Philip Augustin, P.E. Portland General Electric Slide 2 1)
MOD-025-2 Verification and Data Reporting of Generator Real and
Reactive Power Capability and Synchronous Condenser Reactive Power
Capability (GO, TO*) 2) MOD-026-1 Verification of Models and Data
for Generator Excitation Control System or Plant Volt/Var Control
Functions (GO, TP) (R1, R3-R6) 3) MOD-027-1 Verification of Models
and Data for Turbine/Governor and Load Control or Active
Power/Frequency Control Functions (GO, TP) (R1, R3-R5) 1 Slide 3
MOD-032-1 Establishes consistent modeling data requirements and
reporting procedures for development of planning horizon cases
necessary to support analysis of the reliability of the
interconnected transmission system. MOD-033-1 Establishes
consistent validation requirements to facilitate the collection of
accurate data and building of planning models to analyze the
reliability of the interconnected transmission system. 2 Slide 4 1)
PRC-019-1 Coordination of Generating Unit or Plant Capabilities,
Voltage Regulating Controls, and Protection (GO, TO*) 2) PRC-024-1
Generator Frequency and Voltage Protective Relay Settings (GO) 3
Slide 5 Reliability StandardTitleEffective Date MOD-025-2
Verification & Data Reporting of Generator Real & Reactive
Power Capability & Synchronous Condenser Reactive Power
Capability 7/1/2016 40% Verified 7/1/2017 60% Verified 7/1/2018 80%
Verified 7/2/2019 100% Verified MOD-026-1 Verification of Models
& Data for Generator Excitation Control System or Plan Volt/VAR
Control Functions 7/1/2014 R1, R3 thru R6 7/1/2018 R2, 30% Verified
7/1/2020 R2, 50% Verified 7/1/2024 R2, 100% Verified MOD-027-1
Verification of Models & Data for Turbine / Governor & Load
Control or Active Power / Frequency Control Functions 7/1/2014 R1,
R3 thru R5 7/1/2018 R2, 30% Verified 7/1/2020 R2, 50% Verified
7/1/2024 R2, 100% Verified PRC-019-1 Coordination of Generating
Unit or Plant Capabilities, Voltage Regulating Controls &
Protection 7/1/2016 40% Verified 7/1/2017 R1, 60% Verified 7/1/2018
R1, 80% Verified 7/1/2019 R1, 100% Verified PRC-024-1 Generator
Frequency & Voltage Protective Relay Settings 7/1/2016 R1, R2,
R3 & R4, 40% Verified 7/1/2017 R1, R2, R3, & R4, 60%
Verified 7/1/2018 R1, R2, R3, & R4, 80% Verified 7/1/2019 R1,
R2, R3, & R4, 100% Verified 4 Slide 6 To Prevent a physical
attack from resulting in widespread instability, uncontrolled
separation, or Cascading within an Interconnection. Applicable to
TO with substation(s)/switching station(s) operated at 200 kV or
higher and has an aggregate weighted value of 3000 or more The
collector system of a generation plant is not applicable Voltage
Value of a Line Weight Value Per Line Less than 200 kV (not
applicable) (not applicable) 200 kV 299 kV700 300 kV- 499 kV1300
500 kV and above0 5 Slide 7 R1. Risk Assessment TO shall perform an
initial risk assessment of Transmission stations/ substations
(existing and planned to be in service within 24 months). Identify
the Transmission station/ substation(s) that if rendered inoperable
or damaged could result in widespread instability, uncontrolled
separation, or Cascading. Subsequent risk assessments shall be
performed: At least once every 30 months (2 1/2 years) for a TO
that identified one or more Transmission station/ substation(s) in
their initial risk assessment At least once every 60 months (5
years) for a TO that has not identified any Transmission stations/
substations in their initial risk assessment. The TO shall identify
the primary operational control center for each Transmission
station/ substation(s) identified in the R1 risk assessment. 6
Slide 8 R2. Third party verification. Each TO shall have an
unaffiliated third party verify the risk assessment performed under
Requirement R1. The unaffiliated third party verification may
include recommendations for the addition or deletion of a
Transmission station/ substation(s). The TO shall ensure the
verification is completed within 90 calendar days R3. TO-TOP
Notification for Primary control center(s) Primary control
center(s) that operationally control(s) an identified Transmission
station/ substation not under the operational control of the TO:
The TO, within seven calendar days following completion of
Requirement R2 notify the TOP that of the identification and the
date of completion of Requirement R2. R4. Evaluation of the
potential threats and vulnerabilities Each TO & TOP shall
evaluate threats and vulnerabilities to a physical attack for each
of their identified Transmission station(s), substation(s), and
primary control center(s) The evaluation shall consider the
following: Unique characteristics of the identified and verified
Transmission station(s), Transmission substation(s), and primary
control center(s); Prior history of attack on similar facilities
taking into account the frequency, geographic proximity, and
severity of past physical security related events; and Intelligence
or threat warnings received from sources such as law enforcement,
the Electric Reliability Organization (ERO), the Electricity Sector
Information Sharing and Analysis Center (ES-ISAC), U.S. federal
and/or Canadian governmental agencies, or their successors. 7 Slide
9 R5. Physical Security Plan(s) and Implementation Schedule Within
120 days of completion of requirement R2. Each TO &TOP shall
develop and implement a documented physical security plan(s) and
implementation schedule for their respective Transmission station/
substation(s) and primary control centers. The physical security
plan(s) shall include the following attributes: Resiliency or
security measures designed collectively to deter, detect, delay,
assess, communicate, and respond to potential physical threats and
vulnerabilities identified during the evaluation conducted in
Requirement R4. Law enforcement contact and coordination
information. A timeline for executing the physical security
enhancements and modifications specified in the physical security
plan. Provisions to evaluate evolving physical threats, and their
corresponding security measures, to the Transmission station(s),
Transmission substation(s), or primary control center(s). 8 Slide
10 R6. Third party review of the security plan(s) and
implementation schedule TO & TOP shall select an unaffiliated
third party reviewer with one or more of the following
qualifications: An entity or organization with electric industry
physical security experience, and whose review staff has at least
one member who holds either a Certified Protection Professional
(CPP) or Physical Security Professional (PSP) certification. An
entity or organization approved by the ERO. A governmental agency
with physical security expertise. An entity or organization with
demonstrated law enforcement, government, or military physical
security expertise. The TO&TOP shall ensure the verification is
completed within 90 calendar days If the third party reviewer
recommends changes to the evaluation performed threats and
vulnerabilities to a physical attack or security plan(s) developed
under Requirement R5, the Transmission Owner or Transmission
Operator shall, within 60 calendar days of the completion of the
unaffiliated third party review, for each recommendation: Modify
its evaluation or security plan(s) consistent with the
recommendation; or Document the reason(s) for not modifying the
evaluation or security plan(s) consistent with the recommendation.
9 Slide 11 Anticipated ActionsAnticipated Dates 5-day Final Ballot
ClosedMay 1, 2014 Anticipated BOT AdoptionMay 15, 2014 Expecting to
file with applicable Regulatory Authorities June 5, 2014 Becomes
effective the first day of the first calendar quarter 6 months
after standard is approved 10 Slide 12 During a GMD event,
geomagnetically-induced currents (GIC) may cause transformer
hot-spot heating or damage, loss of Reactive Power sources,
increased Reactive Power demand, and Misoperation, the combination
of which may result in voltage collapse and blackout. 11 Slide 13
R1. Each PC and TP shall maintain ac System models and
geomagnetically-induced current (GIC) System models within its
respective area for performing the studies needed to complete its
GMD Vulnerability Assessment. Establishes Category P8 as the normal
System condition for GMD planning in Table 1. The System models
shall include: 1.1. Existing Facilities 1.2. Known outage(s) of
generation or Transmission Facility(ies) with a duration of at
least six months. 1.3. New planned Facilities and changes to
existing Facilities 1.4. Real and reactive Load forecasts 1.5.
Known commitments for Firm Transmission Service and Interchange
1.6. Resources (supply or demand side) required for Load 12 Slide
14 13 Slide 15 R2. Each PC and TP shall complete a GMD
Vulnerability Assessment of the Near Term Transmission Planning
Horizon for its respective area once every 60 months. This GMD
Vulnerability Assessment shall use studies, document assumptions,
and document summarized results of the steady state analysis. 2.1.
Studies shall include the following conditions: 2.1.1. System peak
Load for one year within the Near-term Transmission Planning
Horizon. 2.1.2. System Off-Peak Load for one year within the
Near-term Transmission Planning Horizon. 2.2. Studies shall be
conducted based on the benchmark GMD event described in Attachment
1 to determine 14 Slide 16 Attachment 1: Calculating Geoelectric
Fields for the Benchmark GMD Event (1) A reference peak geoelectric
field amplitude of 8 V/km derived from statistical analysis of
historical magnetometer data; (2) Scaling factors to account for
local geomagnetic latitude; (3) Scaling factors to account for
local earth conductivity; and (4) A reference geomagnetic field
time series or waveshape to facilitate time-domain analysis of GMD
impact on equipment. 15 Slide 17 16 Substation Location and
Grounding resistance Transmission Line Information
Transformer/autotransformer winding resistance Slide 18 R3. If the
determination through the GMD Vulnerability Assessment that its
System does not meet the performance requirements of Table 1 Each
PC and TP shall develop a Corrective Action Plan addressing how the
performance requirements will be met. R4. Each PC and TP shall have
criteria for acceptable System steady state voltage limits for its
System during the GMD conditions described in Attachment 1. 17
Slide 19 R5. Each PC, in conjunction with its TPs shall determine
and identify the individual and joint responsibilities of entities
in the PCs area for performing the required studies for the GMD
Vulnerability Assessment. R6. Each PC and TP shall distribute its
GMD Vulnerability Assessment results and Corrective Action Plan, if
any, to adjacent PC, adjacent TP, and TO and GO in its respective
planning area within 90 calendar days of completion, 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. 18 Slide 20 R7. Each TO and GO shall conduct an assessment
of thermal impact for all of its solely and jointly owned power
transformers with high- side, wye-grounded windings connected at
200 kV or higher. The assessment shall: 7.1. Be based on the
benchmark GMD event described in Attachment 1 with peak
geomagnetically-induced current (GIC) flows 7.2. Document
assumptions used in the analysis 7.3. Describe suggested actions
and supporting R8. Provide its assessment of thermal impact from R7
within 90 days of completion to the PC and TP with responsibility
for the area in which the associated power transformer is located.
19 Slide 21 Informal Comment Period Closes 5/21/2014 Anticipated
ActionsAnticipated Date 45-day Formal Comment Period with Initial
Ballot June 2014 45-day Formal Comment Period with Additional
BallotAugust 2014 Final ballotOctober 2014 BOT adoptionNovember
2014 20 Slide 22 Week of May 5: 2007-11 Disturbance Monitoring:
PRC-002-2 (45-day comment period and additional ballot) Week of May
12: 2010-05.1 Protection System (Misoperations): PRC-004-3 (45-day
comment period and additional ballot) Week of May 19: 2010-14.2
Periodic Review of BAL-004: Recommendation (45-day comment period,
no ballot) 2014-03 Revisions to TOP/IRO Reliability Standards
(45-day comment period and initial ballot) Week of May 26: 2007-06
System Protection Coordination: PRC-027-1 (45-day comment period
and additional ballot) 2010-14.1 BARC: BAL-002-2 (45-day comment
period and additional ballot) 21
