent full time employees (EFTE)?
CI-2c. What are the resource benefits (labor, materials, administrative) of implementing these
CI-2d. What are the reliability benefits of implementing these requirements?
Are there alternative method(s) or existing reliability standard requirement(s) not identified in the
draft standard which may achieve the reliability objective of the standard that may result in less
cost impact (implementation, maintenance, and ongoing compliance resource requirements)? If
so what? Please provide as much additional supporting evidence as possible.
How long would it take your organization to implement full compliance to the standard as written?
What would affect the implementation (i.e. outage scheduling, availability of materials, human
resources, etc.)?
Would a technical guideline or “best practices” whitepaper or a training program be effective in
achieving a desired outcome to meet the reliability need, as opposed to a “continent‐wide”
standard or variance?
Do you have any other comments? If so, please provide suggested changes and rationale.
F. Project 2012-INT-04 – Interpretation of CIP-007-3 for ITC – Initial Ballot & Formal Comment
Period – March 22, 2013
Ballot Pools Forming: February 6 – March 7, 2013
Background: A project team from the CIP Interpretation Drafting Team has reviewed ITC
Transmission’s (ITC) request for interpretation and developed this interpretation. In its first question,
ITC asked for clarification on whether each sub-requirement of CIP-007-3, Requirement R5 requires
both “technical and procedural controls.” In its second question, ITC asked for clarification on whether
technical controls in CIP-007-3, Requirement R5.3 mean that each individual Cyber Asset within the
Electronic Security Perimeter (ESP) has to automatically enforce each of the three R5.3 sub-parts.
Question 1: Does each sub‐requirement of Requirement R5 require use of both "technical
and procedural controls”?
No, it is not necessary for both technical and procedural controls to be used in each
subrequirement of Requirement R5. The use of “and” in Requirement R5 indicates that the
responsible entity must implement both technical and procedural controls to achieve collectively
the sub‐requirements within Requirement R5 and the associated sub‐requirements. Both are not
necessary for each sub‐requirement individually. …
Note: This interpretation includes one redline from the previous version posted for comment.
Question 2: Does the use of “technical controls” in Requirement R5.3 mean that each
individual Cyber Asset within the Electronic Security Perimeter (ESP) has to automatically
enforce each of the three R5.3 sub‐requirements?
No, the IDT interprets the three sub‐ requirements within R5.3 no differently than the other subrequirements of R5. …
Note: This interpretation includes several redlines from the previous version posted for comment.
The most notable one is the removal of references to Technical Feasibility Exceptions (TFEs).
G. Project 2012-INT-06 – Interpretation of CIP-003-3 for Consumers Energy – Initial Ballot &
Formal Comment Period – March 22, 2013
Ballot Pools Forming: February 6 – March 7, 2013
Background: A project team from the CIP Interpretation Drafting Team has reviewed Consumers
request for interpretation and developed this interpretation. Consumers Energy requested clarification
on CIP-003-3 Requirement R2 as to whether a registered entity can assign different CIP Senior
Managers for different applicable functions.
Question: Consumers Energy Corporation seeks clarification on the meaning of CIP‐003‐3,
Requirement R3 R2 as it relates to designating a CIP Senior Manager. In its response, the
Interpretation Drafting Team will answer whether a Registered Entity may assign different
CIP Senior Managers for different applicable functions for which it is registered.
A Registered Entity cannot assign different CIP Senior Managers for different applicable functions
if those functions are included under one registration (NERC ID).
Note: The sentence above is the only redline from the previous version posted for comment.
Compliance Application Notices
CANS posted for industry comment – Nothing new
CANS can be found here: http://www.nerc.com/page.php?cid=3|22|354
Violations – 1/31/13
Unidentified Registered Entity
Silicon Valley Power
See also, FFTR Spreadsheet and Spreadsheet NOPs
The NERC BOT approved the following standards at its Feb. 7, 2013 meeting (Board package)
o BAL-003-2 - Frequency Response
o Paragraph 81, Phase I
o TPL Table 1, Footnote b
o Generator Verification
 MOD-025-2
 MOD-026-1
 MOD-027-1
 PRC-019-1
o Interpretation of TPL-003-0a and TPL-004-0 for System Protection and Control
o Interpretation of CIP-002-3 for Oklahoma Gas and Electric
NERC Industry Conference – COM-003-1 – Communications in Operations – on Feb. 14 and 15
(Link to calendar details)
NERC Webinars
o Feb 13 - PRC-25-1, Relay Loadability: Generation, 2-4 pm ET (Webinar Registration)
o Feb 19 - Rapid Revision Procedure, 1–2pm ET (Webinar Registration)
o Mar 6 - PER-005-1 Lessons Learned – 1-2 pm ET (Webinar Registration)
Reliability Assurance Initiative Concept White Papers posed for industry comment (Link to
The NERC Board of Trustees approved the 2013-2015 Reliability Standards Development Plan at
their December 19, 2012 meeting and filed it with FERC for informational purposes on December
31, 2012. (Link to filing)
Future Meetings

2013-02-11 Discussion Items