2015 CMEP Implementation Plan

2015 ERO Compliance
Monitoring and Enforcement
Implementation Plan
Revised November 18, 2014
NERC | 2015 ERO CMEP Implementation Plan Version 1.0 | November 18, 2014
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Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ................................................................................................................................................................4
Purpose ...................................................................................................................................................................4
Implementation Plan ..............................................................................................................................................4
RE Implementation Plans ....................................................................................................................................4
Risk-based Approach to Compliance Monitoring and Enforcement ..........................................................................6
Risk-based Compliance Monitoring ........................................................................................................................6
Deployment of Risk-based Compliance Oversight ..............................................................................................6
Risk-based Compliance Oversight Framework....................................................................................................6
Risk-based Enforcement .........................................................................................................................................9
Risk-based Compliance Oversight Plan ................................................................................................................... 10
Risk Elements Results .......................................................................................................................................... 10
2015 Risk Elements .......................................................................................................................................... 10
Regional Risk Assessments .................................................................................................................................. 16
Regional Compliance Oversight Plan ................................................................................................................... 16
NERC Oversight of Regional Implementation Plans ......................................................................................... 17
Revision History ....................................................................................................................................................... 18
Appendix A1 - Florida Reliability Coordinating Council (FRCC) 2015 CMEP Implementation Plan ......................... 19
Appendix A2 - Midwest Reliability Organization (MRO) 2015 CMEP Implementation Plan ................................... 24
Appendix A3 - Northeast Power Coordinating Council (NPCC) 2015 CMEP Implementation Plan......................... 28
Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan ............................. 34
Appendix A5 - SERC Reliability Corporation (SERC) 2015 CMEP Implementation Plan .......................................... 51
Appendix A6 - Southwest Power Pool Regional Entity (SPP RE) 2015 CMEP Implementation Plan ....................... 58
Appendix A7 - Texas Reliability Entity (Texas RE) 2015 CMEP Implementation Plan ............................................. 61
Appendix A8 - Western Electricity Coordinating Council (WECC) 2015 CMEP Implementation Plan ..................... 68
Appendix B - Compliance Assessment Report......................................................................................................... 83
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Preface
The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority
whose mission is to ensure the reliability of the bulk power system (BPS) in North America. NERC develops and
enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the BPS through
system awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the
continental United States, Canada, and the northern portion of Baja California, Mexico. NERC is the electric
reliability organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission
(FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the
BPS, which serves more than 334 million people.
The North American BPS is divided into several assessment areas within the eight Regional Entity (RE) boundaries,
as shown in the map and corresponding table below. The ERO Enterprise is comprised of NERC and the eight REs.
FRCC
MRO
NPCC
RF
SERC
SPP-RE
Texas RE
WECC
Florida Reliability Coordinating
Council
Midwest Reliability Organization
Northeast Power Coordinating
Council
ReliabilityFirst
SERC Reliability Corporation
Southwest Power Pool Regional
Entity
Texas Reliability Entity
Western Electricity Coordinating
Council
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Introduction
Purpose
The ERO Compliance Monitoring and Enforcement Program Implementation Plan (Implementation Plan) is the
annual operating plan carried out by Compliance Enforcement Authorities (CEAs) while performing their
responsibilities and duties as called for in the Compliance Monitoring and Enforcement Program (CMEP). CEAs,
which consist of NERC and the eight REs, carry out CMEP activities in accordance with the NERC Rules of Procedure
(ROP), including Appendix 4C, the respective Regional Delegation Agreements between NERC and each RE, and
other agreements with the Canadian regulatory authorities.
Historically, the Implementation Plan has specified the NERC Reliability Standards and Requirements to be actively
monitored and audited by the REs during the implementation year.1 For the 2015 Implementation Plan and
beyond, NERC will replace the approach used to develop the ERO CMEP Implementation Plan and the Actively
Monitored List (AML) with processes that identify and prioritize continent-wide risks to the reliability of the BPS,
as well as related Reliability Standards and registration functional categories. The new approach will provide input
to a more individualized compliance oversight plan for registered entities. The transformation to focus on
identifying and prioritizing risks replaces a static, one-size-fits-all list of Reliability Standards and prioritizes
functions and Reliability Standards based on risk to determine the appropriate oversight method.
The NERC ROP requires that NERC provide the Implementation Plan to the REs on or about September 1 of the
preceding year.2 REs must submit their Implementation Plans to NERC for review and approval on or about
October 1. Regional Implementation Plans provide:




Details on Regional Risk Assessment processes and results,
Reliability Standards and Requirements associated with Regional Risk Assessment results,
Regional compliance oversight plan, which includes its annual audit plan, and
Other key activities and processes used for CMEP implementation.
Implementation Plan
The ERO Enterprise maintains a consolidated Implementation Plan that provides guidance and implementation
information common among the NERC and the eight REs.
During the implementation year, NERC or a RE may update the Implementation Plan. Updates could include, but
are not limited to: changes to compliance monitoring processes, changes to regional processes, or updates
resulting from a major event, FERC Order, or other matter. When updates occur, NERC will post a revised plan on
the NERC website and issue a compliance communication. REs should submit updates to the NERC Compliance
Operations group, which will review and act on any proposed changes. NERC will be responsible for updating the
ERO CMEP Implementation Plan to reflect any RE changes and will post the updated plan to the website and issue
compliance communications.
RE Implementation Plans
The Regional Implementation Plans supplement the ERO CMEP Implementation Plan and provide information that
is RE-specific. The Regional Implementation Plan describes Regional risk assessments that identify risks that
Regions will consider as part of their compliance oversight plan, which includes the 2015 annual audit plan.
1
2
NERC ROP, Section 401 (Scope of the NERC Compliance Monitoring and Enforcement Program).
NERC ROP, Section 403 (Required Attributes of RE Compliance Monitoring and Enforcement Programs).
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Introduction
Appendices 1.1-1.8 contain the Regional Implementation Plans. NERC will update the Implementation Plan on or
about November 1 to include the Regional Implementation Plans. Regional Implementation Plans are due to NERC
for review on or about October 1.
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Risk-based Approach
Enforcement
to
Compliance
Monitoring
and
Risk-based Compliance Monitoring
Deployment of Risk-based Compliance Oversight
Through a Reliability Assurance Initiative (RAI), NERC has transformed its compliance and enforcement program
into one that is forward-looking, focuses on areas that represent a high risk to BPS reliability, and reduces the
administrative burden on registered entities. The transformed approach to compliance monitoring emphasizes an
examination of reliability risks as the basis for the determination of the appropriate oversight framework,
including scope, frequency, and what monitoring tools are appropriate in each case.
During 2015, CEAs will begin deploying processes and tools used to support risk-based compliance oversight. NERC
and the REs are committed to ensuring full transformation to risk-based compliance oversight, and NERC and the
REs plan continued communications, training, and outreach throughout 2015 to support risk-based compliance
oversight.
Risk-based Compliance Oversight Framework
The ERO Enterprise’s Risk-based Compliance Oversight Framework (Framework) consists of processes that involve
reviewing system-wide risk elements, an assessment of a registered entity’s inherent risk, and, on a voluntary
basis, an evaluation of a registered entity’s internal controls prior to establishing a monitoring plan that is tailored
to a particular entity or group of entities.
Figure 1 below illustrates the ERO Enterprise’s transformation from a static compliance approach to a dynamic
approach. Reliability risk is not the same for all registered entities; therefore, this Framework examines BPS risk
as well as individual registered entity risk to determine the most appropriate CMEP tool to use when monitoring
a registered entity’s compliance with Reliability Standards. This Framework also promotes examination of how
registered entities operate. As illustrated by the blue arrows in Figure 1, the Framework tailors compliance
monitoring focus to those areas that pose the greatest risk to BPS reliability. The elements in Figure 1 are dynamic
and are not independent; rather, they are complementary and interdependent on each another.
Figure 1: Risk-based Compliance Oversight Framework
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Risk-based Approach to Compliance Monitoring and Enforcement
Risk Elements
The first step of the Framework consists of identifying and prioritizing continent-wide risks. These risks are
identified and prioritized based on, among other things, the work done by NERC staff, the Reliability Issues
Steering Committee (RISC), initiatives such as the Standards Independent Experts Review Project, and risks
identified in the ERO Enterprise Strategic Plan. Risks are identified and prioritized based on significance, likelihood,
vulnerability, and potential impact to the reliability of the BPS. They may be categorized as operational and
planning risks, as well as threats to cyber systems or physical security. While risk identification occurs on at least
an annual basis, they are dynamic and continually evolve. Accordingly, periodic reviews and updates may be
necessary and appropriate to address increased or emerging risks as well as reflect mitigated risks. However, the
risks and associated Reliability Standards identified through this process do not constitute the entirety of risks
that may affect the reliability of the BPS. Regional Entities are expected to consider local risks and specific
circumstances associated with individual registered entities within their footprint when developing their
compliance oversight plans.
Inherent Risk Assessment
REs perform an Inherent Risk Assessment (IRA) of registered entities to identify areas of focus and the level of
effort needed to monitor compliance with NERC Reliability Standards for a particular registered entity. The IRA is
a review of potential risks posed by an individual registered entity to the reliability of the BPS. An IRA considers
risk factors such as assets, systems, geography, interconnectivity, prior compliance history, and overall unique
entity composition when determining the compliance oversight plan for a registered entity. The IRA will be
performed on a periodic basis, with the frequency based on a variety of factors, including, but not limited to,
changes to a registered entity and significant changes or emergence of new reliability risks. For monitoring
activities performed in 2015, REs may be in various stages of conducting IRAs for registered entities within their
footprint. During 2015 and beyond, REs will continue to expand the IRA process to registered entities in their
footprints based on risk and compliance monitoring schedules.
Internal Controls Evaluation
To further tailor monitoring plans in accordance with risk for registered entities in their footprints, the Regional
Entities also take into account any information obtained through the processes outlined in the Internal Control
Evaluation (ICE) Guide. For those entities who volunteer to undergo an ICE, REs will select those who will
participate in the ICE process based on the risk posed by particular entities and compliance monitoring schedules.
The Internal Controls Evaluation (ICE) enables a further refinement of the registered entity’s compliance oversight
plan. Registered entities have an opportunity to: (i) provide, on a voluntary basis, information to their respective
RE about their internal controls that address the risks applicable to the entity and for identifying, assessing, and
correcting noncompliance with Reliability Standards; and (ii) demonstrate the effectiveness of such controls. As a
result of the ICE, there may be additional focus of the compliance assurance activities for an entity. Registered
entities may elect not to participate in an ICE. In that case, the CEA will use the results of the IRA to determine the
appropriate compliance oversight strategy, including focus and tools within the determined scope.
CMEP Tools
Ultimately, the RE will determine which of the compliance monitoring tools (i.e., off-site or on-site audits, spot
checks, or Self-Certifications) are warranted. REs will tailor compliance monitoring activities for registered entities
in their footprint based on reliability risks. Reliability Coordinators, Balancing Authorities, and Transmission
Operators are expected to remain on a three-year audit cycle. The determination of the appropriate CMEP tools
will be adjusted, as needed, within a given implementation year.
Self-certifications
In the 2015 ERO CMEP Implementation Plan, the ERO identifies continent-wide reliability risks to the BPS and a
core set of Reliability Standards and Requirements associated with those risks for specific registered functions.
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Risk-based Approach to Compliance Monitoring and Enforcement
In developing a compliance oversight plan for registered entities in its footprint, REs should support compliance
assurance with these identified Standards and Requirements. Through a risk assessment, an RE may determine
that regional risks or risks associated with any particular registered entity drive more, less, or different priorities,
and, therefore, the RE may modify the set of core Reliability Standards or pursue compliance assurance through
any monitoring tools to address those regional and entity-specific considerations. If an annual self-certification
program is not included in a Regional IP, the RE will be expected to address the identified risks through other
means.
Compliance Assessments for Events and Disturbances
An important component of the ERO enterprise’s risk-based approach to compliance monitoring is the voluntary
participation in the Compliance Assessment (CA) Process by registered entities after an event or disturbance.
Through the Events Analysis Process, the ERO enterprise promotes a culture of reliability excellence that
encourages an aggressive and critical self-review and analysis of operations, planning, and critical infrastructure
performance. The CA Process is a complementary review of the event focused on the evaluation of compliance
with Reliability Standards. A registered entity completes a CA by reviewing the facts and circumstances of an event
or disturbance, identifying relevant Reliability Standards and Requirements, evaluating compliance with these
Standards and Requirements, and self-reporting any potential noncompliance. Regional Entity (RE) compliance
staff also assesses significant events and disturbances to improve understanding of reliability risks that may guide
further compliance monitoring activities.
Registered Entity Responsibilities
The ERO enterprise encourages registered entities to perform a voluntary, systematic CA in response to all system
events and disturbances. Registered entities are also expected to share the CA with the RE for all Category 2 and
above events. The ERO Events Analysis process document describes the categories for events.3 Registered entities
should use the Sample Compliance Assessment Report Template (Appendix 3 of this document) when performing
a CA. In addition to the completed CA template, registered entities should provide to the RE sufficient event
information, such as the Brief Report or Event Analysis Report, so the RE may thoroughly understand the event.
Registered entities that follow the process above to systematically evaluate their own compliance performance,
identify, self-report potential noncompliance, and address reliability issues demonstrate the effectiveness of their
internal controls and their commitment to a culture of compliance. Registered entities that are able to
demonstrate strong internal controls and a robust culture of compliance that mitigates risk may be afforded some
recognition by way of reduced levels and frequency of compliance monitoring activities. Mitigating credit for these
actions is also considered during the enforcement of a noncompliance. Such credit is available to the registered
entity for comprehensive compliance assessments that clearly demonstrate a systematic review of applicable
Standards and, as appropriate, self-reporting.
Regional Entity Responsibilities
REs will review system event reports and CA reports provided by registered entities and may utilize a risk-based
approach to prioritize these evaluations. However, the REs will conduct a regional compliance evaluation (RCE)
for all Category 2 and above events. By exception, the RE may also examine lower category events that indicate
the need for closer examination. As part of its independent evaluation of the CA, the RE may request additional
information from the registered entity if it is needed to better understand the event. This process, while informal,
may be used to recommend a formal compliance monitoring method, such as a spot check or be used to
recommend the modification the scope of an upcoming audit.
The scope of RCEs and the manner in which the REs and NERC evaluate, process, and respond to these reviews is
intended to reflect the significance of the event. The registered entity can greatly assist the RE by providing a
thorough and systematic self-evaluation with its CA. The RE will share the RCE and CA with NERC staff.
3
http://www.nerc.com/pa/rrm/ea/EA%20Program%20Document%20Library/Final_ERO_EA_Process_V2.1.pdf
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Risk-based Approach to Compliance Monitoring and Enforcement
Risk-based Enforcement
The ERO Enterprise recognizes that not all instances of noncompliance require the same type of processing and
documentation and that there is a need to streamline processes for resolving minimal and moderate risk issues.
This is necessary to enable the ERO Enterprise, as well as industry, to allocate resources to address the issues
posing a higher level of risk to reliability. The ERO Enterprise will continue to use more formal enforcement
processes, particularly Notices of Penalty, to respond to higher risk issues. Such cases can lead to the identification
and implementation of above-and-beyond activities and other non-monetary sanctions, in addition to financial
penalties.
Compliance Exceptions
Based on the experience with a streamlined process and a reduced record since 2013, NERC and the REs have
exercised discretion when deciding whether to initiate an enforcement action for instances of noncompliance
posing a minimal risk to the reliability of the BPS. Issues resolved outside of the enforcement process are referred
to as compliance exceptions. The resolution of these issues outside of the enforcement process has not eliminated
oversight or visibility over the issues. Rather, these issues are provided for review by NERC and FERC. The process
has allowed NERC and the Regional Entities to work with registered entities to identify and mitigate minimal risk
issues promptly and more efficiently. Beginning in January 2015, all minimal risk instances of noncompliance will
be eligible for resolution as a compliance exception. While compliance exceptions will effectively supersede Find,
Fix, Track and Report (FFT) as the process for resolving minimal risk instances of noncompliance in the future, for
the time being, the FFT process remains relevant, particularly as it relates to moderate risk issues or minimal risk
issues that a region may not deem appropriate to be treated a compliance exception, based on individual facts
and circumstances of a particular noncompliance.
Self-Logging Program
Beginning in October 2013, NERC and the Regional Entities began to allow select registered entities with
demonstrated effective management practices to self‐identify, assess, and mitigate instances of noncompliance
to self-log4 minimal risk instances of noncompliance that would otherwise be individually self‐reported. Properly
logged items will be presumed appropriate for resolution as compliance exceptions unless there are additional
risk factors identified by the CEA. This is consistent with the notion that instances of noncompliance that are selfidentified through internal controls, corrected through a strong compliance culture, and documented by the
registered entity, should not be resolved through the enforcement process or incur a penalty, absent a higher risk
to the BPS.
The self-logging program also encourages the development and communication of management practices by
registered entities and rewards registered entities for implementing demonstrated, effective controls in place to
detect and correct issues as they arise.
4
The program is also known as the aggregation program.
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Risk-based Compliance Oversight Plan
Risk Elements Results
The ERO Enterprise has always assessed risks to the reliability of the BPS, as well as mitigating factors that may
reduce or eliminate a given reliability risk, and the ERO Enterprise will continue to do so under the Framework
referenced above. The ERO Enterprise developed a risk elements Guide to describe a process for identifying risks
to the BPS and associated registration functional categories and NERC Reliability Standards to those risks.
In 2015, the ERO Enterprise identified nine risk elements with specific areas of focus. REs will consider the nine
risk elements, along with regional risk considerations, to develop their Regional Implementation Plans.
The risk elements identify and prioritize existing risks to the reliability of the BPS. Each of the nine risk elements
below is accompanied by a table identifying Reliability Standards and Requirements associated with each risk.
The risk elements serve as an input into the overall Regional Risk Assessment to support a risk-informed
compliance oversight plan. Risk elements do not serve as a baseline list of Reliability Standards and Requirements,
as previously identified through the AML in prior years’ CMEP Implementation Plans, nor do they identify
Reliability Standards and Requirements that must be audited. Rather, they provide the starting point for the
analysis of regional risks which will then be reflected in the Regional Implementation Plans.
2015 Risk Elements
The nine risk elements below are not a comprehensive list of all risks to the reliability of the BPS. Where issues
are being addressed through other mechanisms, they are not included herein for compliance assurance activities.5
1.
Infrastructure Maintenance
As the BPS continues to age, lack of infrastructure maintenance is a reliability risk that continues to grow in
importance.
AC Substation Equipment Failures
As reported in the State of Reliability 2014 report, AC Substation Equipment Failures had the largest
positive correlation with automatic transmission outage severity in 2013. The correlation is statistically
significant: a pattern and underlying dependency exists between AC substation equipment failures and
transmission outage severity. While it is unclear whether or not there is a relationship between substation
equipment failures and maintenance, such a relationship may exist. The issue of AC Substation Equipment
Failure is one that is still being investigated, and action plans to address this concern are being developed.
Thus, the ERO CMEP IP may be updated during the year to reflect new activities based on NERC’s
investigation.
Aging Infrastructure
The general concern of Infrastructure Maintenance has been highlighted in other NERC documents. The
2013 Long-Term Reliability Assessment highlighted this area of concern, stating:
Aging transmission system infrastructure has many challenges, such as the availability of spare
parts, the obsolescence of older equipment, the ability to maintain equipment due to outage
scheduling restrictions, and the ability to keep pace with technological advancements … Larger
scale “infrastructure revitalization” may be necessary in the future; however, with older
generation retiring throughout the next decade, the average age of BPS generation facilities will
be relatively young. Implementation of any replacement strategy and in-depth training programs
5
For example, vegetation management and right-of-way clearances, while key priorities, are not areas of focus for compliance assurance
activities because they are being addressed through other ongoing targeted initiatives.
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Risk-based Compliance Oversight Plan
requires additional capital investment, engineering and design resources, and construction labor
resources, all of which are in relatively short supply.
Areas of Focus
Table 1 – Infrastructure Maintenance
Standard
Requirements
PRC-005-2
R3, R4
PRC-008-0
R1, R2
PRC-011-0
R1
PRC-017-0
R1
Entities for Attention
Generator Owners
Transmission Owners
Distribution Provider
Distribution Providers
Transmission Owners
Distribution Providers
Transmission Owners
Distribution Providers
Generator Owners
Transmission Owners
2.
Uncoordinated Protection Systems
Protection systems that trip unnecessarily can contribute significantly to the extent of an event. When protection
systems are not coordinated properly, the order of execution can result in either incorrect elements being
removed from service or more elements being removed than necessary. This can also occur with Special
Protection Systems, Remedial Action Schemes, and Underfrequency Load Shedding and Undervoltage Load
Shedding schemes. Such coordination errors occurred in the September 8, 2011 event (see recommendation 19)6
and the August 14, 2003 event (see recommendation 21).7 Both the RISC’s ERO Priorities: RISC Updates and
Recommendations report and NERC’s ERO Top Priority Reliability Risks 2014-2017 report recognize protection
systems as a significant risk based on the extensive work and detailed analysis contained in the State of Reliability
reports from 2012 and 2013.
Areas of Focus
Table 2 – Uncoordinated Protection
Systems
Standard
Requirements
Entities for Attention
PRC-001-1.1
R3, R5
Generator Operator
Transmission Operator
Transmission Operator
R4
3.
Protection System Misoperations
Protection systems are designed to remove equipment from service to avoid damage to equipment when a fault
occurs. A protection system that does not trip or is slow to trip may lead to the damage of equipment (which may
result in degraded reliability for an extended period of time), while a protection system that trips when it should
not can remove important elements of the power system from service at times when they are needed most.
Unnecessary trips can even start cascading failures as each successive trip can cause another protection system
to trip.
NERC’s 2012 and 2013 State of Reliability Reports identified protection system misoperations as a significant
threat to BPS reliability. Additional activities are needed to ensure this risk is managed adequately.
6
7
See Arizona-Southern California Outages on September 8, 2011.
See Final Report on the August 14, 2003 Blackout.
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Risk-based Compliance Oversight Plan
Key Finding 3 of NERC’s State of Reliability 2014 report was based on the continuing history of misoperations being
a significant contributor to events. The report notes:
In 2013, there were 71 transmission-related system disturbances that resulted in a NERC Event
Analysis reported event. Of those 71 events, 47 (about 66 percent) had associated misoperations.
Of these 47 events, 38 (about 81 percent) experienced misoperations that were contributory to
or exacerbated the severity of the event. In several cases, multiple misoperations occurred during
a single disturbance. Cause coding has not yet been completed for all 2013 events, but it is
estimated that there were 60–75 misoperations associated with these 38 reportable events.
Therefore, out of approximately 2,000 total misoperations in 2013, approximately 3.0 to 3.5
percent were causal to or exacerbated by the severity of reportable system disturbances.
Both the RISC’s ERO Priorities: RISC Updates and Recommendations report and NERC’s ERO Top Priority Reliability
Risks 2014-2017 report recognize protection systems and their failures as a significant risk based on the extensive
work and detailed analysis contained in the State of Reliability reports from 2012 and 2013.
Areas of Focus
Table 3 – Protection System Misoperations
Standard
Requirements
PRC-004-2.1a
R1.
R2.
PRC-016-0.1
R1, R2
PRC-023-38
R1.
PRC-025-1
R1
Entities for Attention
Transmission Owner
Distribution Provider
Generator Owner
Transmission Owner
Generator Owner
Distribution Provider
Transmission Owner
Generator Owner
Distribution Provider
Transmission Owner
Generator Owner
Distribution Provider
4.
Workforce Capability
A lack of knowledge, experience, and capabilities is a common threat in any industry that relies on skilled workers.
The RISC, in its ERO Priorities: RISC Updates and Recommendations report, highlighted Workforce Capability and
Human Error as a priority area needing focus. Findings of the RISC focused around the need to improve
organizational performance and culture to ensure support for the individual worker to gain knowledge and
address known issues in advance of their reoccurrence. This is also reflected in NERC’s ERO Top Priority Reliability
Risks 2014-2017 report.
NERC has also identified the challenge of maintaining a robust and knowledgeable workforce for a number of
years. In the 2013 Long-Term Reliability Assessment, NERC notes, “Workers entering the power industry will be
tasked with understanding and implementing a variety of new technologies and smarter systems and devices.
Across the industry, there is substantial interest in training and hiring workers to support these industry needs as
well as transferring the expertise and knowledge of retiring workers.”
8
Reliability Standard PRC-023-3 is effective October 1, 2014. However, PRC-023-2 remains relevant as Criterion 6 of Requirement R1 will
remain in effect until PRC-025-1 is fully implemented pursuant to its phased in implementation plan.
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Risk-based Compliance Oversight Plan
Areas of Focus
Table 4 – Workforce Capability
Standard
CIP-004-3a
Requirements
R1, R2
EOP-001-2.1b
R2, R3 R4
EOP-003-2
R8.
R10.
EOP-005-2
R11.
EOP-006-2
R17.
R9, R10
PER-005-1
R3.
TOP-004-2
R6
Entities for Attention
Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner
Transmission Operator
Balancing Authority
Transmission Operator
Balancing Authority
Transmission Operator
Transmission Operator
Transmission Owner
Distribution Provider
Generator Operator
Reliability Coordinator
Reliability Coordinator
Balancing Authority
Transmission Operator
Transmission Operator
5.
Monitoring and Situational Awareness
Without the right tools and data, operators can make uninformed decisions which may or may not be appropriate
to ensure reliability for the given state of the system. NERC’s ERO Top Priority Reliability Risks 2014-2017 notes
that “stale” data and lack of analysis capabilities contributed the 2003 and 2011 events. Certain essential
functional capabilities must be in place, with up-to-date information, available for use on a regular basis, and
utilized by staff to make informed decisions.
An essential component of Monitoring and Situational Awareness is the availability of information when needed.
Unexpected outages of tools, or planned outages without appropriate coordination or oversight, can leave
operators without visibility to some or all of the system they operate. While failure of a decision‐support tool is
rarely the cause of an event, such failures manifest as latent risk that further hinders the decision‐making
capabilities of the operator. One clear example of this is the August 14, 2003 event.
NERC has analyzed data and identified that outages of tools and monitoring systems are fairly common
occurrences. The RISC’s ERO Priorities: RISC Updates and Recommendations report, NERC’s ERO Top Priority
Reliability Risks 2014-2017 report, and the Cyber Attack Task Force final report recognize this concern.
Areas of Focus
Table 5 – Monitoring and Situational
Awareness
Standard
Requirements
Entities for Attention
EOP-010-19
IRO-002-2
IRO-005-3.1a
IRO-008-1
IRO-014-1
R2
R6, R7, R8
R1
R1, R2
R1
PRC-001-1.1
R6
Reliability Coordinator
Reliability Coordinator
Reliability Coordinator
Reliability Coordinator
Reliability Coordinator
Transmission Operator
Balancing Authority
Transmission Operator
Balancing Authority
Transmission Operator
TOP-002-2.1b
R4, R19
R11
9
EOP-010-1 becomes effective on April 1, 2015. Pursuant to the implementation plan, Requirement 2 of EOP-010-1 will become effective
on the first day following the retirement of IRO-005-3.1a.
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Risk-based Compliance Oversight Plan
Table 5 – Monitoring and Situational
Awareness
Standard
Requirements
TOP-006-2
R2
TOP-008-1
FAC-011-2
R4
R1, R2, R3
FAC-014-2
R5, R6
Entities for Attention
Reliability Coordinator
Transmission Operator
Balancing Authority
Transmission Operator
Reliability Coordinator
Reliability Coordinator
Planning Authority
Transmission Planner
Transmission Operator
6.
Long Term Planning and System Analysis
Long term planning and system analysis is related to several other areas (such as increased use of DSM, integration
of variable generation, changes in load and system behavior, Smart Grid, increased dependence on natural gas,
fossil requirements and retrofit outage coordination, nuclear generation retirements and outages, and resource
planning). Long-term planning and analysis have been highlighted as a concern in RISC’s ERO Priorities: RISC
Updates and Recommendations report, and in NERC’s ERO Top Priority Reliability Risks 2014-2017 report.
Areas of Focus
Table 6 – Long Term Planning and System
Analysis
Standard
10
TPL-001-0.1
Requirements
Entities for Attention
R1.
Planning Authority
Transmission Planner
7.
Threats to Cyber Systems
Threats to cyber systems remain an area of significant importance. The need for attention in this area is addressed
in the 2013 Long-Term Reliability Assessment report, in the RISC’s ERO Priorities: RISC Updates and
Recommendations report, the Cyber Attack Task Force final report, and in NERC’s ERO Top Priority Reliability Risks
2014-2017 report. The risk includes threats and vulnerabilities that result from compromise of technology or
communications that support the reliable operations of the BPS.
Areas of Focus11
Table 7 – Cyber Security
Standard
CIP-002-3
Requirements
Entities for Attention
R2, R3
Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner
10
The effective date of TPL-001-4 is January 1, 2015. However, as a result of the phased implementation plan, earlier versions of the TPL
Reliability Standards are referenced here.
11
While Table 7 lists the CIP version 3 Reliability Standards (as those are currently enforceable), the ERO, through release of its Cyber
Security Reliability Standards CIP V5 Transition Guidance, actively encourages and supports registered entities transitioning from
compliance with the version 3 Reliability Standards directly to the version 5 Reliability Standards. As stated in that guidance, NERC and the
Regional Entities will take a flexible compliance monitoring and enforcement approach for the CIP Reliability Standards, recognizing that
the details of implementing a version 3 to version 5 transition may cause a significant impact on certain compliance monitoring activities.
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Risk-based Compliance Oversight Plan
Table 7 – Cyber Security
Standard
CIP-003-3
CIP-004-3a
CIP-005-3a
CIP-006-3
CIP-007-3a
CIP-009-3
Requirements
R4, R6
R3, R4
R1, R4
R1, R4, R5
R1, R2, R4, R6, R8
R1, R2
Entities for Attention
Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner
Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner
Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner
Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner
Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner
Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner
8.
Human Error
Human Error remains a key focus for the ERO Enterprise. Included in this subset are communication errors which
can pose a significant potential risk to BPS reliability. Human Error was identified as a key issue by both the RISC
in its ERO Priorities: RISC Updates and Recommendations report and by NERC in its ERO Top Priority Reliability
Risks 2014-2017 report.
Areas of Focus
Table 8 – Human Error
Standard
Requirements
Entities for Attention
COM-002-2
R2.
Reliability Coordinator
Transmission Operator
Balancing Authority
9.
Extreme Physical Events
Extreme Physical Events are those events that result in extensive damage to equipment, irrespective of cause.
Such events could include earthquake, GMD events, high wind, flooding, physical attack, or sabotage. NERC
identified this concern as a significant risk in its ERO Top Priority Reliability Risks 2014-2017 report. As concluded
in the report, risk avoidance is insufficient to manage this risk, and additional focus must be given to those things
that focus on resiliency and recovery.
Risk mitigation efforts (reducing the potential consequence) are underway, but additional focus is needed to
address and minimize both the magnitude and duration of the consequences of an extreme physical event.
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Risk-based Compliance Oversight Plan
Areas of Focus
12
Table 9 – Extreme Physical Events
Standard
Requirements
EOP-0023.1
R6, R7, R8
EOP-004-2
R2
EOP-005-2
EOP-005-2
EOP-006-2
EOP-008-1
R1, R6
R9.
R1.
R3
EOP-008-1
R4
EOP-010-1
R1.
R3.
TPL-002-0b
R1.
TPL-003-0b
R1.
TPL-004-0a
R1.
Entities for Attention
Balancing Authority
Reliability Coordinator
Reliability Coordinator
Balancing Authority
Transmission Owner
Transmission Operator
Generator Owner
Generator Operator
Transmission Operator
Transmission Operator
Reliability Coordinator
Reliability Coordinator
Balancing Authority
Transmission Operator
Reliability Coordinator
Transmission Operator
Planning Authority
Transmission Planner
Planning Authority
Transmission Planner
Planning Authority
Transmission Planner
Regional Risk Assessments
When considering risk elements, REs will perform a Regional Risk Assessment, identifying risks specific to the
region that could potentially impact the reliability of the BPS. After determining region-specific risks, REs will also
identify the related Reliability Standards and Requirements associated with those risks. These Reliability Standards
and Requirements are not intended to be a static list that must be examined during all Compliance Audits. Rather,
the risk elements identified by the RE will serve as input considerations when conducting an IRA for a registered
entity.
REs are ultimately responsible for identifying and prioritizing risk elements within their footprints. REs should
consider risk elements as an input into their Regional Risk Assessments. In doing so, REs are expected to:
 Gather and review RE-specific risk reports and operational information (e.g. interconnection points and
critical paths, system geography, seasonal/ambient conditions, etc.),
 Review and prioritize potential RE-specific risks, and
 Identify associated Reliability Standards and Requirements that will be inputs into the IRAs, ICE, and
ultimately the compliance oversight plan.
The Regional Implementation Plans will describe the process and results. It should explain how it identified the
risk in a particular RE footprint, including reasons why any risk elements identified above are not included or
applicable to the RE footprint. Although each RE will consider risk elements, and may use similar risk
considerations, the output of the Regional Risk Assessments may differ as a result of regional characteristics and
the uniqueness of each RE’s footprint.
Regional Compliance Oversight Plan
Based on the RE’s consideration and assessment of risk elements and Regional Risk Assessments, each RE will
develop a compliance oversight plan, which, in 2015, will include, at a minimum, the list of planned audits for
12
CIP-014-1 – Physical Security also addresses extreme physical events, but it is not yet FERC-approved. Table 9 may be modified to reflect
the Requirements of CIP-014-1 following such approval.
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Risk-based Compliance Oversight Plan
Reliability Coordinators, Balancing Authorities, and Transmission Operators that are in the three-year audit cycle.
REs may also identify other registered entities that it will monitor through appropriate CMEP tools based on risk
elements and Regional Risk Assessments, and the application of IRA and ICE.
NERC Oversight of Regional Implementation Plans
NERC collects and reviews the Regional Implementation Plans prior to posting the final version of the ERO CMEP
Implementation Plan. NERC oversight of the Regional Implementation Plans will focus on how the REs conducted
Regional Risk Assessments and how the assessments’ results ultimately led to the compliance oversight plan.
The RE should document all processes, conclusions, and results used to develop a registered entity’s oversight
plan and will not need to obtain prior approval from NERC on oversight plans. However, REs should maintain
supporting documentation for review by NERC in connection with its oversight of the compliance assurance
program.
The application of the Framework by the REs will reflect RE-specific circumstances including, as noted above,
varying stages of conducting IRAs and ICEs. NERC oversight and regular training will ensure that all processes
discussed herein are implemented in a consistent manner throughout the ERO Enterprise.
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Revision History
Version
Version 0.0
Version 1.0
Date
September 8, 2015
November 18, 2014
Revision Detail
Initial release of ERO CMEP IP
ERO CMEP IP updated to include Regional Entity IPs in Appendices. Additional
updates include:
 Added section and guidance on Compliance Assessments for Events
and Disturbances. Refer to “Risk-based Compliance Monitoring”
section and Appendix B.
 Added details and guidance for Self-Certification requirements for
registered entities in 2015.
Refer to “Risk-based Compliance
Monitoring” section.
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Appendix A1 - Florida Reliability Coordinating Council (FRCC)
2015 CMEP Implementation Plan
This Appendix contains the CMEP Implementation Plan (IP) for the FRCC as required by the NERC Rules of
Procedure.
1. Compliance Monitoring and Enforcement
1.1 CMEP IP Highlights and Material Changes
 In mid-2014, the FRCC Compliance department reorganized to create a department called Risk
Assessment and Mitigation (RAM). This group will be focused on risk assessment both before a monitoring
activity takes place to help determine the scope of monitoring oversight, and after a possible violation is
discovered to help determine the risk posed by that violation so the most efficient disposition can take
place. The risk evaluation of an entity, which precedes the entity’s compliance oversight plan, will include
the Inherent Risk Assessment and voluntary Internal Controls Evaluation(s) of registered entities. In
addition to performing risk determinations, RAM is the registered entities’ primary contact for selfreporting and mitigation plans.
 The formation of the RAM group and associated new division of responsibilities, has enabled the FRCC
enforcement group to concentrate on violation determination and disposition, and compliance
department metrics.
 Audit notification letters will be sent to the registered entities ninety (90) days prior to commencement
of a Compliance Audit.
 Per CMEP section 3.1.4.2, audit period End Dates are being modified to thirty (30) days following the date
of the audit notification letter. The audit period will still begin on the day after the End Date of the
registered entity’s prior Compliance Audit by the FRCC (or the later of June 18, 2007 or the date the
registered entity became subject to Reliability Standards if the registered entity has not previously been
subject to a Compliance Audit).
 Compliance audits conducted in 2015 will include a management review of any possible non-compliance
findings prior to the completion of the audit. In order to facilitate the management review, audit exit
briefings may be conducted remotely, following on-site activities. However, the audit team will present
a summary briefing prior to concluding the on-site portion of the audit.
1.2 Other Regional Key Initiatives & Activities
 FRCC enforcement will include the “Exception” method as an option for disposition of minimal risk noncompliances in 2015.
 The FRCC enforcement program will reserve enforcement actions to include the Find, Fix, Track and
Report process and Notices of Penalties for those non-compliances that pose moderate or serious/
substantial risks to the reliability of the BPS. As to other non-compliances, FRCC enforcement will exercise
appropriate discretion to initiate the Exception process for minimal risk non-compliances of Reliability
Standards.
 FRCC will continue to evaluate registered entities for potential inclusion into the Entity Self-Logging
program (formerly known as the “Aggregation” pilot program) which allows those registered entities that
have demonstrated effective management practices to keep track of minimal risk non-compliances (and
associated mitigation) on a log that is periodically reviewed by FRCC.
2. Regional Risk Assessment Process
The FRCC has reviewed the nine ERO identified risk elements and associated areas of focus for implementation
plan coordination and concurs with the specified Standards/Requirements in all the areas of focus with
additions documented below in the Regional Risks and Associated Reliability Standards section.
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Appendix A1 - Florida Reliability Coordinating Council (FRCC) 2015 CMEP Implementation Plan
FRCC also considered the following risk elements and identified additional Standards/Requirements for
monitoring as detailed below in the Regional Risks and Associated Reliability Standards section.

Number and type of registered functions
As of September 24, 2014, FRCC has sixty-eight (68) registered entities.13 The FRCC Regional Entity is
registered as a Reliability Coordinator and Planning Coordinator. The SERC Regional Entity organization is
the Compliance Enforcement Authority for these functions.
The FRCC has not identified any region-specific risks associated with the number and type of registered
functions within the FRCC, and therefore has not included additional Reliability Standards due to
registered functions.

Geographic location such as seasonal/ambient conditions and terrain
The area of the State of Florida that is within the FRCC Region is peninsular Florida east of the Apalachicola
River. Areas west of the Apalachicola River are within the SERC Region. The entire FRCC Region is within
the Eastern Interconnection and is under the direction of the FRCC Reliability Coordinator.
The FRCC considers factors such as its susceptibility to tropical storms and hurricanes when selecting
additional Reliability Standards for inclusion in its monitoring activities. Such storms increase the
probability of the region experiencing transmission line vegetation contact, significant imbalances in
generation and load, the need to evacuate control centers, and the need to implement restoration plans.
As a result, requirements of the Reliability Standards for Loss of Control Center Functionality, Transmission
Vegetation Management, and Automatic Underfrequency Load Shedding have been added.

BPS transmission lines (circuit miles, voltage levels, IROL flowgates)
The FRCC has not identified any region specific risks associated with the BPS transmission lines located in
the FRCC region, and therefore has not included additional Reliability Standards due to BPS transmission
lines.

BPS generation facilities
The FRCC has not identified any region specific risks associated with the BPS generation facilities located
in the FRCC region, and therefore has not included additional Reliability Standards due to BPS generation
facilities.

Blackstart Resources
Requirements of the Reliability Standard for System Restoration from Blackstart Resources are already
included in NERC’s risk elements results. Therefore, no requirements have been added.

Interconnection points and critical paths
The FRCC region only connects to the Eastern Interconnection on the north side of the region due to its
peninsular geography. Therefore, the FRCC considers factors such as susceptibility to system separation
when selecting additional Reliability Standards for inclusion in its monitoring activities. As a result of the
FRCC’s limited interconnection points, and as also mentioned for geographic location previously,
requirements of the Reliability Standard for Automatic Underfrequency Load Shedding have been added.
13
Registered functions include: Balancing Authority, Distribution Provider, Generator Owner, Generator Operator, Interchange Authority,
Load Serving Entity, Planning Authority, Purchasing Selling Entity, Resource Planner, Reserve Sharing Group, Transmission Owner,
Transmission Operator, Transmission Planner, and Transmission Service Provider.
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Appendix A1 - Florida Reliability Coordinating Council (FRCC) 2015 CMEP Implementation Plan

Special Protection Schemes (SPS)
The FRCC considers factors such as any major SPS installed in the FRCC region when selecting additional
Reliability Standards for inclusion in its monitoring activities. As a result of a major SPS in the FRCC region,
and as also mentioned for geographic location and interconnection points previously, requirements of the
Reliability Standard for Automatic Underfrequency Load Shedding have been added.

System events and trends
The FRCC considers internal system events when selecting additional Reliability Standards for inclusion in
its monitoring activities. External events are reviewed and considered in NERC’s risk elements. As no
major internal events have occurred recently, FRCC has not included additional Reliability Standards due
to system events and trends.

Compliance history trends
The FRCC considers historical compliance trends within the region when selecting additional Reliability
Standards for inclusion in its monitoring activities. As a result, requirements of the Reliability Standards
for Cyber Security – Electronic Security Perimeter(s), Cyber Security – Physical Security of Critical Cyber
Assets, Cyber Security – Systems Security Management, Loss of Control Center Functionality, and Facility
Ratings have been added.
3. Regional Risks and Associated Reliability Standards
The table below contains the Regional risk focus areas identified during the Regional Risk Assessment. The
table also contains associated Reliability Standards/Requirements to identified risks that may be considered
in the Regional compliance oversight plan.
Reliability Standards Subject to Regional Monitoring
Regional Risk
Focus Areas
Infrastructure
Maintenance
Extreme Physical
Events
Extreme Physical
Events
Extreme Physical
Events
Compliance
History Trends
Justification
The implementation plan for PRC-005-2 will result in
PRC-005-1.1b remaining in effect for 2015. Registered
entities are likely to have Protection Systems subject to
the current version of the standard, as well as the new
version. Therefore, monitoring activities for PRC-005
may include both PRC-005-1.1b and PRC-005-2. This is
a clarification on FRCC monitoring, and is not a newly
identified regional risk element.
FRCC’s susceptibility to hurricanes increases the risk of
a control center event.
FRCC’s susceptibility to hurricanes and frequent
storms, along with an extended growth season,
increases the risk of vegetation related outages.
The FRCC’s peninsular geography along with its
susceptibility to hurricanes, limited connections to the
Eastern Interconnect and the existence of a significant
SPS that could result in islanding increase the risk of an
island event occurring.
FRCC has experienced a high number violations with
these Standards/Requirements.
Associated Standard &
Requirement(s)
PRC-005-1.1b R2
EOP-008-1 R6
FAC-003-3 R1, R2, R6 & R7
PRC-006-1 R8 & R9
FAC-008-3 R2, R3 & R6
CIP-005-3a R2
CIP-006-3c R2
CIP-007-3c R3
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Appendix A1 - Florida Reliability Coordinating Council (FRCC) 2015 CMEP Implementation Plan
4. Compliance Oversight Plan
Self-Certifications
For 2015 compliance monitoring, FRCC will forgo the annual Self-Certification process and replace annual
Self-Certification activities with a more focused risk based approach. FRCC will use Self-Certification in a
coordinated approach with the other compliance monitoring methods to address the Standards and
requirements that represent the greatest risk to the reliability to the Bulk Power System (BPS) based on the
registered entities’ overall risk assessment. FRCC will follow the guidance in the 2015 ERO CMEP IP, as well
as consider results from Regional risks assessments, registered entity inherent risk assessments, etc. FRCC
will implement guided Self-Certification for registered entities to Self-Certify compliance with those
Standards and Requirements identified through the risk assessment process. The registered entity should
provide the methodology and other documentation used for self-assessment to determine the compliance
status for those requirements. This “guided” approach will include more information on the expectations of
what the registered entity should consider and include in their response to the FRCC.
Reliability Standards monitored through guided Self-Certification will not be included in the 2015 registered
entity Compliance Audit scope.
Those responsible entities that do not have any Critical Assets or Critical Cyber Assets under the CIP V3
Standards will not be scheduled for an off-site audit for the CIP Reliability Standards during the CIP Version 5
Transition Period (August 2014 through March 31, 2016). Instead, those Responsible Entities will be
monitored via the guided Self-Certification process for the applicable CIP Standards.
In addition, non-BA/TOP registered entities that were initially scheduled for a six-year audit during 2015 will
instead be monitored by guided Self-Certifications. This will allow the RAM department time to perform the
necessary IRAs and ICEs.
Periodic Data Submittals
FRCC has identified the Reliability Standards and requirements listed in the table below that require Periodic
Data Submittals. The Monthly data submittals are due by the 10th of the month for the previous month’s
data and the Quarterly data submittals are due by the 15th of the month following the previous quarter. All
data submittals are to be submitted via the Compliance Tracking and Submittal system (CTS).
For Quarterly submittals for FAC-003-3 R1 and R2, if an entity does not have any Sustained Outage(s) during
a respective quarter, they are not expected to submit a quarterly report. In turn, FRCC will advise NERC that
there were no Sustained Outages within the quarter. However, entities are expected to submit a FAC-003-3
Event form for ALL Sustained Outages within the quarter in which the event occurs, as specified in the
standard. Again, while not specifically required by FAC-003-3, FRCC strongly encourages and appreciates
entities’ reporting, within 48 hours, all Sustained Outages for Categories 1A&B, 2A&B and 4A&B utilizing the
FAC-003-3 Event form. FRCC will be notified when an event is reported by the CTS system and will follow-up
accordingly with the submitting entity and NERC.
2015 Periodic Data Submittal Plan
Standard &
Requirement
BAL-001-1 R1, R2
BAL-002-1 R1
FAC-003-3 R1 and R2
Justification
CPS 1 and CPS 2 data collected by applicable registered entities
DCS 2 data collected by applicable registered entities
Sustained Outage data collected by applicable registered entities
Compliance Audits
The audit schedule is also located on the FRCC’s website here:
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Appendix A1 - Florida Reliability Coordinating Council (FRCC) 2015 CMEP Implementation Plan
https://www.frcc.com/Compliance/FRCCCompliance/ComplianceDocumentLibrary.aspx
NCR #
NCR00004
NCR00021
NCR00023
NCR00045
NCR00057
NCR00068
NCR00073
NCR00079
2015 Compliance Audit Plan
Registered Entity
Beaches Energy Services of Jacksonville Beach (BES)
Florida Keys Electric Cooperative Assn (FKEC)
Florida Municipal Power Pool (FMPP)
Lee County Electric Cooperative, Inc (LCEC)
Orlando Utilities Commission (OUC)
Seminole Electric Cooperative (SEC)
Tallahassee, City of (TAL)
Vero Beach, City of (VERO)
5. Compliance Outreach
Compliance Outreach Activities
Outreach Activity
Spring Compliance Workshop
CIP Compliance Workshop
Fall Compliance Workshop
Reliability Standard Webinars
CIP Compliance Newsletter
Anticipated Date
April 14-16, 2015
May 12-14, 2015
November 10-12, 2015
Periodic
Periodic
CIP Version 5 (V5) Outreach
FRCC will also develop a CIP Outreach Program for the FRCC registered entities to educate and provide
transparency on outstanding CIP V5 issues. This outreach may involve NERC staff support, evaluating an
entity’s V5 progress, proactively addressing V5 related questions and spending additional time assessing V5
readiness during CIP Compliance Audits.
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Appendix A2 - Midwest Reliability Organization (MRO) 2015
CMEP Implementation Plan
This Appendix contains the CMEP Implementation Plan (IP) for MRO as required by the NERC Rules of Procedure.
1. Compliance Monitoring and Enforcement
1.3 CMEP IP Highlights and Material Changes
Mitigating Activities for Compliance Exceptions
As part of the Annual Implementation Plan, MRO staff will periodically sample Compliance Exceptions to
verify that the mitigating activities have been completed. The sample will come from only those
Compliance Exceptions that have been identified by a registered entity as already mitigated, or Compliance
Exceptions that have a planned mitigation date that has passed. Also, the Compliance Exceptions sampled
are not restricted to the registered entities that have an Inherent Risk Assessment performed on them for
2015.
The periodic sampling may occur at any time, and will be reviewed through informal means, Spot Checks, or
during a normally scheduled Compliance Audit. MRO staff are required to document the results regardless
of whether a formal or informal review process is used.
All mitigation activities relating to enforcement matters that are filed with regulators will be verified for
completion.
2. Regional Risk Assessment Process
Analysis performed by MRO on risks related to the Risk Areas within the Risk Elements resulted in the
identification of a list of Requirements determined to provide an initial level of risk mitigation within the
MRO region. (Section 3 below contains this list of requirements.) The analysis focused on several areas that
have been identified as having a larger impact to reliability, including areas identified within the 2003 and
2011 blackout reports. The Requirements in Section 3 are not considered the only or complete way to
mitigate the related risks, but were determined to be a starting point to focus oversight in the MRO region
related to these risks. As referenced in Section 4 below, these requirements are subject to guided SelfCertifications in 2015. In addition to this oversight, as part of the Inherent Risk Assessments that will be
performed on registered entities, additional Standards and Requirements will be considered and potentially
scoped into entity-specific oversight plans.
3. Regional Risks and Associated Reliability Standards
The table below contains the Regional risk focus areas identified during the Regional Risk Assessment
process. The table also contains Reliability Standards/Requirements associated with identified risks that
may be considered in the Regional compliance oversight plan.
Reliability Standards Subject to Regional Monitoring
Risk Area
Protection
System
Misoperations
Long Term
Planning and
System Analysis
Associated Standard &
Requirement(s)
It is important for entities with awareness of a wide area of the
PRC-023-2 R6
BES, to determine those facilities which are most important and
require relay loadability attention.
Planning criteria were called out in the 2003 and 2011 blackout
TPL-002-0b R2
reports.
Justification
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Appendix A2 - Midwest Reliability Organization (MRO) 2015 CMEP Implementation Plan
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Requirement(s)
Threats to Cyber It is important to periodically assure that the ESP is secure, even if CIP-005-3a R4
Systems (risk
testing is being done after individual changes. Small changes in
elements)
networks that seem to have no impact locally can cause changes in
the security posture of the overall network.
Threats to Cyber It is important to periodically assure that CCAs are secure, even if
CIP-007-3a R8
Systems (risk
testing is being done after individual changes. Small changes in
elements)
systems that seem to have no impact locally can cause changes in
the security posture.
Human Error (risk The issuing of directives is crucial to reliable system operation, as
COM-002-2 R2
elements)
they are performed by those entities that have a wide area view,
and are used during times of emergency to alleviate events.
Monitoring and
Evaluation of planning and operational criteria was a technical
FAC-014-2 R2
Situational
initiative from the 2003 blackout.
Awareness
Monitoring
Real-time operating tools were called out in the 2003 blackout
TOP-002-2.1b R11
Situational
report as well as the 2011 blackout report.
Awareness (risk
elements)
Extreme Physical It is important to inspect rights of way to determine if unscheduled FAC-003-3 R6
Events
maintenance needs to occur, in order to preemptively identify
vegetation issues that could cause a fault. Poor vegetation
management was a contributing factor to the 2003 blackout.
Extreme Physical It is important to complete vegetation management in order to
FAC-003-3 R7
Events
prevent transmission line faults, which can lead to cascading
events. Poor vegetation management was a contributing factor to
the 2003 blackout.
Uncoordinated
The performance of protection systems directly impacts the
PRC-001-1 R3
Protection
operation of the BES, therefore coordination of changes to
Systems (risk
protection systems is crucial to reliability. Improved protection
elements)
system coordination was a recommendation in the 2011 blackout
report.
Uncoordinated
The performance of protection systems directly impacts the
PRC-001-1 R5
Protection
operation of the BES, therefore coordination of changes to the BES
Systems (risk
that impact protection systems is crucial to reliability.
elements)
Risk Area
Justification
4. Compliance Oversight Plan
Self-Certifications
For 2015, Self-Certifications will include staff guidance and instructions. These “guided” Self-Certifications
will focus more on risk and supporting evidence than the previous annual Self-Certifications. As part of the
guided Self-Certification process, registered entities will provide MRO with supporting evidence to
substantiate determinations.
These guided Self-Certifications are intended to provide MRO with reasonable assurance of compliance
based upon the results of the registered entity’s assessment. When appropriate, the guided SelfCertification can be used instead of Compliance Audits or Spot Checks as the monitoring tool for specific
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Appendix A2 - Midwest Reliability Organization (MRO) 2015 CMEP Implementation Plan
Reliability Standards and Requirements. The overall goal of the guided Self-Certification process is to
improve the effectiveness of oversight and increase efficiency by relying on the work of registered entities in
meeting compliance requirements.
Part of the process of relying upon the work of others includes MRO performing a review of the work and
evidence supporting the guided Self-Certification results. MRO may re-perform the work, in part, in order to
verify the accuracy of the Self-Certification determinations. In the event that further substantiation is
needed, MRO staff may conduct a random Spot Check of the work or include the applicable Standards and
Requirements in a subsequent Compliance Audit. The overall goal of the guided Self-Certification process is
to provide reasonable assurance that the entity meets compliance with the applicable Standards and
Requirements.
Guided Self-Certifications will be performed over the implementation period (January 1 to December 31) on
a quarterly basis for an identified baseline set of high impact Reliability Standards that have been deemed
important for reliable operations of the BPS. The intent of the quarterly frequency is to disperse the
workload to assure sufficient time for completion and review, and to promote continuous self-monitoring of
compliance.
In addition to the quarterly guided Self-Certification schedule, guided Self-Certifications may also be used for
lower risk compliance monitoring as a result of Inherent Risk Assessments of registered entities and for
lower risk events that could or did negatively impact the reliable operation of the region or systems within
the region.
The following list of registered entities have been identified as being on the 2015 Compliance Audit schedule.
Additional registered entities, at the discretion of MRO, will also be subject to Inherent Risk Assessments
(IRAs). Based on IRA results and any subsequent Internal Control Evaluations (ICE), these additional registered
entities may also be subject to a Compliance Audit in 2015.
NCR #
NCR01030
NCR01013
NCR01012
NCR01003
NCR10102
NCR00826
NCR00952
NCR01033
NCR01029
NCR00818
5.
2015 Compliance Audit Schedule
Registered Entity
Southern Minnesota Municipal Power Agency
Minnkota Power Cooperative
Minnesota Power
Manitoba Hydro
Tri-State Generation and Transmission Association
Midcontinent Independent System Operator, Inc.
Wisconsin Public Service Corporation
Upper Peninsula Power Company
Saskatchewan Power Corporation
Madison Gas and Electric
Compliance Outreach
Compliance Outreach Activities
Outreach Activity
MRO Newsletter
MRO Hot Topics
MRO Operations Conference
MRO Security Conference
MRO Compliance and Enforcement Conference
Anticipated Date
Six times a year
Periodically as needed
Summer 2015
Fall 2015
Fall 2015
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Appendix A2 - Midwest Reliability Organization (MRO) 2015 CMEP Implementation Plan
Compliance Outreach Activities
Outreach Activity
Registered Entity-specific conferences and meetings
Anticipated Date
Periodically as needed
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Appendix A3 - Northeast Power Coordinating Council (NPCC)
2015 CMEP Implementation Plan for Entities within the U.S.
This Appendix contains the CMEP Implementation Plan (IP) for the registered entities within the U.S. portion of
NPCC as required by the NERC Rules of Procedure.
1. Compliance Monitoring and Enforcement
1.1 CMEP IP Highlights and Material Changes
NPCC will continue to implement a cyber-security outreach program that consists of NPCC Subject Matter
Experts visiting critical facilities owned by participating entities (participation is voluntary) and assessing the
cyber security posture of the control systems that support the operation of these facilities.
NPCC will continue the physical security outreach program in 2015 (participation is also voluntary) and NPCC
staff will hold a Security Information Exchange session, which will include entity presentations, at the spring
and fall Compliance Workshops.
As part of the CIP Version 5 transition and consistent with NERC guidance, NPCC will perform CIP audits based
on the entity’s selected option for maintaining compliance with CIP standards during the Transition Period:
Continue to comply by maintaining a valid RBAM for Critical Asset identification
pursuant to CIP-002-3.
Option 1
For Responsible Entities that have already adopted the CIP V4 Critical Asset
Criteria (CIP-002-4, Attachment 1), use the CIP V4 Critical Asset Criteria in its
entirety, with the exception of criterion 1.4 (Blackstart Resources) and criterion
1.5 (Cranking Paths), to identify assets subject to the controls in CIP-003-3
through CIP-009-3.
Option 2
Use the CIP V5 “High” and “Medium” Impact Rating Criteria (CIP-002-5.1,
Attachment 1) to identify assets subject to the controls in the CIP V5 Standards.
Option 3
The on-site CIP Audits will be conducted as directed in the Guidance document. CIP Audits of those entities
that have not chosen to move to Version 5 (Options 1 and 2) will be audited to Version 3. If an entity indicates
that they have adopted CIP Version 5 (Option 3), NPCC will review their compliance with Version 5
Standards. In all cases, NPCC’s approach would be to perform a review of those Standards / Requirements
that are “mostly compatible” with the Version 5 Standards. Since Version 3 is enforceable until July 1, 2016,
no findings of non-compliance with Version 5 Standards will be issued. A non-public document will be issued
indicating any areas of concern where future compliance with version 5 may be in jeopardy.
Previously, off-site CIP audits had been conducted to verify that an entity does not have any Critical Cyber
Assets. In accordance with the recently released CIP Transition Guidance, there are no off-site CIP audits
scheduled in 2015. NPCC may include selected Spot Checks in place of the Off-site CIP Audits.
NPCC will be providing more details on the CIP approach to Compliance Monitoring in an upcoming Webinar
(date not yet determined) and at our Compliance Workshops.
1.2 Other Regional Key Initiatives & Activities
NPCC will continue to participate in the Risk Based Registration Advisory Group (RBRAG) which is charged with
the ERO-wide development of criteria for risk-based registration.
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Appendix A3 - Northeast Power Coordinating Council (NPCC) 2015 CMEP Implementation Plan for Entities within the U.S.
NPCC will continue to participate in the Reliability Assurance Initiative Advisory Group (RAIAG) which is
monitoring and ensuring the uniform ERO-wide implementation of RAI monitoring and enforcement activities.
NPCC will continue to participate in the RAI Program related to the Logging (Aggregation) of Minimal Risk
Issues. NPCC also expects to treat certain minimal risk violations as Compliance Exceptions.
NPCC will continue to be a member of the RAI Regional Entity Group (RAIRE), which is formulating the overall
RAI Training and ICE protocol and guidance documents.
NPCC supported all six Webinars associated with the NERC Compliance Auditors Handbook and ERO Checklist.
NPCC will continue to provide input to the NERC Manual Task Force (MTF) tasked with maintaining the
Auditors Handbook and enhancing Auditor Tools.
NPCC will continue to participate in the development of a program to implement CIP-014-1, Physical Security.
NPCC will continue to participate in the NERC CIP Version 5 Transition Guidance workgroup.
As part of the Events Analysis process, NPCC will continue to encourage registered entities to perform a
voluntary, systematic Compliance Analysis (CA) in response to all system events and disturbances. Registered
entities are also expected to share the CA with the RE for all Category 2 and above events.
2. Regional Risk Assessment Process
NPCC’s Regional Risk Assessment Process is a summary and compilation of specific parts of NPCC’s Entity
Inherent Risk Assessment process and NERC’s IRA Assessment Guide that takes into account the nine areas of
focus for 2015 consideration.
1. Infrastructure maintenance
2. Uncoordinated protection systems
3. Protection systems misoperations
4. Workforce capability
5. Monitoring and situational awareness
6. Long term planning and system analysis
7. Threats to cyber systems
8. Human error
9. Extreme physical events
NPCC’s Regional Risk Assessment Process includes the following:
2.1 Functional Registration Impact Profile
The Functional Registration Impact Profile is used to populate NPCC’s standards subject to Regional
monitoring. It considers the potential effect on the reliability of the Bulk Power System (BPS) based on NPCC’s
Regional perspective and registered entity’s functions. The following table shows the initial impact
classification of registered entities.
Assignment of Initial Functional Registration Impact
High Impact
Medium Impact
Low Impact
RC/BA
TO w/o BES facilities
GO/GOP under 200 MW
TOP
TO w/ BES facilities
GO /GOP over 500
MW
GO /GOP between 200 MW and 500 MW
DP peak load over 1000 MW
DP peak load under 1000 MW
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Appendix A3 - Northeast Power Coordinating Council (NPCC) 2015 CMEP Implementation Plan for Entities within the U.S.
2.2 NPCC Regional Compliance History
NPCC will examine the past compliance history of the entire Region. This will include an identification of the
Standards and Requirements that have been violated the most within the NPCC Region. It will examine past
audit performances, including the number and type of violations that were discovered through audits
compared with the number and type of violations that were discovered through self-reports or SelfCertifications. It will also incorporate any issues or problems that may have been identified that did not result
in a potential violation.
2.3 NPCC Regional Enforcement History Profile
NPCC will analyze violations to identify any trends regarding:
 Level of risk to the BPS (operational vs. documentation)
 Timeframes of violations (real time, next day, planning)
 Number of repeat violations
2.4 NPCC Overall Evaluation
Based on a registered entity’s function, NPCC will specifically examine impact and violations based on the
following:
 RC
 Qualifying IROL/SOL events
 Qualifying loss of load events
 BA
 DCS Performance (ACE or restoration of reserve)
 Qualifying IROL/SOL events
 Qualifying loss of load events
 TO/TOP
 Qualifying IROL/SOL events
 Protection System Misoperations
 Qualifying loss of load events
 GO
 Protection System Misoperations
3. Regional Risks and Associated Reliability Standards
The table below contains the Regional risk elements identified during the Regional Risk Assessment. The
table also contains associated Reliability Standards/Requirements to identified risks that may be considered
in the Regional compliance oversight plan.
Reliability Standards Subject to Regional Monitoring
Regional Risk Focus
Associated Standard &
Justification
Areas
Requirement(s)
Uncoordinated
NPCC identified three risk elements where it was PRC-002-NPCC-01
Protection Systems;
necessary to develop a Regional Standard to
Protection System
ensure that applicable entities had Disturbance
Misoperations;
Monitoring Equipment and capabilities to
Monitoring and
monitor and capture adequate disturbance data
Situational Awareness to facilitate Bulk Electric System event analyses.
Infrastructure
Basic capability required to manage reliability
FAC-003-3 R1,R2,R4,R5,R6,R7
Maintenance
during emergency conditions
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Appendix A3 - Northeast Power Coordinating Council (NPCC) 2015 CMEP Implementation Plan for Entities within the U.S.
Regional Risk Focus
Areas
Uncoordinated
Protection Systems
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
Basic capability required to manage reliability
PRC-006-1 R8,R9,R10
during emergency conditions
PRC-015-0 R1
NPCC reliability area of focus in 2015
Workforce Capability
NPCC reliability area of focus in 2015
Basic capability required to manage reliability
during emergency conditions
Process is critical to maintaining the power
system equipment capability/reliability
Monitoring and
Basic capability required to manage reliability
Situational Awareness during emergency conditions
Long Term Planning
and System Analysis
Human Error
Extreme Physical
Events
PRC-005-1.1b R1,R2
PRC-023-3 R1 to R6
IRO-005-3.1a R6,R7
TOP-002-2.1b
R5,R6,R7,R8,R10,R14
TOP-008-1 R1,R2,R3
TOP-007-0 R1 to R4
VAR-002-2b R1 to R3
BAL-001-1 R1 to R4
BAL-002-1 R1 to R6
BAL-003-0.1b R2,R3,R5
Conditions/equipment/capability to perform the
functions can change as technology changes
COM-001-1.1 R1,R2
NPCC reliability area of focus in 2015
IRO-005-3.1a R9,R12
IRO-009-1 R3
MOD-001-1a R2 to R5 and
R7 to R9
NPCC reliability area of focus in 2015
Basic capability required to manage reliability
during emergency conditions
Basic capability required to manage reliability
during emergency conditions
Basic capability required to manage reliability
during emergency conditions
MOD-029-1a R1 to R8
TPL-003-0b R1 to R3
PER-003-1 R2
EOP-001-2.1b R2,R6
EOP-002-3.1 R1,R3,R5
EOP-005-2 R2
4. Compliance Oversight Plan
The specific list of audited standards will be contained in the entity’s audit notification letter sent at least 90
days prior to the scheduled audit. The specific list of 2015 Self Certifications, applicable registered functions,
dates, and scheduled reporting dates will be posted on the NPCC website. The link to the Self Certification
Schedule
is:
https://www.npcc.org/Compliance/Compliance%20Reporting%20Schedules/Forms/Public%20List.aspx
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Appendix A3 - Northeast Power Coordinating Council (NPCC) 2015 CMEP Implementation Plan for Entities within the U.S.
NPCC will not audit Interchange Authorities, Load Serving Entities or Purchase-Selling Entities in 2015.
The audit schedule is also located on the NPCC’s website here:
https://www.npcc.org/Compliance/Audit%20Schedule/2015%20Preliminary%20Audit%20Schedule.pdf
Audits of Canadian Entities will be conducted in accordance with the appropriate agreements.
The following U.S. entities are scheduled for an audit in 2015:
NCR #
NCR00538
NCR11377
NCR11324
NCR07024
NCR07025
NCR07026
NCR07029
NCR00200
NCR04057
NCR07087
NCR07090
NCR11121
NCR07101
NCR07108
NCR07111
NCR00124
NCR07124
NCR07130
NCR11339
NCR00164
NCR07132
NCR07133
NCR11287
NCR00208
NCR07136
NCR07139
NCR07141
NCR07128
NCR07154
NCR07091
NCR07160
NCR10332
NCR07180
NCR07181
NCR11337
NCR11152
NCR00543
NCR00088
NCR07220
2015 Compliance Audit Plan
Registered Entity
Astoria Energy, LLC
Brayton Point Energy, LLC
Brookfield White Pine Hydro, LLC
Burlington Electric Department
Calpine Energy Services
Capitol District Energy Center Cogeneration Associates, JV
Central Maine Power Company
Dynegy Power, LLC
Exelon Generation Co., LLC (Power)
Flat Rock Windpower L.L.C.
Fortistar North Tonawanda
GenOn East 1
Granite Ridge Energy, LLC
Huntley Power LLC
Hydro-Quebec Production
Ipswich Municipal Light Department
ISO-NE
KIAC Partners
Lakeside New York LLC
Littleton Electric Light Department
Lockport Energy Associates
Long Island Power Authority
Marble River LLC
Marblehead Municipal Light Department
Mass. Municipal Wholesale Electric Company
MASSPOWER
Middletown Power LLC
National Grid Generation LLC
New Athens Generating Company, LLC
New Hampshire Transmission, LLC
New York Independent System Operator
NextEra Energy Resources, LLC
NSTAR Electric Company
NYSEG
ReEnergy Black River
Tanner Street Generation, LLC
TC Ravenswood LLC
TC Ravenswood Services Corp.
TransCanada Hydro Northeast Inc
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Appendix A3 - Northeast Power Coordinating Council (NPCC) 2015 CMEP Implementation Plan for Entities within the U.S.
NCR #
NCR07228
5.
2015 Compliance Audit Plan
Registered Entity
Vermont Transco, LLC
Compliance Outreach
Compliance Outreach Activities
Outreach Activity
Anticipated Date
2015 workshop dates:
NPCC utilizes its semi-annual workshops as a primary mechanism for outreach to its
registered entities. An Introduction to NPCC presentation is included at each workshop. May 19-21 and Nov 1719.
NPCC conducts webinars open to all NPCC registered entities on an as needed basis. It
also posts webinar question-and-answer documents as appropriate. NPCC responds to
individual requests from registered entities, but if an individual concern can be applied
to all registered entities, NPCC will post a Compliance Guidance Statement or
clarification to address that concern.
NPCC conducts surveys of its registered entities as needed to acquire registration data,
BES element data, workshop content preferences, etc.
NPCC hosts monthly Compliance Committee meetings to disseminate the latest
information regarding the compliance program to industry stakeholders.
In 2013, NPCC implemented a Physical Security Outreach Program. Under this
continuing program, NPCC physical security subject matter experts perform voluntary
physical security assessments for certain registered entities.
NPCC developed a Cyber Security Outreach Program that began in 2014 and will
continue in 2015.
In 2015, NPCC will institute a CIP Version 5 transition outreach program.
NPCC developed an internal entity guide to assist registered entities in meeting
quarterly reporting requirements pursuant to PRC-004 and NERC ALR4-1.
The NPCC website includes links associated with the areas of Standards, Registration,
Compliance Monitoring, and Enforcement.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst)
2015 CMEP Implementation Plan
This Appendix contains the CMEP Implementation Plan (IP) for ReliabilityFirst as required by the NERC Rules of
Procedure.
1. Compliance Monitoring and Enforcement
1.1 CMEP IP Highlights and Material Changes
ReliabilityFirst will follow and implement the ERO Risk-based Compliance Oversight Framework described in
the ERO CMEP IP. The 2015 ERO CMEP Implementation Plan identifies a number of risk elements and areas
of focus, which provide a starting point for ReliabilityFirst’s risk analysis and Compliance Oversight Plan.
However, the plan recognizes that it does not containcomplete set of the risks that may affect the BPS, and
that Regional Entities are expected to consider local risks and the specific circumstances associated with
individual registered entities within their footprint when developing their compliance oversight plans.
As such, ReliabilityFirst performed its Regional Risk Assessment (RRA), which identified areas of focus specific
to the ReliabilityFirst region (ReliabilityFirst areas of focus), set forth in Section 3 of this document.
ReliabilityFirst may monitor the Reliability Standards (Standards) and Requirements associated with the
ReliabilityFirst risk elements in 2015. ReliabilityFirst has the discretion to add, subtract, or modify Standards
and Requirements as it deems necessary based on the individual Inherent Risk Assessments (IRA).14 The
ReliabilityFirst RRA is discussed in further detail in Section 2 of this document.
CMEP Implementation Plan Updates and Changes throughout the Year
ReliabilityFirst monitors FERC and NERC activities, system events, and events in the ReliabilityFirst region.
Based on these monitoring activities, ReliabilityFirst may modify its CMEP Implementation Plan throughout
the year to include Standards that address and mitigate situational awareness and reliability issues as they
arise.
1.2 Other Regional Key Initiatives & Activities
Risk-based Enforcement
ReliabilityFirst is implementing a risk based enforcement approach consistent with that of the ERO Enterprise.
Specifically, ReliabilityFirst will be exercising enforcement discretion by processing qualified minimal risk
issues as “compliance exceptions.” Compliance Exceptions will effectively supersede the Find, Fix, Track and
Report (“FFT”) disposition method for most minimal risk noncompliances.
Self-Logging
ReliabilityFirst is implementing self-logging approach consistent with that of the ERO Enterprise. Self-logging
allows qualified registered entities to keep a log of minimal risk noncompliances that is periodically checked
by ReliabilityFirst instead of submitting individual self-reports and corresponding mitigation plans for each
noncompliance. Once ReliabilityFirst approves the log entries, they are processed as compliance exceptions.
2. Regional Risk Assessment Process
The RRA identifies risks within the ReliabilityFirst region that could potentially impact the reliability of the BPS.
To accomplish the RRA, ReliabilityFirst utilizes a cross-functional team of internal Subject Matter Experts (the
RRA Team) to review and analyze information and data to determine the highest-priority risks to the
ReliabilityFirst region. The types of region-specific information and data the RRA Team reviews includes: US
Population & Census Data, Severe Weather Related Outages (e.g., OE-417 reports, Outages), Generation
14
Additionally, ReliabilityFirst audit teams have the discretion to adjust audit scope during an engagement at a
registered entity.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Availability Data System (GADs), Transmissions Availability Data System (TADS), Misoperations, Event Analysis,
Load Analysis, Locational Marginal Pricing, System Operating Limits (SOL), Interconnection Reliability
Operating Limits (IROL), TIER Power Line Ranking, Interconnection Points, Cyber Security data, Physical
Security data, and data on Threats and Vulnerabilities. After a period of information gathering, analysis and
decision making, the RRA team develops the results of the RRA in the form of ReliabilityFirst risk elements.
The 2014 ReliabilityFirst RRA identified the following five ReliabilityFirst risk elements (in no particular order
or ranking):
 Weather Related
 Physical Threat
 Cyber Security
 Human Error
 Equipment Failure
The five ReliabilityFirst risk elements align with five of the nine NERC risk elements discussed in the 2015 ERO
CMEP Implementation Plan:
 Infrastructure Maintenance
 Workforce Capability
 Threats to Cyber Systems
 Human Error
 Extreme Physical Events
ReliabilityFirst believes that the four NERC risk elements that do not align with ReliabilityFirst risk elements,
set forth below, are best assessed at the registered entity level during the Inherent Risk Assessment
(ReliabilityFirst’s Entity Risk Assessment):
 Uncoordinated Protection Systems
 Protection System Misoperations
 Monitoring and Situational Awareness
 Long Term Planning and System Analysis
Section 3 of this document contains additional detail on the five ReliabilityFirst risk elements and their
Reliability Standards and Requirements, which ReliabilityFirst may include in the 2015 ReliabilityFirst
Compliance Oversight Plans.
The RRA is performed annually and will be updated as necessary. As new and emerging threats and risks are
identified, system events take place, and compliance monitoring activities are performed, ReliabilityFirst will
update the RRA to keep current with potential issues, threats and risks.
ReliabilityFirst reviews potential risks posed by an individual registered entity to the reliability of the BPS, by
utilizing the IRA – Inherent Risk Assessment guide developed as part of the RAI Initiative. This assessment
helps identify areas of focus and the level of compliance oversight required. Reliability Standards and
Requirements may be added to or removed from the scope of an audit. Going forward, ReliabilityFirst will
perform risk assessment prior to each audit, and at least two weeks prior to the development of a registered
entity’s audit notification package.
In additional to the risk elements and focus areas identified in the RRA, ReliabilityFirst identified Regionspecific risk factors that it will consider when evaluating a registered entity. The items below provide Regionspecific details on additional risk areas that ReliabilityFirst may consider when identifying and assessing risk.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan

Population and geographic location – The ReliabilityFirst region includes three of the most populated
areas in the United States (Chicago, Philadelphia, and Washington DC). The ReliabilityFirst region also
contains many medium-sized urban areas such as Baltimore, Cleveland, Pittsburgh, Indianapolis,
Cincinnati, and Toledo. Maintaining and ensuring reliable service to these areas of the country is critical
to the overall well-being of the nation and national security. Any registered entity serving the load in
these areas and those registered entities responsible for operating and maintaining reliability of the BPS
supplying these areas, or in close proximity to these populated areas, may pose a higher risk.

Entity Make-up and diversity – The ReliabilityFirst region is a summer peaking region, with several
registered entities serving peak loads or operating an individual resource in excess of 500 MWs.
Maintaining and ensuring reliable service to these areas of the country is critical to the well-being of the
people and in some cases to national security.

Entity Registration – ReliabilityFirst takes into account Entity Registration (i.e. RC, BA, TOP versus DP,
PSE), during the assessment of registered entities. RCs, BAs and TOPs have the authority to issue
operating orders, instructions, and directives and ultimately play a larger role in safeguarding the
reliability of the BES.

Transmission Assets – The transmission network in the ReliabilityFirst region consists of 765kV; 500kV;
345kV; 230kV; 138kV and 115kV lines. The majority of transmission facilities are overhead, with large
urban areas serviced by underground transmission cables. Overall asset ownership (lines, transformers,
generators, voltage, size of units, fuel type, flowgates, SOL, IROL, etc.) are also considered as part of the
assessment. These assets form the backbone of the system and will be assessed with a higher risk due
to their importance to maintain the reliability of the BPS. A registered entity that owns these types of
facilities may have their audit scope adjusted to address owning and maintaining these types of
equipment.

Misoperations – the number of misoperations within the ReliabilityFirst region has been an issue of
focus over the last few years. There is a higher risk to the BPS if the cause for a misoperation is due to
controllable circumstances. Registered entities having these types of misoperations may have their
audit scope adjusted to address resolving these misoperations.

Special Protection Schemes and Relay Protection – registered entities in the ReliabilityFirst region use
special protection schemes to mitigate system constraints until transmission reinforcements can be
planned and built. In some cases these special protection schemes are left in place indefinitely. Special
protection schemes can present a higher risk to the BPS when they are not properly implemented,
coordinated, or operated as intended.

Emergency Operations and Blackstart Facilities – There are multiple facilities designated as blackstart
units in the ReliabilityFirst region. Registered entities are required to regularly test these blackstart
units and submit results to ReliabilityFirst annually. There is a potential risk that there may be
insufficient blackstart resources designated for an area, or that blackstart resources may not be
available if they are not properly tested.

Generation Assets – ReliabilityFirst generation mix is made up of units that are nuclear, coal, gas, hydro,
wind, solar, and refuse power assets. The asset mix for the next few years is expected to change, with a
decrease in coal generation and an increase in renewable resources such as wind generation and solar
generation. There is a risk that generating capacity and available resources may not be available to
meet demand on a real-time, near term and long term time horizon. Registered entities owning these
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
resources may be subject to standards and requirements to ensure availability and proper maintenance
of these resources is retained.

EMS and Monitoring Tools Availability – Keeping monitoring tools available and operational for system
operators’ use is imperative to maintaining a reliable grid. Registered entities with these types of
monitoring tools may have additional Standards and Requirements in their audit scope to ensure these
monitoring tools are maintained and available to the system operator.
The non-physical characteristics considered by ReliabilityFirst during the IRA include the following:

Operating Performance – ReliabilityFirst analyzes data from the GADS, TADS reports and information from
reviewed system events. Since 2008 there have been various system events ranging from local load drop
to interconnection frequency excursions. There is always a risk that an event could cause a large scale
blackout, but it is more probable that a series of smaller events will occur and if undetected, will manifest
into a larger event. This information can help to pinpoint problems or identify trends for a registered
entity and help to focus the scope of an audit to deter future events from occurring.

Compliance History – Assessing the violation history, audit performance, Self-Certification, and self-report
performance indicates past performance trends and a registered entity’s behavior towards compliance
and their implementation of their compliance programs. Registered entities with a history of compliance
issues may have their audit scope adjusted to ensure their mitigating measures achieve full compliance
and prevent recurrence.

Normal System Performance – The flow of power across the ReliabilityFirst region is normally from west
to east, to supply the beltway of the mid-Atlantic region and northeast (including the New York City Area).
There are instances when this normal power flow is disrupted and system constraints are realized. These
system constraints rely on operator intervention for resolution. A registered entity’s system events
(involvement, impact to BPS, significance, availability of operators tools, EMS, etc.), their operational
performance (use of Emergency procedures and why), and their overall situational awareness all play a
role in their system performance.

System Maintenance upkeep and replacement (EMS, Physical plant, age of equipment, record keeping,
tracking, and overall program) Continued maintenance of equipment is essential to a reliable BPS. As
equipment gets older, system maintenance may increase and facility availability may decrease.
Additionally, where ReliabilityFirst has confidence in a registered entity’s internal compliance program as a
result of an Internal Control Evaluation (ICE), ReliabilityFirst may narrow the audit scope and audit periodicity
to reflect the compliance maturity of the registered entity. To support a strong culture of compliance and to
demonstrate robust internal controls, registered entities are encouraged to continually perform selfassessments of their compliance program and internal controls on an ongoing basis.
ReliabilityFirst will notify registered entities of the Reliability Standards and Requirements to which they will
be monitored against through the posting of the CMS for Self-Certification and Data Submittals, the
Compliance Monthly Update Letter, the audit notification packages, as well as any of the outreach programs
listed in Section 5 of this document.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
3. Regional Risks and Associated Reliability Standards
The table below contains the ReliabilityFirst risk focus areas identified during the ReliabilityFirst RRA. The
table also contains the Reliability Standards and Requirements associated with each risk element.
NOTE: Standards and/or Requirements in BLUE denote inclusion within the NERC risk elements identified in
the 2015 ERO CMEP IP.
Regional Risk
Focus Areas
Weather Related
(Aligns with ERO
risk element:
Extreme Physical
Events)
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
As a result of ReliabilityFirst’s review of the NERC risk EOP-001-2.1b R4
elements and the ReliabilityFirst risk elements,
TOP-001-1a R5
ReliabilityFirst identifies these Standards and
TOP-001-1a R4
Requirements for compliance monitoring focus in
PER-005-1, R1.1.1
2015.
Weather Related
(Aligns with ERO
risk element:
Extreme Physical
Events)
2014 Cold Weather Event: As a result of this event,
there is a need to: (1) determine that entities
investigate a process for unit testing and preparation
of resources in advance of winter operations,
including testing dual-fuel capability, (2) review
operator communications with respect to fuel-limited
generation commitment decisions for accuracy and
consistency, (3) changes to allow adjustment of start
times based on changes in fuel utilized, (4)
requirements for generation units whose primary fuel
may not be natural gas but that require gas to
operate, (5) review the entities emergency procedures
to ensure overall communications and coordination of
emergency procedures, (6) ensure transmission
owners understand their existing voltage reduction
capabilities (amount, time frame, etc.), (7) have the
entities consider adjustments to the roles and
responsibilities for communications during emergency
procedures besides refining the training to reinforce
processes and tools.
As a result of ReliabilityFirst’s review of the NERC risk TOP-005-2a R2
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
Weather Related
Attachment 1-TOP-005 lists the types of data that BAs
and TOPs are expected to share with other BAs and
TOPs. Item 2. Other operating information updated as
soon as available. Item 2.8. Severe weather, fire, or
earthquake. There is a continual need to ensure that
the conditions of Item 2.8 are met per R2.
As a result of ReliabilityFirst’s review of the NERC risk EOP-003-2 R1,R3,R5,R8
elements and the ReliabilityFirst risk elements,
TOP-002-2.1b R5,R6,R7
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Regional Risk
Focus Areas
(Aligns with ERO
risk element:
Extreme Physical
Events)
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
2013 Hot Weather Event. Several days of unusual,
extremely hot weather led to emergency conditions in
an RC service area. In order to avoid more serious
impacts, the RC had to direct transmission owners to
implement controlled outages in a few contained
areas for limited time periods. Controlled outages
such as these are a last resort to prevent uncontrolled
blackouts over larger areas (SEE EOP-003-2, R1, R3, R5
& R8).
Weather Related
(Aligns with ERO
risk element:
Extreme Physical
Events)
During this period, temperatures were approximately
20 degrees above normal, and demand for electricity
reached an all-time high. At the same time, some
generation and transmission facilities were scheduled
out of service for routine maintenance because lower
system demand was usually experienced during this
period (SEE TOP-002-2.1b, R5, R6 & R7).
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
BAL-005-0.2b R7
COM-001-1.1 R3,R5
EOP-001-2.1b R4
EOP-005-2 R1, R1.2
NUC-001-2.1 R7,R8,R9.4,R9.4.13
2012 Hurricane Sandy Event. Some TO/DP entities in TOP-001-1a R4,R5
the RTO, particularly those that were not on the coast, TOP-002-2.1b R7
experienced greater damage in other storms, such as
the 2012 Derecho storm. However, the damage that
others experienced from Hurricane Sandy exceeded
that caused by both Hurricane Irene and the Derecho
storm. In fact, one entity reported that Sandy was the
most damaging storm to them since record keeping
began. For one entity, all service areas were impacted.
The majority of increased staffing was in the
restoration area. Additional areas that received
increased staffing were operations centers, primary
control centers, and backup control centers.
1. A large NPGOP had only one nuclear station that
was damaged due to the loss of transmission system
load and experienced high voltage. Another nuclear
facility had a temporary loss of off-site power due to
switchyard damage and a bushing on a voltage
regulator associated with a transformer. During loss
of off-site power at this facility, the reactor shutdown
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Regional Risk
Focus Areas
Weather Related
(Aligns with ERO
risk element:
Extreme Physical
Events)
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
cooling and spent fuel cooling was temporarily lost
but was restored when emergency diesels started and
loaded. Fossil units were forced off both pre-storm (in
anticipation of potential flooding) and as the stations
flooded.
2. Five potential lessons learned were identified for
generation stations during the storm:
 ISOs/RCs need to improve communication with
generation plants during major events.
 ISOs/RCs should develop or document alternate
communications methods when normal methods
are lost.
 More comprehensive weather preparation
procedures need to be developed.
 Improvements can be made for managing
personnel who remain on-site.
 Development of anticipated generation
reductions is necessary for the loss of one or more
nearby transmission elements.
3. Several generation operation risks were identified
during the storm. These include:
 Increased potential for Loss of Off-site Power
(LOOP) to nuclear facilities.
 Possibility of LOOP due to switchyard damage, or
loss of normal condenser cooling and loss of
availability of service water due to high water.
 Curtailments due to wet coal, which is normal
with any significant precipitator.
 Potential lack of fuel due to damage to the fuel
provider’s facilities.
4. The largest challenge for the BA was coordinating
load lost on the distribution systems with lost
generation—in particular, the loss of entire generating
stations or the loss of multiple units within close
temporal proximity. This at times forced ACE to go
either high or low for extended periods of time. It was
also challenging to maintain load/generation balance
during restoration as generation and/or load was
added back into the system.
As a result of ReliabilityFirst’s review of the NERC risk EOP-005-2 R6, R9
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
EOP-005-2, R6 & R9: A large TOP has not been audited
for these requirements.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Regional Risk
Focus Areas
Weather Related
(Aligns with ERO
risk element:
Extreme Physical
Events)
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
As a result of ReliabilityFirst’s review of the NERC risk EOP-006-2 R1
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
Weather Related
(Aligns with ERO
risk element:
Extreme Physical
Events)
EOP-006-2, R1: The two RCs have not been audited for
this requirement.
As a result of ReliabilityFirst’s review of the NERC risk EOP-010-1 R1,R3 (as of 4/1/15)
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
EOP-010, R1 & R3: Although the results of a GMD are
reported under EOP-004-2, means of detection and
correction for these types of events will eventually fall
under EOP-010 which was recently approved by FERC
in June 2014, but has no enforcement date at this
time. GMDs are confined to a small eastern portion of
PJM. MISO is not significantly impacted by GMDs.
PJM addresses GMDs in their Emergency Procedures
Manual.
Weather Related
(Aligns with ERO
risk element:
Extreme Physical
Events)
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
Weather Related
(Aligns with ERO
risk element:
Extreme Physical
Events)
TPL-002-0b, 003-0b & 004.0a: TPs have not been
audited for this requirement since 2009 and 2010.
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
TPL-002-0b R1
TPL-003-0b R1
TPL-004-0a R1
EOP-001-2.1b R1,R2,R3,R4,R6
EOP-002-3.1 R1,R2,R3,R4,R5
EOP-003-2 R1,R3,R7,R8
EOP-004-2 R2
IRO-003-2 R1,R2
IRO-004-2 R1
IRO-005-3.1a R5,R6,R9
PRC-006-1
R1,R2,R3,R4,R5,R9,R10
PRC-022-1 R1
TOP-006-2 R2,R6,R7
TOP-007-0 R1,R2,R3,R4
TOP-008-1 R1,R2,R3,R4
TPL-001-4 R1, R7 (as of 1/1/15)
TPL-002-0b R1
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Physical Threat
(Aligns with ERO
risk element:
Extreme Physical
Events)
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
TPL-003-0b R1
TPL-004-0a R1
VAR-002-2b R2,R3 (v3 as of
10/1/14)
As a result of ReliabilityFirst’s review of the NERC risk CIP-006-3c
elements and the ReliabilityFirst risk elements,
R1,R2,R3,R4,R5,R6,R7,R8
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
Cyber Security
(Aligns with ERO
risk element:
Threats to Cyber
Systems)
In CIP-006-3, failure to comply with the requirements
of this standard can lead to threats in cyber and
physical security space.
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
Regional Risk
Focus Areas
Human Error
(Aligns with ERO
risk element:
Human Error &
Workforce
Capability)
Human Error
(Aligns with ERO
risk element:
Human Error &
Workforce
Capability)
Access control is defined by CIP-004-3a, R4.
In CIP-005-3a, CIP-006-3c & CIP-007-3a, failure to
comply with the requirements of these standards can
lead to threats in cyber and physical security space.
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
A medium size entity had an established procedure
that required a series of communications in advance
of energizing new equipment to assure ratings
information is timely updated. It was determined that
procedure was not strictly followed for two projects
and resulted in a communication gap between the
project team and the groups responsible for updating
and communicating the facility ratings.
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
CIP-004-3a R4
CIP-005-3a R1,R2,R3,R4,R5
CIP-006-3c
R1,R2,R3,R4,R5,R6,R7,R8
CIP-007-3a
R1,R2,R3,R4,R5,R6,R7,R8,R9
FAC-008-3 R8
IRO-010-1a R3
Due to reconfiguration at a substation for breaker
installation and relay replacement by a TO, a line
outage resulted in disabling of the primary and backup
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Regional Risk
Focus Areas
Human Error
(Aligns with ERO
risk element:
Human Error &
Workforce
Capability)
Human Error
(Aligns with ERO
risk element:
Human Error &
Workforce
Capability)
Human Error
(Aligns with ERO
risk element:
Human Error &
Workforce
Capability)
Human Error
(Aligns with ERO
risk element:
Human Error &
Workforce
Capability)
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
protection on an energized bus. The implications of
removing the 138 kV line facilities and the change in
protection status of the bus was not recognized by
field personnel. As a result, the system operator was
not informed of the disabling of bus protection during
the outage resulting in this information not being
communicated to the RC.
As a result of ReliabilityFirst’s review of the NERC risk PRC-005-1.1b R3 (v2 as of
elements and the ReliabilityFirst risk elements,
4/1/15)
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
An oversight in an medium size entity's Generator
Protection System Maintenance and Testing Program
which required testing of relays that were changed,
their associated control circuitry paths, as well as all of
the other input paths of the associated lockout relays
resulted in these devices not being tested.
As a result of ReliabilityFirst’s review of the NERC risk PRC-023-2 R2 (v3 as of 10/1/14)
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
A large entity's Out-of-Step Blocking (OSB) Relay
Loadability Spreadsheet contained an error in the
formula used to calculate certain OSB relay loadability
values.
As a result of ReliabilityFirst’s review of the NERC risk TOP-004-2 R4
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
A large registered entity recently failed to recognize
they had entered an unknown operating state when
extremely low substation battery voltage was
intermittently occurring which compromised the relay
protection at the substation.
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Regional Risk
Focus Areas
Human Error
(Aligns with ERO
risk element:
Human Error &
Workforce
Capability)
Human Error
(Aligns with ERO
risk element:
Human Error &
Workforce
Capability)
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
A small GOP identified that they had exceeded their
VAR-002-2b R2 (v3 as of
voltage schedule without making notification to the
10/1/14)
TOP. It was determined that the Control Room
Operator failed to recognize the elevated voltage
condition in spite of received alarms, operator aids,
and training. Another small GOP was unaware of their
obligation to notify the TOP when their assigned
voltage schedule could not be met.
Following a planned outage, a Power System Stabilizer
(PSS) status change was not reported within the
required 30 minutes. The exciter went through a
control upgrade during the outage and during the
course of the project, the PSS was disabled. The cause
was determined to be an oversight of the operator
due to not verifying the PSS was in service during start
up due to past routine sequence. A large GOP on
numerous occasions, exceeded their voltage
schedules at various generating facilities due to lack of
operator situation awareness of the AVR status.
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
In CIP-002-3 - CIP-009-3, there is a possibility of
Human Error associated with any of the requirements
in these standards.
Equipment Failure
(Aligns with ERO
risk element:
Infrastructure
Maintenance)
As a result of ReliabilityFirst’s review of the NERC risk
elements and the ReliabilityFirst risk elements,
ReliabilityFirst identifies these Standards and
Requirements for compliance monitoring focus in
2015.
VAR-002-2b R3, R3.1 (v3 as of
10/1/14)
CIP-004-3a R1,R2
COM-002-2 R2
EOP-001-2.1b R2,R3,R4
EOP-003-2 R8
EOP-005-2 R10,R11,R17
EOP-006-2 R9,R10
PER-005-1 R3
CIP-002-3 R1,R2,R3, R4
CIP-003-3 R1,R2,R4,R5,R6
CIP-004-3a R1,R2,R3,R4
CIP-005-3a R1,R2,R3,R4,R5
CIP-006-3c
R1,R2,R3,R4,R5,R6,R7,R8
CIP-007-3a
R1,R2,R3,R4,R5,R6,R7,R8,R9
CIP-008-3 R1,R2
CIP-009-3 R1,R2,R3,R4,R5
BAL-006-2 R4.3
Per the Compliance Monitoring Section of this
standard, Each BA shall perform an Area Interchange
Error (AIE) Survey as requested by the NERC Operating
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
Committee to determine the BA’s Interchange error(s)
due to *equipment failures or improper scheduling
operations, or improper AGC performance.
Note: *ReliabilityFirst wishes to determine if the
number of equipment failures that impact AIE is
presently known.
Equipment Failure As a result of ReliabilityFirst’s review of the NERC risk PRC-001-1.1 R2, R2.2
(Aligns with ERO elements and the ReliabilityFirst risk elements,
risk element:
ReliabilityFirst identifies these Standards and
Infrastructure
Requirements for compliance monitoring focus in
Maintenance)
2015.
Regional Risk
Focus Areas
During relay testing, a large registered entity recently
failed to report a relay failure which would not initiate
a breaker trip and thus reduced system reliability for
twelve days. The equipment failure and reduced
reliability was not reported to the respective entities.
It is also believed that this entity had entered an
unknown operating state per TOP-004-2, R4.
Equipment Failure As a result of ReliabilityFirst’s review of the NERC risk TOP-004-2 R4
(Aligns with ERO elements and the ReliabilityFirst risk elements,
risk element:
ReliabilityFirst identifies these Standards and
Infrastructure
Requirements for compliance monitoring focus in
Maintenance)
2015.
A large registered entity recently failed to recognize
they had entered an unknown operating state when
extremely low substation battery voltage was
intermittently occurring which comprised the relay
protection at the substation. The condition was not
studied or analyzed to determine any possible impacts
to the reliability of the BES.
Equipment Failure As a result of ReliabilityFirst’s review of the NERC risk
(Aligns with ERO elements and the ReliabilityFirst risk elements,
risk element:
ReliabilityFirst identifies these Standards and
Infrastructure
Requirements for compliance monitoring focus in
Maintenance)
2015.
A medium-size entity experienced an ECS failure
TOP-006-2 R1
which resulted in loss of monitoring and control
capabilities due to failure of their front-end
processors. It's RC and neighboring TOPs were only
able to monitor the tie-lines. During an ECS outage
TOP-006-2 R2
while the TOCC asked neighboring TOPs to monitor tie
lines, the TOCC could not monitor the applicable
transmission line status, real and reactive power
flows, voltage, and status of rotating and static
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Reliability Standards Subject to Regional Monitoring
Associated Standard &
Justification
Requirement(s)
reactive resources. Also, the TOCC did not have
control to operate the system during the ECS outage
Equipment Failure As a result of ReliabilityFirst’s review of the NERC risk FAC-003 R1,R2,R3,R4,R5,R6,R7
(Aligns with ERO elements and the ReliabilityFirst risk elements,
PRC-005-1.1b R3,R4 (v2 as of
risk element:
ReliabilityFirst identifies these Standards and
4/1/15)
Infrastructure
Requirements for compliance monitoring focus in
PRC-008-0 R1,R2
Maintenance)
2015.
PRC-011-0 R1
PRC-017-0 R1
Equipment Failure As a result of ReliabilityFirst’s review of the NERC risk CIP-008-3 R1
(Aligns with ERO elements and the ReliabilityFirst risk elements,
risk element:
ReliabilityFirst identifies these Standards and
Infrastructure
Requirements for compliance monitoring focus in
Maintenance)
2015.
Regional Risk
Focus Areas
CIP-008-3 requires an Incident Response Plan for
Critical Cyber Assets. Lack of such a plan, in the event
of an incident, will leave the entity with the inability to
properly respond to the incident.
Equipment Failure As a result of ReliabilityFirst’s review of the NERC risk CIP-009-3 R1,R2,R3,R4,R5
(Aligns with ERO elements and the ReliabilityFirst risk elements,
risk element:
ReliabilityFirst identifies these Standards and
Infrastructure
Requirements for compliance monitoring focus in
Maintenance)
2015.
CIP-009-3 requires a recovery plan for Critical Cyber
Assets. Lack of such a plan, in the event of equipment
failure, will leave the entity with the inability to
properly recover from an event.
4. Compliance Oversight Plan
Self-Certifications and Spot Checks
ReliabilityFirst will require Self-Certifications by all registered entities, including those that will be audited in
2015. ReliabilityFirst will require all Self-Certifications to be completed on a Requirement-level basis.
ReliabilityFirst will publish a list of the Standards and Requirements to which registered entities must selfcertify in the ReliabilityFirst 2015 Compliance Monitoring schedule.
ReliabilityFirst presently has no Spot Checks scheduled for 2015, but reserves the option to initiate Spot
Checks throughout the year as needed.15 In addition, ReliabilityFirst may use the Spot Check process to verify
mitigation plans as needed.
Compliance Monitoring Schedule for Self-Certifications and Data Submittals
ReliabilityFirst developed a Compliance Monitoring Schedule (CMS) that contains the Standards and
Requirements for the Self-Certifications and Data Submittals scheduled for 2015. The CMS is based upon the
NERC risk elements set forth in the NERC 2015 ERO CMEP Implementation Plan and the ReliabilityFirst risk
15
As part of its oversight of the PJM Local Control Centers, ReliabilityFirst conducts one random spot-check of a Local Control Center each
year.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
elements set forth in Section 3 below. Several Requirements in the CMS include a data submittal. Most of
these data submittals are associated with the monthly, quarterly, and or annual reporting requirements set
forth in the Requirements.
CIP Self-Certifications and Data Submittals in Lieu of CIP Audits for Registered Entities with no Critical Assets
or Critical Cyber Assets
For registered entities subject to the CIP Standards that own no Critical Assets or Critical Cyber Assets,
ReliabilityFirst will perform Self-Certifications and data submittals in lieu of conducting an off-site audit. This
determination is based upon NERC’s Cyber Security Reliability Standards CIP V5 Transition Guidance which
states:
For those Responsible Entities that do not have any Critical Assets or Critical Cyber Assets under the CIP
V3 Standards…Regional Entities will forgo off-site audits of the CIP Reliability Standards during the
Transition Period. Regional Entities may instead use compliance monitoring methods, such as Spot
Checks, Self-Certifications, among others.16
Compliance Monitoring of Purchase-Selling Entity (PSEs)
For registered entities registered for the PSE function, ReliabilityFirst will perform Self-Certifications in lieu of
conducting an audit, as their ERAs indicate the need. These Self-Certifications will apply to registered entities
that are registered for multiple functions in addition to the PSE function (e.g., if a registered entity is registered
as a DP, LSE and PSE, the audit scope will only include Standards and Requirements applicable to the DP and
LSE functions, and the registered entity will submit Self-Certifications for the Standards and Requirements
applicable to the PSE function). This determination is based on ReliabilityFirst’s experience to date and will be
reevaluated in future Implementation Plans as needed.17 PSEs are obligated to maintain compliance with
applicable Reliability Standards at all times.18
Monitoring of New or Revised Standards
ReliabilityFirst will monitor new or revised Standards based upon their implementation plans and as required
by NERC and FERC. A list of new and revised Standards and their effective dates is set forth below:
Standards Subject to Monitoring in late 2014
Standard
Effective Date
INT-004-3
10-1-2014
INT-006-4
10-1-2014
INT-009-2
10-1-2014
INT-010-2
10-1-2014
INT-011-1
10-1-2014
PRC-023-3
10-1-2014
PRC-025-1
10-1-2014
VAR-001-4
10-1-2014
VAR-002-3
10-1-2014
16
NERC Cyber Security Reliability Standards CIP V5 Transition Guidance, Section 5, page 7, http://www.nerc.com/pa/CI/Documents/V3V5%20Transition%20Guidance%20FINAL.pdf.
17 If the Risk-Based Registration Initiative becomes effective prior to 2015 or ReliabilityFirst otherwise identifies a need to change this
approach, ReliabilityFirst will update the Implementation Plan as appropriate.
18
It should be noted that if the Risk Based Registration initiative becomes effective, there is the possibility that the PSE function may be
removed and ReliabilityFirst will no longer require these self-certifications.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Standards Subject to Monitoring in 2015
Standard
Effective Date
BAL-003-1
4-1-2015
EOP-010-1
4-1-2015
MOD-032-1
7-1-2015
PRC-005-2
4-1-2015
TPL-001-4
1-1-2015
The audit schedule will not be posted on the ReliabilityFirst website. If an entity has a question concerning its
audit, please contact ReliabilityFirst.19
NCR #
NCR08039
NCR00680
NCR08077
NCR08034
NCR08053
NCR00941
NCR00761
NCR08001
NCR00711
NCR00748
NCR08019
NCR10257
NCR00417
NCR08013
NCR00917
NCR11235
NCR00896
NCR00822
NCR11097
NCR00721
NCR11247
NCR11297
NCR00794
NCR00954
NCR11380
2015 Compliance Audit Schedule
Registered Entity
Allegheny Ridge Wind Farm, LLC
American Bituminous Power Partners, L.P.
Wheelabrator Falls Inc.
US Operating Services Company - Chambers
Hancock-Wood Electric Cooperative, Inc.
Washington City Light & Power
Duke Energy Ohio/Kentucky PJM
Bryan Municipal Utilities
City of Batavia Municipal Electric Utility
The Dayton Power and Light Company
East Coast Power Linden Holding LLC
EFS Parlin Holdings LLC
Whiting Clean Energy, Inc.
Commonwealth Edison Company
Southern Indiana Gas & Electric Company d/b/a Vectren Energy
Delivery of Indiana, Inc.
Gratiot County Wind LLC
Public Service Electric & Gas Company
Michigan Public Power Agency
TAQA Gen X LLC
City of Rochelle
GSG 6, LLC
Homer City Generation, L.P.
Hoosier Energy REC, Inc.
Wolverine Power Supply Cooperative, Inc.
Kincaid Generation, LLC
19
As mentioned above, for registered entities where the CIP Standards apply, that have declared that they own no Critical Assets (CAs) or
Critical Cyber Assets (CCAs), ReliabilityFirst will perform self-certifications and data submittals in lieu of conducting an off-site audit. This
determination is based upon Cyber Security Reliability Standards CIP V5 Transition Guidance provided by NERC.
For those registered entities that are also registered for functions that are audited on a six year cycle, ReliabilityFirst will evaluate and
determine the scope of those registered entity audits based upon the risk those functions pose to the BES (i.e. a TOP that is also registered
as a LSE, etc.). There may be times when these audits are not conducted based upon the registered entity ERA.
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Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
NCR #
NCR08026
NCR00337
NCR00889
NCR00884
NCR00940
NCR00006/NCR04026/NCR05055
NCR07025/NCR01189/NCR00007/
NCR10115
NCR10208
NCR00682/NCR01056
NCR03044
NCR00761
NCR00936
NCR00826
NCR00688
NCR00752
NCR00881
2015 Compliance Audit Schedule
Registered Entity
PECO Energy Company
Troy Energy, LLC
PPL Susquehanna, L.L.C.
PPL Electric Utilities Corporation
Wabash Valley Power Association, Inc.
Calpine Corporation
Calpine Energy Services
Lincoln Generating Facility, LLC
American Electric Power Service Corporation as agent for Appalachian
Power Company, Indiana Michigan Power Company, Kentucky Power
Company, Kingsport Power Company, Ohio Power Company,
Wheeling Power Company, AEP Ohio Transmission Company, AEP
Appalachian Transmission Company, AEP West Virginia Transmission
MISO-MBHydro Contingency Reserve Sharing Group
Duke Energy Corporation
University Park Energy, LLC
Midcontinent Independent System Operator, Inc.
Atlantic City Electric Company
Delmarva Power & Light Company
Potomac Electric Power Company
5. Compliance Outreach
Compliance Outreach Activities
Outreach Activity
Monthly Newsletter - The ReliabilityFirst Newsletter provides registered entities with
news and information relating to reliability activities.
Monthly Compliance Update Letter - The ReliabilityFirst Monthly Compliance Update
Letter provides registered entities with any changes made to the Compliance
Monitoring Schedule and the due dates for compliance submittals.
ReliabilityFirst Website - The ReliabilityFirst website provides compliance and
technical materials to support compliance program implementation.
Workshops/Seminars/Webinars - ReliabilityFirst Compliance workshops/seminars or
webinars, will be scheduled to assist the registered entities in the understanding of
their responsibilities to satisfy compliance to the Reliability Standards throughout
the year.
CIP Version 5 Outreach and Awareness – ReliabilityFirst will conduct CIP Version 5
outreach, including training and education engagements, to ensure that registered
entities have confidence in their implementation of the CIP V5 Standards and
Requirements. These engagements will primarily be conducted as Workshops and
Webinars.
Compliance Data Management System (CDMS) - ReliabilityFirst allows its registered
entities to report compliance via CDMS, an internet based application. The CDMS
home page provides informational announcements, updates, and newsworthy items
of interest to the registered entities.
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Anticipated Date
Monthly throughout
the year.
Updated throughout
the year as needed.
Monthly throughout
the year.
Semi-annual (March
and October).
Monthly throughout
the year.
Updated throughout
the year as needed.
Appendix A4 - ReliabilityFirst Corporation (ReliabilityFirst) 2015 CMEP Implementation Plan
Compliance Outreach Activities
Outreach Activity
Periodic Reports - ReliabilityFirst will provide Periodic Reports to its registered
entities identifying compliance related activities that the registered entities continue
to struggle with. These reports will be posted on the ReliabilityFirst website.
Open Compliance Calls - ReliabilityFirst has implemented a monthly conference call
to provide an open forum for registered entities to call and voice concerns, ask
questions, and to gain information about upcoming compliance items.
Assist Visits - ReliabilityFirst has implemented a program whereby a registered entity
may request a one on one or a small group meeting where guidance on compliance
related activities can be provided. These Assist Visits can be in the form of a
conference call, web meeting, or on-site visit. Topics can range from helping an
entity become more familiar with compliance related material and activities, to
special guidance and education when either the registered entity or ReliabilityFirst
believes the registered entity needs special attention or additional help.
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50
Anticipated Date
Monthly throughout
the year.
Monthly throughout
the year.
As requested by our
registered entities.
Appendix A5 - SERC Reliability Corporation (SERC) 2015 CMEP
Implementation Plan
This Appendix contains the CMEP Implementation Plan (IP) for SERC as required by the NERC Rules of Procedure
(ROP).
1. Compliance Monitoring and Enforcement
1.1 CMEP IP Highlights and Material Changes
As part of SERC’s efforts to be more efficient and effective, and to strengthen and support the Compliance
area, the Operations and Planning (O&P) and Critical Infrastructure Protection (CIP) audit resources were
brought under one monitoring area function, Compliance Monitoring. This will allow SERC to be more
consistent in the application of tools and processes in compliance monitoring activities.
SERC will continue to support its Industry Subject Matter Expert (ISME) program, through which SERC
frequently uses industry volunteers employed by registered entities in the SERC Region as supplemental
compliance audit team members. SERC continues to be a leader among the Regions in this area. In 2014, the
program was enhanced to focus on identification, qualification, and assignment of ISMEs to match the
technical resource needs of specific audits, evaluation of ISME participation and performance during audits,
and training of ISMEs. During 2015, the ISME program will continue to be supported, highlighted during
certain SERC outreach events, and have information available on the SERC public website.
1.2 Other Regional Key Initiatives and Activities
Building from the successful momentum with the Reliability Assurance Initiative (RAI) in 2014, SERC will
continue to support RAI in 2015 in various ways. SERC will scope the appropriate Compliance Monitoring Plan
for each registered entity based on ERO Risk-based Compliance Oversight Framework, as described in the ERO
CMEP IP, which includes:-- the NERC 2015 risk elements Guide, SERC Regional Risk Assessment, Inherent Risk
Assessment (IRA), and Internal Control Evaluation (ICE). The Compliance Monitoring Oversight Plan will
include areas of focus, level of efforts, timing, and overall strategy on use of CMEP tool(s). Note, however,
each registered entity remains responsible for compliance with all Mandatory and Enforceable Reliability
Standard Requirements applicable to its registered function(s).
For registered entities identified as a Multiple Region registered entity (MRRE), the lead Region shall be
responsible for the coordination of compliance monitoring oversight activities. The lead Region is responsible
for coordinating and conducting the IRA and ICE; however, each Region shall have input to ensure regional
risks are identified. The lead Region may modify the Compliance Monitoring Oversight Plan as appropriate.
2. Regional Reliability Assessment Process and Regional Risk Identification
The SERC Region encompasses a large area, has some of the nation's largest cities and utilities, and serves a
significant portion of the U.S. population. Protecting the reliability of the electric grid in the SERC Region is the
responsibility of SERC members with the support of SERC staff and reliability programs. Reliable operation of
the Bulk Power System (BPS) is essential to regional economic viability. While each registered entity within
the SERC Region is diligent with respect to reliability and resiliency within their service area, it is the
responsibility of SERC to coordinate the reliability-related activities throughout the Region.
It should be recognized that the BPS in the SERC Region has been planned, built, and operated as part of the
integrated Eastern Interconnection. This integrated system serves the electric customers in the region under
both traditional vertically integrated and market-based generation dispatch mechanisms.
SERC has worked with its members since 2012 to develop and implement a continuous program of Regionwide assessments of potential reliability risks that could impact the SERC Region BPS. The SERC Regional
Reliability Risk Assessment program is a robust, centralized process for analyzing, prioritizing, addressing, and
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Appendix A5 - SERC Reliability Corporation (SERC) 2015 CMEP Implementation Plan
communicating significant risks and risk-controlled initiatives. This is the first application of the output of this
program communicating the choice of Standards for inclusion in the SERC CMEP.
The SERC Standing Committees, the SERC Reliability Risk Team (RRT)20, and SERC Reliability Assessment and
Performance Analysis staff contribute to the SERC Regional Reliability Risk Assessment Program. The objective
of the program is to improve BPS reliability through a coordinated effort that identifies, analyzes, prioritizes,
and addresses reliability risks. In conformance with the ERO RAI risk management program, the SERC process
consists of the following major activities:





Identify/Nominate Risks
Determine Time Horizon (e.g. immediate, next-day, operational, seasonal, and long-term).
Assess and Rank Risk
 Determination of the consequence, or severity impact(s)
 Determination of the probability of occurrence
 Assignment of High, Medium, or Low from the Risk Assessment Matrix
 Prioritization of risks
 Stored in the Risk Registry
Develop Risk Control Initiatives
Monitor and Reevaluate Risk Impact
The coordination of the efforts with the SERC registered entities, the SERC technical committees, SERC staff,
neighboring system personnel, and other members of the ERO is vital to the understanding and analysis of
potential major reliability issues. SERC, through its members and staff, is heavily engaged with NERC and its
risk initiatives. SERC’s risk management programs enable it to focus compliance monitoring oversight activities
on those Reliability Standards which, if violated, would pose the greatest risk to the reliable operation of the
SERC portion of the BPS. The Reliability Standards listed in Section 3 are the program’s recommendation for
2015 and are based on what is known at the time of this submittal.
SERC has recognized one NERC Reliability Standard, PRC-006, as needing greater specificity to achieve
successful coordination of the registered entities within the SERC Region. PRC-006 has Requirements that
identify the Planning Coordinator (PC) as the registered entity responsible for developing under frequency
load shedding (UFLS) schemes within their PC area. However, the NERC Standard does not provide specific
guidance regarding the extent of cooperation with surrounding PCs which may lead to inconsistent set points
and other regional inconsistencies for key UFLS parameters. In response, SERC created a Regional Reliability
Standard, PRC-006-SERC-01, to establish consistent and coordinated Requirements for the design,
implementation, and analysis of UFLS programs among applicable SERC registered entities. The Regional
Standard adds specificity not contained in the NERC Standard for development and implementation of the
UFLS scheme in the SERC Region that effectively mitigates the consequences of an under-frequency event.
SERC has numerous UFLS schemes deployed within its Region; therefore, SERC developed and implemented
the Regional Standard to ensure more comprehensive UFLS testing to identify possible regional gaps.
3. Regional Risk Focus Areas and Associated Reliability Standards
The table below contains the Regional risks focus areas identified during the Regional Reliability Assessment
process. The table also links associated Reliability Standards/Requirements to identified risks that may be
20
The RRT includes SERC Engineering Committee, Operating Committee, and CIP Committee members and was explicitly created to
formalize and apply a process to carry out the basic elements of reliability risk monitoring, classification and management. It is noteworthy
that the RRT monitors many risks not defined in the Reliability Standards, but are in support of best practices that promote BPS reliability.
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Appendix A5 - SERC Reliability Corporation (SERC) 2015 CMEP Implementation Plan
considered in the Regional Compliance Monitoring Plan. Note that the Standards/Requirements listed below
are in addition to the Standards/Requirements identified in the 2015 ERO risk elements Guide.
Reliability Standards Subject to Regional Monitoring
Regional Risk
Focus Area
External Risks
associated with
Critical Cyber
Assets
Physical
Events/Threats
Cyber System
Integrity Risks
Cold weather
impacts on
transmission and
generation
Justification
Electronic Access Points (EAP) often provide the first
level of defense against vulnerability-based attacks,
and based on SERC’s most violated Reliability
Standards/Requirements (previous three years) CIP005 is the Region’s third most violated CIP Standard.
Given the EAP is often the first level of defense,
controlling access into the perimeter and monitoring
for cyber-based attacks is critical to protecting cyber
assets within and reducing the risk of degradation to
the BPS.
Physical Events represent those events that result in
extensive damage to equipment, irrespective of cause.
Based on SERC’s most violated Reliability
Standards/Requirements report (previous three years)
CIP-006 is the Region’s second most violated CIP
standard. Additional focus is needed to address and
minimize both the magnitude and duration of the
consequences of a physical event. Physical access to
cyber systems must be restricted and appropriately
managed to ensure the integrity of the cyber systems
within the Physical Security Perimeter.
As the top violated Reliability Standard within the SERC
Region, additional focus must be placed on cyber
system integrity. Two key parts of ensuring system
integrity are security patch and user account
management. Security patch management is crucial in
monitoring and addressing known security
vulnerabilities prior to those vulnerabilities being
exploited in a malicious manner that could degrade, or
render unavailable, the cyber systems required to
ensure the reliability of the BPS. User account
management is essential in ensuring only authorized
personnel can gain electronic access to Critical Cyber
Assets.
The SERC and NERC Polar Vortex related research, final
and preliminary reports reveal numerous operational
risks inherent to SERC registered entities, which may
degrade the SERC Region’s BPS reliability performance
below what is required by the NERC Standards.
Standard & Requirement
CIP-005-3a R2, R3
CIP-006-3c R2, R5, R6
CIP-007-3 R3, R5
BAL-001-1 R1, R2; BAL-002-1
R1; BAL-005-0.2b R7; COM002-2 R1, R2
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Appendix A5 - SERC Reliability Corporation (SERC) 2015 CMEP Implementation Plan
Reliability Standards Subject to Regional Monitoring
Regional Risk
Focus Area
Major storm
events such as
hurricanes and
tornados
Justification
Standard & Requirement
The SERC Region historically has experienced severe
COM-002-2 R1, R2
weather events, such as hurricanes and tornados. The
most recent noteworthy weather events are hurricane
Katrina and recurring mass tornado events in 2008 and
2011. These events usually create system
contingencies beyond existing planning criteria;
however, emergency procedures and other operating
standards still apply. Over the years, the Region has
identified this risk and emphasized system
preparedness through the 2012 Assessment of SERC
Performance Information for Identifying Potential
Reliability Risk, as well as through the NERC Reliability
Assessment reporting process.
Power System
coordination and
modeling
Increased BPS use in a manner for which the
system wasn’t originally designed, coupled with
insufficient operating experience, coordinated
studies and coordinated operations, can introduce
risk to reliable operation of the BPS in the SERC
Region. The NERC Arizona-Southern California
Outages report highlighted potential areas of
vulnerability. Significant changes in generation
dispatch, particularly if such changes are
unstudied, increases reliability risk. As a result,
additional focus on registered entities impacted by
these issues with respect to these Standards is
warranted. References to neighboring system
coordination and recommendations can be found
in the NERC Arizona-Southern California Outages
report.”
MOD-001-1a R6; FAC-008-3
R6; FAC-014-2 R1, R2, R3, R4 ;
IRO-003-2 R1, R2; IRO-004-2
R1; VAR-001-4 R1, R2; VAR002-3 R1, R2, R3
UFLS Schemes
The SERC UFLS Regional Standard is to establish
PRC-006-SERC-01 R1, R2, R3,
consistent and coordinated requirements for the
R4, R5, R6
design, implementation, and analysis of UFLS programs
among SERC applicable registered entities. The
regional standard adds specificity not contained in the
NERC standard for development and implementation of
the UFLS scheme in the SERC Region that effectively
mitigates the consequences of an under-frequency
event.
4. Compliance Oversight Plan
Scheduling of Audits
Registered entities registered as a Balancing Authority (BA), Reliability Coordinator (RC), or Transmission
Operator (TOP) will continue to be audited every three years per the current NERC ROP. SERC will continue
to monitor registered entities that are scheduled for an audit based on SERC’s long term monitoring plan in
2015. For all registered entities scheduled for an audit in 2015, flexibility to adjust the periodicity, as well as
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Appendix A5 - SERC Reliability Corporation (SERC) 2015 CMEP Implementation Plan
audit scope, will be considered and adjusted based upon the Regional Risk Assessment, the Risk-based
Compliance Oversight Plan provided by NERC, and the Inherent Risk Assessment (IRA) of the registered entity
performed by SERC.
For registered entities registered only as a Purchasing-Selling Entity (PSE), SERC will use the Self-Certification
monitoring method in lieu of conducting an audit of these registered entities. This monitoring method was
selected based upon SERC’s Regional Risk Assessment conducted for 2015 and the limited number of reliability
issues posed by PSE operation.
SERC will not conduct an off-site or on-site CIP audit for registered entities that have declared that they own
no Critical Assets (CAs) or Critical Cyber Assets (CCAs). This determination is based upon the Cyber Security
Reliability Standards CIP V5 Transition Guidance provided by NERC that states, “For those Responsible Entities
that do not have any Critical Assets or Critical Cyber Assets under the CIP V3 Standards, however, Regional
Entities will forgo off-site audits of the CIP Reliability Standards during the Transition Period.” SERC may
determine to use another monitoring method based on the registered entity IRA.
SERC is gathering CIP V5 data from its registered entities to better understand the scope and focus of required
outreach during 2015 and beyond. SERC is conducting a survey during the implementation period to
determine the status of each registered entity’s transition to the CIP V5 Standards. Based on the data
obtained, SERC will further align its outreach activities.
Self-Certification Monitoring
SERC will use Self-Certifications based on the guidance in the ERO CMEP IP, SERC’s annual Regional Risk
Assessments, registered entity IRA, internal controls evaluations (if applicable), compliance history, etc. SelfCertifications may also use guided self-certifications that include specific questions and/or data
requests. SERC will require all Self-Certifications to be completed on a Requirement basis. This will require
a Self-Certification in which all sub-Requirements must be completed for each Requirement listed. SERC will
provide additional guidance on Self-Certification requirements to registered entities throughout 2015 as
needed
Spot Checking
SERC will determine the need for Spot-Checks based on the outcome of the registered entity IRA. In addition,
SERC may use the Spot Check process to verify Mitigation Plans as needed.
Periodic Data Submittals
SERC will still have a number of Standards and Requirements that require a data submittal. Most of these
data submittals serve as reminders to our registered entities of a monthly, quarterly, and/or annual reporting
Requirement in the Standard.
The audit schedule below shows registered entities that are subject to an audit during 2015 based on the
three year cycle prescribed by NERC’s ROP. The schedule is also located on the SERC’s website here:
http://www.serc1.org/Documents/Compliance/2015%20Program/2015%20SERC%20Audit%20Schedule.pdf
NCR #
NCR01312
NCR00070
NCR01225
NCR01223
NCR01151
NCR01359
2015 Compliance Audit Schedule
Registered Entity
South Carolina Public Service Authority-Audit
Southeastern Power Administration-Audit
East Kentucky Power Cooperative-Audit
LG&E and KU Services Company-Audit
Tennessee Valley Authority-Audit
USACE-Mobile District-Audit
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Appendix A5 - SERC Reliability Corporation (SERC) 2015 CMEP Implementation Plan
NCR #
NCR01359
NCR00826
NCR01315
NCR01361
NCR01234
NCR01320
NCR11305
2015 Compliance Audit Schedule
Registered Entity
City of Springfield, IL-CWLP-Audit
Midwest Independent Transmission System Operator Inc. (RFC Lead)Audit
South Mississippi Electric Power Association-Audit
USACE-Savannah District-Audit
Entergy-Audit
Southern Company Services, Inc.– Trans-Audit
Smoky Mountain Transmission LLC-Audit
5. Compliance Outreach
Compliance Outreach Activities
Outreach Activity
SERC Compliance Portal
SERC registered entities submit Self-Certifications, Self-Reports, Mitigation Plans,
and Data Submittals via the SERC Portal. Surveys are conducted for feedback to
allow SERC to incorporate enhancements based on the needs of the users and
outreach events include training on upgrades and enhancements.
Outreach Events
SERC outreach events are planned throughout the year to accommodate the training
needs of registered entities. Planned events, listed here, with specific themes will
also feature compliance and reliability topics of importance at the time of the event.
All events are posted to the SERC website, listed in the SERC Outreach & Training
Catalog on the website, featured in the monthly SERC Transmission newsletter, and
email notifications and reminders are sent to primary and alternate compliance
contacts for all registered entities within the SERC Region footprint.
 Open Forum (WebEx): SERC’s Redesigned Website
 Spring Compliance Seminar
 Small Entity Workshop: CIP V5 Transition
 Open Forum (WebEx)
 Open Forum (WebEx)
 CIP Compliance Seminar
 Fall Compliance Seminar
Focused Workshops / Webinars
Supplemental focused events will be scheduled on an as-needed basis to provide
outreach and training for new or revised Reliability Standards, targeted groups of
registered entities based on functional Registration, and ERO initiatives.
Lessons Learned
Lessons Learned website postings will share information among registered entities.
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Anticipated Date
As needed
throughout the year
Jan 26, 2015
Feb 24-25, 2015
Feb 25, 2015
Apr 13, 2015
Jul 20, 2015
Sep 29-30, 2015
Oct 27-28, 2015
As needed
throughout the year
As available
throughout the year
Appendix A5 - SERC Reliability Corporation (SERC) 2015 CMEP Implementation Plan
Compliance Outreach Activities
Outreach Activity
Anticipated Date
Training and Education Catalog
SERC maintains a catalog of recorded and upcoming training and education activities Updated as needed
on its website to increase the number of people who are aware and are able to take throughout the year
advantage of SERC’s training and education programs.
Compliance Outreach Assistance
Upon receipt of a New Registration Application, a document containing links to
“Compliance 101” files on the FERC, NERC, and SERC websites will be sent to the
applicant to provide basic compliance information in one convenient location. A
sample of the links includes information such as the Energy Policy Act (EPA) of 2005
on the FERC site, ROP and Reliability Standards on the NERC site, and Acronym
Reference Index and SERC Filing Due Dates on the SERC site.
The SERC Transmission newsletter is distributed to registered entities within the
SERC Region on a monthly basis. Articles contain links to scheduled outreach
information for both SERC and NERC events, along with other topics helpful to
maintain BPS reliability.
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Updated as needed
throughout the year
Appendix A6 - Southwest Power Pool Regional Entity (SPP RE)
2015 CMEP Implementation Plan
This Appendix contains the CMEP Implementation Plan (IP) for the SPP RE as required by the NERC Rules of
Procedure.
1. Compliance Monitoring and Enforcement
1.1 CMEP IP Highlights and Material Changes
SPP RE budgeted for four open positions in 2015 – the Compliance Director, two (2) Lead Engineers and a CIP
Compliance Specialist. SPP RE will also utilize contractors or consultants during the 2015 year to assist Staff
during audits, investigations and/or enforcement activities.
SPP RE will be developing new tools and templates to implement the Reliability Assurance Initiative (RAI)
activities.
1.2 Other Regional Key Initiatives & Activities
SPP RE will continue to collaborate with NERC, Regional Entities and the registered entities to identify changes
to enhance the risk-based approach to the monitoring and enforcement processes.
SPP RE CIP Staff will begin an Outreach Program that will assist the registered entities in the transition to CIP
version 5.
2. Regional Reliability Assessment Process and Regional Risk Identification
SPP RE has developed a Regional Audit Scope Plan that identifies the risk elements within the SPP RE footprint.
The SPP RE risk focus areas identified include the top violated requirements, facility rating impacts, newly
enforceable Reliability Standards, System Awareness and protection of Cyber Assets.
SPP RE will consider these Regional risk focus areas when following the ERO Risk-based Compliance Oversight
Framework described in the ERO CMEP. SPP RE will also consider the Regional risk focus areas when
conducting risk assessments for the registered entities that are scheduled for audits during 2015 to develop
the audit scope.
3. Regional Risks Focus Areas and Associated Reliability Standards
The table below contains the Regional risk focus areas identified during the Regional Risk Assessment process.
The table also contains associated Reliability Standards/Requirements for identified risks that may be
considered in the Regional compliance oversight plan.
Reliability Standards Subject to Regional Monitoring
Regional Risk
Focus Areas
Protection of
Cyber Assets
Protection of
Cyber Assets
Protection of
Cyber Assets
Facility Ratings
Impacts
Justification
Associated Standard &
Requirement(s)
CIP-005-3 R2, R3
Essential to ensure the system protecting the cyber
system can continue to maintain a security perimeter.
Essential to ensure the protection of Cyber Assets from CIP-006-3 R2, R3, R6
unauthorized physical access.
Essential to ensure applicable security patches are
CIP-007-3 R3, R5
identified and installed on the CIP systems.
Essential to ensure Generator Owners and
Transmission Owners develops, maintain and
FAC-008-3 R1, R2, R3, R6, R7
coordinate accurate facility ratings.
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Appendix A6 - Southwest Power Pool Regional Entity (SPP RE) 2015 CMEP Implementation Plan
Reliability Standards Subject to Regional Monitoring
Regional Risk
Focus Areas
Facility Ratings
Impacts
System
Awareness
System
Awareness
New
Requirements
Top Violated
Justification
Essential to ensure Transmission Operators and
Planning Authorities and Reliability Coordinators
establish and coordinate SOLs and IROLs.
Essential to ensure the Balancing Authorities and
Transmission Operators operates and maintains the
reliability of the system.
Essential to ensure the Balancing Authorities and
Transmission Operators operates and maintains the
reliability of the system.
Essential to ensure Generator Owners have a strategy
to prevent vegetation encroachment into the MVCD.
Top violated in the SPP RE area. Essential to ensure the
BPS infrastructure is maintained.
Associated Standard &
Requirement(s)
FAC-014-2 R2
TOP-002-2.1b R6
TOP-004-2 R1, R4
FAC-003-3 R3 (GO only)
PRC-005-1.b R1, R2
4. Compliance Oversight Plan
SPP RE will use the following monitoring tools for 2015:
On-Site Audits –SPP RE will continue to audit the Transmission Operator and Balancing Authority entities that
are on the three (3) year cycle for the Ops & Planning and CIP audits in 2015.
Off-Site Audits- SPP RE will continue to audit the registered entities that are scheduled for a six (6) year audit
cycle and for registered entities that have been registered within the last two (2) years for the Ops & Planning,
CIP will not perform off-site audits in 2015 per the CIP V3 to V5 Transition Documentation.
Spot-Checks – Spot-Checks may be used in lieu of Off-Site audits for entities that have a lower risk identified
through the entity assessment. There are no mandatory Spot Checks listed in the 2015 NERC IP. However, SPP
RE may initiate a Spot Check at any time to verify or confirm Self Certifications, Self Reports, and Periodic Data
Submittals or in response to operating problems or system events. SPP RE may initiate Spot-Checks for the six
(6) year audit cycle registered entities that had Area of Concerns identified in the audits during 2012.
Self-Certification – SPP RE will continue to require SPP RE registered entities to perform a Self-Certification to
ensure that the entity is maintaining the rigor of their internal controls for reviewing compliance with the
Reliability Standards. SPP RE has identified such requirements based on the ERO CMEP IP and Regional
Assessment for the registered entities. Self-Certification will be conducted using webCDMS. Entities will
receive additional notice and instructions before each quarterly reporting window. Periodic Data Submittal The 2015 NERC IP does not identify Reliability Standards and Requirements that require periodic data
submittals. SPP RE will require specific Reliability Standards and Requirements that contain periodic data
submittal requirements for which SPP RE or SPP RTO will collect on a monthly, quarterly, or annual basis.
The reporting requirements and the Audit Scope Plan are located on the SPP RE’s website here:
http://www.spp.org/section.asp?group=3290&pageID=27
The audit schedule is also located on the SPP RE’s website here:
http://www.spp.org/section.asp?group=3290&pageID=27
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Appendix A6 - Southwest Power Pool Regional Entity (SPP RE) 2015 CMEP Implementation Plan
2015 Compliance Audit Schedule
Registered Entity
American Electric Power Service Corp. (AEPW)
Borger Energy Associates, LP (BOEA)
Chisholm View Wind Project, LLC
Dogwood Power Management, LLC (DPM)
East Texas Electric Cooperative, Inc. (ETEC)
Kansas City Power & Light Company (KCPL)
Lea County Electric Cooperative, Inc. (LCEC)
Midcontinent Independent System Operator, Inc (MISO)
Midwest Energy, Inc. (MIDW)
MISO-MBHydro Contingency Reserve Sharing Group (MRSG)
NAES Corporation - Goodman Energy Center (NAESGEC)
NextEra Energy Resources, LLC (NEXTERA)
North American Energy Services - Dogwood (NAESDOGW)
Northeast Texas Electric Cooperative, Inc (NTEC)
PIC Group, Inc.- Mustang (PICMUS)
Post Rock Wind Power Project, LLC
Sunflower Electric Power Corporation (SECI)
Terrebonne Parish Consolidated Government (TERREBONNE)
Tex-La Electric Cooperative Of Texas, Inc (TEXL)
Western Farmers Electric Cooperative (WFEC) w/ TRE
City Utilities of Springfield
Southwestern Power Administration
Western Farmers Electric Cooperative (WFEC) w/ TRE
Midcontinent Independent System Operator, Inc (MISO)
Grand River Dam Authority
Oklahoma Gas & Electric Company
NCR #
NCR01056
NCR01062
NCR11291
NCR11250
NCR01227
NCR01107
NCR06047
NCR00826
NCR01118
NCR03044
NCR11236
NCR01096
NCR06054
NCR01124
NCR11224
NCR11264
NCR01148
NCR01152
NCR01342
NCR01160
NCR01081
NCR01144
NCR01160
NCR00826
NCR01101
NCR01130
5. Compliance Outreach
Compliance Outreach Activities
Outreach Activity
Newsletters
SPP.org RE webpages (http://www.spp.org/section.asp?pageid=87)
2015 Spring Compliance Workshop
2015 CIP Workshop
2015 Fall Compliance Workshop
Webinars
Training Videos (http://www.spp.org/section.asp?pageID=92)
Event Analysis Lessons Learned
(http://www.spp.org/section.asp?group=2243&pageID=27)
NERC | 2015 ERO CMEP Implementation Plan Version 1.0 | November 18, 2014
60
Anticipated Date
Monthly
Updated as needed
March 10-11, Little
Rock
June 2-3, Kansas City
September 29-30,
Dallas
Approx. 9 per year
As developed
As developed
Appendix A7 - Texas Reliability Entity (Texas RE) 2015 CMEP
Implementation Plan
This Appendix contains the CMEP Implementation Plan (IP) for the Texas RE as required by the NERC Rules of
Procedure.
1. Compliance Monitoring and Enforcement
1.1 CMEP IP Highlights and Material Changes
Texas RE in 2015 will continue to implement the Reliability Assurance Initiative (RAI), the Electric Reliability
Organization’s strategic initiative to transform the current compliance and enforcement program into a
program that is forward-looking and focuses on high risks to the Bulk Power System (BPS).
In Section 4 below, Texas RE provides a list of registered entities that are planned to undergo compliance
monitoring in the Texas Interconnection in 2015 and additional information on its compliance monitoring.
Consistent with the NERC Rules of Procedure and approved practices, registered entities were selected for
compliance monitoring based on three-year and six-year cycles.
1.2 Other Regional Key Initiatives & Activities
Texas RE will be engaged in a significant amount of outreach associated with transition to CIP Version 5
throughout 2015. The outreach will consist of frequent, information-rich calls, newsletters and specialized
workshops (as needed), intended to provide guidance and support for all entities.
Texas RE will continue its collaborative effort between NERC, the Regional Entities, and registered entities to
identify and implement changes that enhance the effectiveness of the Compliance Monitoring and
Enforcement Program.
2. Regional Reliability Assessment Process and Regional Risk Identification
As part of the Reliability Assurance Initiative, the level of scrutiny a registered entity receives in terms of
compliance monitoring will be directly commensurate with the risk it poses to the reliability of the BPS. For
entities that do not pose a significant reliability risk, the minimum compliance monitoring activities may
suffice. For entities that do pose a significant risk to reliability, it will be necessary for those entities to undergo
additional compliance monitoring such as additional focused spot checks, a greater number of SelfCertifications, or broader and deeper audits of greater frequency.
To assist Texas RE in determining how much risk an entity poses to reliability, Texas RE utilizes dedicated staff
to review risk within the ERCOT Interconnection. The staff relies heavily on feedback from other groups within
Texas RE such as Registration, Enforcement, Reliability Services, and Compliance to achieve an understanding
of the risks encountered or emerging within the region. Additionally, Texas RE reviews externally created
reports and discussions focusing on reliability risks. The recently developed risk elements Guide provides
basic guidance for determining risks for which some level of compliance monitoring may be appropriate.
Texas RE will utilize the risk elements Guide to focus on risks within the region by involving local subject matter
experts. For example, the Texas RE Reliability Services department creates an annual state of reliability report.
Some aspects within the report correlate to the risk elements determined within the risk elements Guide but
others are corollaries, such as “Unplanned generation outages with emphasis on winter preparation,” a
localized issue requiring localized focus. Texas RE will utilize determined risks to facilitate engagements with
registered entities in such a way that prioritizes the evaluation of compliance for the determined risks. Texas
RE will apply the appropriate risk element or risk elements to the appropriate registered entity to maintain
focus on reliability.
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Appendix A7 - Texas Reliability Entity (Texas RE) 2015 CMEP Implementation Plan
Every registered entity is subject to an evaluation of compliance for all Standards determined to be within the
Areas of Focus described within the risk elements Guide. Additional risk elements may be added as needed
throughout the year. For Critical Infrastructure Protection requirements, Texas RE will utilize the approved
transition guide and apply RAI concepts to determine relevant risks to reliability and appropriate Compliance
Monitoring and Enforcement Program processes.
3. Regional Risk Focus Areas and Associated Reliability Standards
The table below contains examples of Regional risk focus areas identified during the Regional Reliability
Assessment process. The table also contains examples of associated Reliability Standards/Requirements to
identified risks that may be considered in the Regional compliance monitoring plan. This table may be updated
as needed and in no way restricts Texas RE from utilizing other regional risks and associated
Standards/Requirements determined throughout the year.
Reliability Risks Subject to Regional Monitoring
Regional Risk Focus
Justification
Area
Planning
Planning is considered a risk due to the
nature of this Interconnection. The list of
requirements covers a broad perspective
of the different facets of planning
requirements that have an impact on
reliability.
Emergency
Response and
Recovery
SPS Management
Standard & Requirement
BAL-001-1 R1-R2; BAL-003-0.1b R1, R2,
R4, R5, R6; EOP-001-2.1b R2-R4;EOP-0023.1 R2; EOP-003-2 R2-R8;EOP-004-2 R1R3; EOP-005-2 R1, R3, R4, R6; EOP-006-2
R1; FAC-008-3 R3, R6- R8; FAC-010-2.1
R1-R4; FAC-011-2 R1-R4; FAC-013-2 R1;
FAC-014-2 R1-R4; PRC-006-1 R1-R14;
VAR-001-4 R1-R5; VAR-002-3 R5, R6
The nature of this Interconnection
BAL-001-1 R1-R2; BAL-002-1 R1; COMrequires monitoring of the reliability
001-1.1 R5; COM-002-2 R1-R2; EOP-001related activities needed to respond and
2.1b R1-R6; EOP-002-3.1 R1-R9; EOPrecover to emergencies.
003-2 R1, R2; EOP-005-2 R1-R18; EOP006-2 R1-R10 ; EOP-008-1 R1-R8; EOP010-1 R1-R3; FAC-010-2.1 R2; FAC-011-2
R2; FAC-014-2 R1-R4, R6; IRO-001-1.1 R3,
R8; IRO-002-2 R1, R4, R6, R7; IRO-003-2
R1, R2; IRO-005-3.1 R12; IRO-006-5 R1;
IRO-006-TRE-1 R1-R2; IRO-009-1 R1-R5;
IRO-010-1a R1, R3; IRO-016-1 R1; PER001-0.2 R1; PER-004-2 R1, R2; PER-005-1
R3; PRC-001-1.1 R2, R6; TOP-001-1a R1R6, R8; TOP-002-2.1b R6; TOP-003-1 R1;
TOP-004-2 R4-R6; TOP-006-2 R5, R6;
TOP-007-0 R1-R4; TOP-008-1 R1-R4; TPL002-0b R1-R3; TPL-003-0b R1-R3; TPL004-0a R1-R2
SPS remains a facet of operations that can PRC-001-1.1 R1-R6; PRC-005-2 R1-R5;
have an impact on reliability. There has
PRC-015-0 R1-R3; PRC-016-0.1 R1-R3;
been a significant amount of change with PRC-017-0 R1-R2
respect to the quantity of SPS’s within this
Interconnect
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Appendix A7 - Texas Reliability Entity (Texas RE) 2015 CMEP Implementation Plan
Reliability Risks Subject to Regional Monitoring
Regional Risk Focus
Justification
Standard & Requirement
Area
UVLS Management There are areas within this Interconnect
EOP-003-2 R2, R4, R7; PRC-001-1.1 R1that require monitoring of this operational R5; PRC-004-2.1a R1-R3; PRC-005-2 R1tool.
R5; PRC-010-0 R1; PRC-011-0 R1-R2; PRC021-1 R1-R2; PRC-022-1 R1
UFLS Management Frequency control is significant within this PRC-001-1.1 R1-R5; PRC-004-2.1a R1-R3;
Interconnection and monitoring the UFLS PRC-005-2 R1-R5; PRC-006-1 R1-R12;
aspect is important to ensure reliability.
PRC-008-0 R1-R2;
Local Emergency
There are localized emergencies that, if
COM-001-1.1 R5; COM-002-2 R1-R2,
Management
not managed well, could lead to broader EOP-001-2.1b R1-R5; EOP-002-3.1 R1-R9,
impacts to the Interconnection.
EOP-003-2 R1-R8; EOP-005-2 R1-R18;
EOP-006-2 R1-R10; IRO-006-TRE-1 R1-R2;
TOP-001-1a R1-R6, R8; TOP-002-2.1b R1,
R4, R6, R10; TOP-003-1 R1-R3; TOP-004-2
R1-R4, R6; TOP-006-2 R1, R2, R4; TOP007-0 R1-R4; TOP-008-1 R1-R4
Operations Guides The management of the various operating IRO-006-TRE-1 R1-R2
(RAP, MP, PCAP,
tools available to preserve reliability
TOAP, etc…)
require a level of compliance monitoring.
SOL/IROL
The nature of the Interconnection
COM-002-2 R1-R2; EOP-001-2.1b R1-R3;
Coordination
requires this risk to be closely monitored FAC-002-1 R1; FAC-008-3 R1-R3, R6, R8;
and reviewed.
FAC-010-2.1 R1-R4; FAC-011-2 R1-R4;
FAC-013-2 R1, R2, R4, R5; FAC-014-2 R1R5 ; IRO-001-1.1 R1, R2, R4, R6-R9; IRO002-2 R3-R5, R7; IRO-003-2 R1-R2; IRO004-2 R1; IRO-005-3.1a R1, R2, R5, R9,
R12; IRO-006-5 R1; IRO-006-TRE-1 R1R2; IRO-008-1 R1-R2; IRO-009-1 R1-R5;
IRO-010-1a R1-R2; IRO-014-1 R1-R4; IRO015-1 R1; MOD-010-0 R1; MOD-012-0
R1-R2; MOD-018-0 R1; NUC-001-2.1 R4,
R9; PER-004-2 R2; PER-005-1 R3; TOP001-1a R1-R3, R7; TOP-002-2.1b R1, R2,
R4, R10, R11, R13, R16, R18; TOP-003-1
R1, R2; TOP-004-2 R1, R4-R6; TOP-005-2a
R2; TOP-006-2 R3, R5, R6; TOP-007-0 R1,
R2, R4; TOP-008-1 R1-R4; TPL-001-0.1
R1-R2; TPL-002-0b R1-R2; TPL-003-0b R1R2; TPL-004-0a R1; VAR-002-3 R2
Critical Voltage
This risk is closely related to the UVLS
CIP-002-3 R1; COM-002-2 R1; FAC-002-1
Support
management but covers risks in other
R1; FAC-008-3 R6, R7, R8; IRO-002-2 R4,
portions of the Interconnect that may not R5; PRC-010-0 R1; PRC-011-0 R1-R2; TOPhave UVLS.
003-1 R2; TOP-006-2 R2, R5; VAR-001-4
R1-R5; VAR-002-3 R1-R4, R6
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Appendix A7 - Texas Reliability Entity (Texas RE) 2015 CMEP Implementation Plan
Reliability Risks Subject to Regional Monitoring
Regional Risk Focus
Justification
Standard & Requirement
Area
SCADA/EMS Outage NERC has recognized this as a re-occurring CIP-003-3 R1,R2, R4-R6;; CIP-005-3a R1and Problems
event that requires monitoring to
R4; CIP-006-3c R2-R6; CIP-007-3a R1-R9;
determine impacts to reliability.
CIP-008-3 R1-R2; CIP-009-3 R1-R4; COM001-1.1 R1-R5; COM-002-2 R1-R2; EOP001-2.1b R2, R3, R5; EOP-003-2 R5, R6,
R8; EOP-004-2 R1-R2; EOP-005-2 R1, R3,
R10; EOP-008-1 R1-R8; IRO-001-1.1 R1,
R4; IRO-002-2 R5, R6, R7, R8; IRO-003-2
R1, R2; IRO-005-3.1a R1, R2, R5, R7, R8,
R9; IRO-006-TRE-1 R1, R2; IRO-010-1a R1;
PER-005-1 R1; PRC-001-1.1 R6; TOP-0011a R1-R5, R7-R8; TOP-002-2.1b R1, R5,
R6, R10, R11, R14, R16; TOP-004-2 R1,
R4, R6; TOP-005-2a R2; TOP-006-2 R1-R6;
TOP-007-0 R1; TOP-008-1 R1-R4
Internal Access
Even with the transition to CIP V5 there is BAL-005-0.2b R3; CIP-002-3 R1-R2; CIPPoints PSP
a need to maintain security and provide
003-3 R1, R5; CIP-004-3a R1-R4; CIP-006monitoring activities associated with CIP. 3c R1-R6, R8
External Access
Even with the transition to CIP V5 there is BAL-005-0.2b R3; CIP-002-3 R1-R3; CIPPoints ESP
a need to maintain security and provide
003-3 R1, R4-R6; CIP-004-3a R1-R4; CIPmonitoring activities associated with CIP. 005-3a R1-R4
Network
Even with the transition to CIP V5 there is BAL-005-0.2b R3; CIP-002-3 R1-R3; CIPArchitecture
a need to maintain security and provide
003-3 R1,R2, R4-R6; CIP-004-3a R1-R4;
monitoring activities associated with CIP. CIP-005-3a R1-R4; CIP-006-3c R2-R6; CIP007-3a R1-R9
Critical Assets
Even with the transition to CIP V5 there is BAL-005-0.2b R3; CIP-002-3 R1-R4
Selection
a need to maintain security and provide
monitoring activities associated with CIP.
Frequency
The nature of this Interconnection
BAL-001-1 R1-R3; BAL-001-TRE-1 R2, R3,
Response and
requires monitoring of the reliability
R6-R10; BAL-003-0.1b R1, R4; BAL-005Control
related activities needed to maintain
0.2b R14; COM-002-2 R1; EOP-001-2.1b
frequency.
R2; EOP-002-3.1 R5; EOP-003-2 R6, R7;
EOP-006-2 R7; PRC-006-1 R1-R14; PRC008-0 R1, R2; TOP-006-2 R7
Protection System
Protection System performance remains a PRC-001-1.1 R2-R6; PRC-004-2.1a R1-R3;
Performance
risk requiring focused attention.
PRC-023-3 R1-R6,; PRC-025-1 R1;
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Appendix A7 - Texas Reliability Entity (Texas RE) 2015 CMEP Implementation Plan
Reliability Risks Subject to Regional Monitoring
Regional Risk Focus
Justification
Standard & Requirement
Area
Operational
Communication is a critical aspect of
BAL-003-0.1b R1; BAL-004-0 R2, R4; BALCommunication
reliability.
005-0.2b R4; BAL-006-2 R2-R5; COM-0011.1 R1, , R3, R4; COM-002-2 R1, R2; EOP001-2.1b R3, R6; EOP-002-3.1 R3, R7, R9;
EOP-003-2 R3; EOP-005-2 R1-4, R8, R15;
EOP-006-2 R2, R4, R5, R7, R8, R10; EOP008-1 R8; EOP-010-1 R2; FAC-001-1 R1;;
IRO-002-2 R1-R3; IRO-004-2 R1; IRO-0053.1a R3, R4, R6, R9, R10, R12; IRO-006-5
R1; IRO-009-1 R4; IRO-016-1 R1; MOD001-1a R4, R5; PRC-001-1.1 R2, R6; TOP001-1a R3-R5, R7, R8; TOP-002-2.1b R3,
R4, R11, R13-R17,; TOP-003-1 R1-R3,;
TOP-004-2 R6,; TOP-005-2a R1-R3; TOP006-2 R1; TOP-007-0 R1, R4; TOP-008-1
R3; VAR-001-4 R3; VAR-002-3 R1-R4, R6
Renewables
The management of renewable
BAL-001-TRE-1 R2, R3, R6-R10; BAL-005Integration
integration is important to reliability due 0.2b R1, R14; CIP-002-3 R1-R3,; COMto the nature of this Interconnection. The 002-2 R1-R2; EOP-004-2 R1, R2; FAC-001Interconnect has had a significant change 1 R1-R3; FAC-002-1 R1; FAC-008-3 R1, R2,
in topology to allow integration and the
R6, R7; IRO-002-2 R1-R8; MOD-026-1 R2results of that integration are becoming
R5; MOD-027-1 R1-R5; PRC-001-1.1 R3;
more apparent during grid operations.
PRC-018-1 R1-R6; TOP-001-1a R3, R6, R7;
TOP-002-2.1b R13- R15; TOP-006-2 R1;
VAR-002-3 R1-R2
4. Compliance Oversight Plan
Texas RE will use the approved ERO Compliance Oversight Framework, as described in the ERO CMEP IP, to
determine the scope of each compliance engagement and the method for conducting the engagement (such
as by audit, Self-Certification, or spot check). Texas RE will evaluate risk elements and apply compliance
monitoring subject to NERC Standards and Requirements applicable to the risks. Each registered entity will
undergo an Inherent Risk Assessment using characteristics of the specific entity to help determine the scope
of the compliance review. The scope of review may be further tailored for those registered entities that opt
to undergo an Internal Control Evaluation.
Texas RE will notify registered entities of upcoming compliance engagements within the timeframes required
by Appendix 4C to the NERC Rules Procedure (at least 90 days before an audit, 30 days before a SelfCertification, and 20 days before a spot check).
Texas RE will evaluate Operations and Planning Requirements and Critical Infrastructure Protection Standards
and Requirements concurrently during an engagement instead of conducting separate engagements. For
Critical Infrastructure Protection Requirements, Texas RE will refer to the approved transition guide.
Texas RE will also implement a change for use of Self-Certifications for registered entities within the Texas RE
footprint. Texas RE will require more information from entities selected to self-certify, and the SelfCertification will be limited to Standards and Requirements related to risks identified through the compliance
monitoring processes. The intent of this change is to implement RAI goals by focusing on risks and properly
leveraging the resources of registered entities and Texas RE.
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Appendix A7 - Texas Reliability Entity (Texas RE) 2015 CMEP Implementation Plan
Texas RE will use the approved Compliance Oversight Framework to determine the scope of each compliance
engagement and the method for conducting the engagement (such as by audit, Self-Certification, or spot
check). Texas RE will notify registered entities of upcoming compliance engagements within the timeframes
required by Appendix 4C to the NERC Rules Procedure (at least 90 days before an audit, 30 days before a SelfCertification, and 20 days before a spot check). The candidate list below is considered an initial list and is
subject to change.
NCR #
NCR01160
NCR01342
NCR02910
NCR04003
NCR04004
NCR04006
NCR04010
NCR04013
NCR04018
NCR04021
NCR04027
NCR04038
NCR04056
NCR04082
NCR04092
NCR04094
NCR04118
NCR04119
NCR04121
NCR04124
NCR04127
NCR04160
NCR10004
NCR10090
NCR10173
NCR10174
NCR10211
NCR10219
NCR10249
NCR11074
NCR11076
NCR11383
2015 Compliance Audit Schedule
Registered Entity
Western Farmers Electric Cooperative
Tex-La Electric Cooperative of Texas, Inc.
Nextera Energy Resources, LLC
Forest Creek Wind Farm, LLC
Sand Bluff Wind Farm LLC
American Electric Power Service Corp.
Barney M Davis Unit 1
Bluebonnet Electric Co Op, Inc.
Brownsville Public Utilities Board
Brownsville Public Utilities Board Silas Ray
Calpine Power Management, LP
CPS Energy
ERCOT ISO
Ingleside Cogeneration, LP
Lower Colorado River Authority
Magic Valley Electric Coop Inc.
San Bernard Electric Coop, Inc.
Sharyland Utilities LP
Sid Richardson Carbon LTD
South Texas Electric Cooperative, Inc.
STP Nuclear Operating Company
Weatherford Municipal Utility System
City of Georgetown
NRG Texas Power, LLC
Champion Wind Farm, LLC
Roscoe Wind Farm, LLC
Electric Transmission Texas, LLC
Luminant Generation Company, LLC
Panther Creek Wind Farm I & II, LLC
Wind Energy Transmission Texas, LLC
Lone Star Transmission, LLC
EC&R QSE, LLC
5. Compliance Outreach
Compliance Outreach Activities
Outreach Activity
Spring Compliance Workshop
Fall Compliance Workshop
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66
Anticipated Date
Spring 2015
Fall 2015
Appendix A7 - Texas Reliability Entity (Texas RE) 2015 CMEP Implementation Plan
Compliance Outreach Activities
Outreach Activity
Talk With Texas RE
Texas REview Newsletter
CIP Compliance Workshop(s)
NERC | 2015 ERO CMEP Implementation Plan Version 1.0 | November 18, 2014
67
Anticipated Date
Projected Monthly
(subject to change)
Projected Monthly
TBD
Appendix A8 - Western Electricity Coordinating Council (WECC)
2015 CMEP Implementation Plan
This Appendix contains the CMEP Implementation Plan (IP) for WECC as required by the NERC Rules of Procedure.
1. Compliance Monitoring and Enforcement
1.1 CMEP IP Highlights and Material Changes
Enhanced Regional Coordination
In 2014, WECC coordinated enforcement activities for some registered entities across multiple regions. In
addition, WECC continued to identify registered entities that could qualify for coordinated compliance and
enforcement activities under a forthcoming Multi-Regional registered entity (MRRE) Process. WECC plans to
work with NERC and the other Regions in 2015 to implement the MRRE Process as appropriate.
Departmental Reorganization: Enforcement and Compliance Risk Analysis
In 2014, the WECC Compliance Department restructured to more appropriately allocate resources to prepare
to implement the Reliability Assurance Initiative (RAI) in 2015. Subject matter experts previously working
within the WECC Enforcement Team moved to the newly created Compliance Risk Analysis functional group.
The Compliance Risk Analysis Group will continue to focus on conducting reviews and technical assessments
of all self-identified violations and mitigation plans. In addition, this group will focus on Inherent Risk
Assessments (IRAs) and Internal Controls Evaluations (ICEs) as part of the RAI.
Strengthened Settlement Process
During 2014, WECC continued to leverage information gained from risk analysis, lessons learned, best
practices, and other information to enhance monitoring and enforcement activities. For example, in
negotiating settlement agreements disposing of violations, WECC may propose reliability-focused terms
aimed at improving reliability, culture of compliance, internal controls, and internal compliance programs.
Most settlements reached in 2014 included such reliability-focused activities. In addition, WECC began
sharing best practices and lessons learned on its Compliance website during 2014 and will continue to expand
this information in 2015.
1.2 Other Regional Key Initiatives & Activities
During 2015, WECC will implement the ERO’s risk-based approach to compliance monitoring in conducting
CMEP-related activities. WECC will phase in implementation of IRA and ICE activities to help determine the
best use of its resources and understand that WECC’s processes will evolve throughout the year.
Risk-based Framework for Off-site Audits
In 2015, WECC will implement the ERO Risk-based Compliance Oversight Framework, as described in the ERO
CMEP IP, for conducting off-site audits for certain registered entities, different from the annual “one-size-fitsall” formal off-site compliance audit strategy that WECC has implemented since 2007. This tailored audit
strategy considers the inherent risks posed by the registered entities in choosing the appropriate monitoring
engagement.
WECC conducted a risk assessment of all entities scheduled for off-site audits in 2015. Based on the risk
assessment, WECC will conduct off-site audits as usual for some entities. However, for most entities otherwise
due for the off-site audit, WECC will substitute the annual Self-Certification process, combined with a focused
validation of the annual Self-Certifications. WECC plans to continue to perform all on-site audits during 2015
as scheduled.
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Appendix A8 - Western Electricity Coordinating Council (WECC) 2015 CMEP Implementation Plan
Inherent Risk Assessment (IRA) Process
WECC Compliance will perform an IRA of registered entities to identify areas of focus and the level of effort
needed to monitor compliance with NERC Reliability Standards for a particular Entity or category of Entity.
While the IRA is similar in nature to what WECC has been doing in the past several years when scoping audits,
the IRA will strengthen the process. In 2015, WECC plans to conduct IRAs for registered entities that have an
on-site audit scheduled. If resources permit, during 2015 WECC may conduct IRAs for other registered entities
as well.
Internal Controls Evaluation (ICE) Process
WECC Compliance may perform an ICE of certain registered entities to assess their internal controls, which
may further focus the level and effort needed to monitor compliance with NERC Reliability Standards for a
particular Entity. For 2015, WECC will roll out the ICE process on a limited basis. Any entity that has a
scheduled audit in third or fourth quarters 2015 may volunteer for the ICE program. WECC will contact each
such entity in early 2015 to provide more information and discuss the Entity’s options. If a registered entity
volunteers for the ICE process, WECC will evaluate its internal controls that support compliance with the
Reliability Standards. WECC will assess the strength of these controls and provides the entity with feedback.
WECC will use its evaluation of internal controls to determine the scope and depth of the compliance
monitoring activity and any potential impacts on enforcement processing of violations and mitigation plans
submitted by entities. Registered entities may elect not to participate in an ICE. In that case, WECC will use
the results of the IRA to determine the appropriate compliance monitoring strategy. WECC also will provide
more information in 2015 regarding the expansion of this program in 2016 and beyond. For Entities not
eligible for this process in 2015, WECC will work with interested entities to recommend how it could focus on
identifying, organizing, and strengthening detective, preventative and corrective controls pertaining to the
Reliability Standards. WECC will post guidance specific to its ICE review process in early 2015 and will update
ICE-related information during the year as appropriate.
Internal Compliance Program Assessment (ICPA)
WECC will continue its voluntary ICPA Program, originally launched during 2012, in 2015. The ICPA Program
is a tool Entities can but are not required to use to assist in the development of strong Internal Compliance
Programs (ICPs). WECC provides feedback, highlighting exemplary practices and providing recommendations
for improvement where appropriate. As the ICE process develops, WECC will consider merging the ICPA
process with the ICE process.
CIP v5 Implementation
In 2014, WECC made significant efforts to prepare both staff and registered entities to be compliant with CIP
v5. WECC will follow NERC’s Transition Guidance for CIP-related monitoring and enforcement during 2015, in
anticipation of the 2016 compliance date. During 2014, WECC conducted numerous outreach activities and
materials to assist registered entities in making the transition. All presentations and associated material are
available via WECC’s website.
The WECC Cyber Security Audit Team will use the NERC CIP v5 transition guidance in conjunction with the
NERC RAI program during its 2015 audit engagements. While maintaining its schedule of 2015 on-site audits,
the WECC Cyber Security Audit Team will continue to engage its registered entities, NERC and the other
Regions in ensuring a consistently applied audit approach on CIP v5.
WECC encourages registered entities to take a proactive approach in transitioning to CIP v5. If registered
entities encounter any issues in its transition, WECC encourages them to contact WECC to work through the
issues.
Physical Security Standard Implementation
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WECC has been actively engaged in CIP-014 activities during 2014, dedicating resources and leveraging key
relationships with Standard Drafting Team members and industry to inject subject matter expertise and
practical experience into both the Standard and RSAW. WECC has a number of CIP auditors with strong
physical security credentials. To share this expertise, WECC has developed and delivered multiple
presentations to both industry and other Regions, providing a “next-steps” perspective aimed at aiding
registered entities in a move toward increased security and compliance with CIP-014. Presentations and other
materials are on WECC’s website.
2. Regional Risk Assessment Process
This section provides a description of how WECC assessed risk in the Western Interconnection and determined
associated Reliability Standards for consideration its Regional compliance monitoring plan. In identifying risks,
WECC considered risks identified by NERC in its risk elements Guide for Development of the 2015 CMEP IP. In
addition, for the Western Interconnection, WECC specifically considered factors such as footprint and
registered entity characteristics, registered functions, geographic locations, system events and trends,
compliance history, SCADA systems, FERC Orders and Guidance, et al. A summary of the specific risks, and
associated standards, follows, for both Critical Infrastructure Protection (CIP) and Operations and Planning
(O&P) Standards:
3. Regional Risks and Associated Reliability Standards
The standards identified below generally will be in scope for compliance monitoring for entities to which the
standards apply, and thus they are similar to the Actively Monitored Lists in the past. During 2015, as WECC
phases in and matures its RAI-related activities, it will begin to tailor monitoring activities to more closely
match individual entity risks. WECC may contact individual Entities to provide more focused scope for audits
or Self-Certifications, for example. WECC will give priority to focusing on entities scheduled for on-site audits
during 2015, and to other Entities for which it may have conducted the Inherent Risk Analysis and, if
applicable, the Internal Controls Evaluation.
Critical Infrastructure Protection (CIP)
Over the past several years, cyber security threats have been on the rise in the electricity sector. As Entities
have become more reliant on automated systems and integrated technology, it has become more important
to identify the cyber security risks associated with using these advanced technologies. While the electric
sector has yet to experience a cyber-attack affecting reliable operation of the Bulk Power System, WECC
believes the risk of a large-scale cyber-attack is significant and must be addressed to the extent possible
through standards monitoring. To help focus compliance monitoring and enforcement efforts, WECC has
identified seven cyber security areas of risk that pose the greatest threat to the Western Interconnection.
WECC’s Compliance Risk Analysis and Cyber Security Audit teams developed the seven areas of risk identified
below. These risks were identified by considering the risks identified by NERC, the history of most violated
CIP Standards in the Western Interconnection, and WECC’s experience in conducting Cyber Security audits,
reviewing self-disclosed violations, and professional expertise of Compliance Risk Analysis and Cyber Security
Audit teams.
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Event and incident response, continuity of operations: This area relates to establishing and maintaining
plans, procedures, and technologies to detect, analyze, and respond to cyber security events.
Threat and vulnerability management: This area relates to establishing and maintaining plans,
procedures, and technologies to detect, identify, analyze, manage, and respond to cyber security threats
and vulnerabilities.
Risk management: This area relates to establishing, operating, and maintaining an enterprise cyber
security risk management program to identify, analyze, and mitigate cyber security risk to the
organization.
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Asset and configuration management: This area relates to managing an entity’s information technology
assets, including hardware and software.
Identity and access management: This area relates to creating and managing logical or physical access to
an entity’s assets.
Workforce management: This area relates to establishing and maintaining plans, procedures,
technologies, and controls to create a culture of cyber security and to ensure the ongoing suitability and
competence of personnel.
Situational awareness: This area relates to establishing and maintaining activities and technologies to
collect, analyze, alarm, present, and use power system and cyber security information, including status
and summary information.
As part of this project, WECC also identified the CIP Standards most commonly associated with these areas of
risk. Based on the degree of association of the CIP Standards with a given risk area, WECC created a list of
Standards most closely associated with these areas of risk:
CIP Reliability Standards Subject to WECC Monitoring
Regional Risk
Focus Area
Event and
incident response,
continuity of
operations
Justification
It is essential for registered entities to develop plans to
respond to cyber-security events. Failure to do so could
significantly increase the exposure of the threat and
time a realized threat exists. Significant impact could
occur if entities cannot properly and quickly respond to
threats. This area has been reported on as needing
attention in the NERC Cyber Attack Task Force final
report and the ERO Priorities – RISC Updates and
Recommendations report.
Threat and
Not having procedures to detect and respond to cyber
vulnerability
vulnerabilities could adversely affect organizational
management
operations, including logical and physical assets. This
risk area has been highlighted in the NERC Cyber Attack
Task Force final report, ERO Priorities – RISC Updates
and Recommendations report, 2013 Long-Term
Reliability Assessment report, and ERO Top Priority
Reliability Risks 2014-2017 report.
Risk management A risk management program that oversees an
organization’s cyber security risk could have far reaching
affects throughout all the entity's cyber security
programs to mitigate threats both physical and logical.
This area makes the foundation of a registered entity’s
cyber security framework. The DOE guide “Risk
Management Process” highlights the need for cyber
security risk management being a part of an
organization’s mission and business requirement.
Standard & Requirement
CIP-007 R6
CIP-008 R1
CIP-009 R2
CIP-005 R4
CIP-007 R8
CIP-008 R1
CIP-002 R1
CIP-008 R1
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CIP Reliability Standards Subject to WECC Monitoring
Regional Risk
Focus Area
Asset and
configuration
management
Identity and
access
management
Situational
awareness
Justification
Not knowing which assets are performing critical
functions for the entity could lead to misconfigured
assets and lack of necessary protections for those assets.
Since asset configurations impact the security and
operation of every asset, it is critical to properly account
for, and manage this area.
Standard & Requirement
CIP-002 R2
CIP-002 R3
CIP-003 R6
CIP-005 R1
CIP-007 R1
CIP-007 R2
CIP-007 R3
CIP-007 R4
CIP-004 R4
CIP-005 R2
CIP-006 R1
CIP-006 R4
CIP-007 R5
Identity and access management is one of the most
important components of a registered entity’s security
infrastructure. An entity’s information assets must be
accessible only to individuals who are granted explicit
entitlements to specific information. Failure to manage
identity and access to cyber assets could allow malicious
individuals to have access to key facilities, devices and
services.
Not having information about an entity’s systems does CIP-005 R3
not allow the entity to take corrective actions to detect CIP-006 R5
and prevent failure and compromise. It is essential for CIP-007 R6
registered entities to have awareness about their
environment. Failing to do so could them from being
protected against attacks. The RISC’s ERO Priorities –
RISC Updates and Recommendations report, NERC’s
ERO Top Priority Reliability Risks 2014-2017 report, and
the Cyber Attack Task Force final report highlight this
concern.
Operations and Planning (O&P)
The O&P Audit team and Compliance Risk Analysis team have identified areas of risk to the Western
Interconnection. These risks were identified by considering the risks identified by NERC documents (ERO Top
Priority Reliability Risks 2014-2017 and 2015 ERO Compliance Monitoring and Enforcement Implementation
Plan), history of most violated Operations and Planning Standards in the Western Interconnection, Event
analysis reports, WECC’s experience in conducting Operations and Planning audits, reviewing self-disclosed
violations, and professional expertise of WECC Compliance Risk Analysis and Operations and Planning Audit
teams.
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Human Performance: This area relates to a range of issues facing the electricity industry today, including
the imminent loss of critical skills and knowledge with the retirement of an aging workforce, cognitive
overload of System Operators complicating the task of maintaining reliability, and an apparent shift in
operating philosophy toward operating to standards rather than to reliability.
Equipment Failure: This area relates to equipment failure due to aging infrastructure of generation
facilities, transmission facilities, and substations. In addition to this, there is a risk associated with failure
of adequate coordination with other entities and consideration of impact on the BPS.
Changing Resources: Variable Generation Integration: This area refers to the composition of installed
electric generation capacity that makes up the resource portfolio. Additionally this area also refers to the
challenges faced due to integration of variable generation, planning for changes in system composition,
replacing retired capacity or coal generation.
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Protection System Reliability: This area relates to Special Protection Scheme/Remedial Action Scheme
(SPS/RAS) effectiveness, SPS/RAS proliferation, misoperation of the protection system devices, and
increasing RAS events. In addition to this, there is a risk associated with failure of adequate coordination
with other entities and consideration of impact on the BPS.
Situational Awareness: Situational awareness refers to the ability to see and comprehend what is
happening on the system. This area relates to importance of including Real-Time Contingency Analysis
(RTCA) Tools, next-day studies in planning studies. It also relates to inadequate data coordination, data
failure, data shrinkage (unexpected outages of tools providing data to operators) leading to operators not
having enough visibility to some or all the system they operate.
Changing Load Composition: This area relates to changing load shape, changing load patterns, increased
A/C penetration like plug-in vehicles.
Vegetation and Right of Way issues: This area relates to outages that are caused due to inability to
maintain vegetation like grow-in issues in the transmission line or Right of Way clearance issues. It refers
to recently approved new NERC standard that specifically relates to the outages caused due to
interrelationship between vegetation growth rates, vegetation control methods and inspection frequency
which if ignored might lead to encroachment into minimum vegetation clearance distances. This can lead
to loss of load or generation.
Transmission Planning Adequacy: This area relates to need and importance of transmission study models
in forecasting and monitoring load, transmission, generation, and facility devices.
High-Impact Low-Frequency Events: This area relates to specific events that might not happen frequently
but might pose a higher impact to the reliability of the BPS.
Adequacy of Reserves: This area relates to changing Reserve Sharing requirements due to increasing risk
of distributed generation, retirement of certain generations due to environmental regulations.
As a result of this project, WECC identified the O&P Standards most commonly associated with these areas of
risk. Based on the degree of association of the O&P Standards with a given risk area, WECC created a list of
Standards most closely associated with these areas of risk:
O&P Reliability Standards Subject to WECC Monitoring
Regional Risk
Focus Area
Human
Performance
Justification
Standard & Requirement
Human Error has been responsible for many historical COM-002-2 R2
outages. Human performance challenges encompass a PER-005-1 R3
range of issues including the imminent loss of critical
skills and knowledge with the retirement of an aging
workforce, cognitive overload of System Operators
complicating the task of maintaining reliability, and an
apparent shift in operating philosophy toward operating
to standards rather than to reliability. These issues are
pervasive and require coordinated industry efforts to
address.
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O&P Reliability Standards Subject to WECC Monitoring
Regional Risk
Justification
Standard & Requirement
Focus Area
Equipment Failure As the components of the BPS continue to age, the FAC-501-WECC-1 R3
likelihood of failure increases. Additionally, engineering PRC-005-1 R2
margins have been minimized through advances in PRC-005-2 R3
technology which means that BPS components PRC-005-2 R4
construction practices are less robust. For example, a PRC-008-0 R1
1940’s transformer may have been over-built to take PRC-008-0 R2
system changes, but today’s transformers are built with PRC-011-0 R1
thinner margins and are less likely to withstand system PRC-017-0 R1
dynamics as well. Hence, tracking the rate of occurrence
aids industry in understanding and identifying potential
systemic issues, such as manufacturing flaws or
operational practices.
Changing
Resources:
Variable
Generation
Integration
The 2013 and 2014 NERC State of Reliability Reports
identified AC substation equipment failure as significant
contributors to disturbance events, with a positive
correlation to increased transmission outage severity.
With the increased installation of variable generation,
fluctuations in generation and load increase the
dependency of system reserves, peaking plants, and
energy storage systems. Also, as generation and load
fluctuate, facilities need to ramp up and down more
frequently increasing maintenance requirements and
the risk of mechanical and electrical failures.
BAL-002-WECC-2 R1
BAL-002-WECC-2 R2
BAL-002-WECC-2 R3
BAL-002-WECC-2 R4
As more renewable resources are brought online and
traditional resources are decommissioned, the available
rotating inertia and base-load is reduced which may
increase the risk to BES stability.
Maintaining resource adequacy will be an ongoing
challenge as the resource mix changes. As noted in the
WECC annual Power Supply Assessment Report’s
current projection, the reserve margins will be adequate
for the next seven to ten years. Changes outside the
assumptions used in resource adequacy evaluations
could present challenges.
Coal plants are also used for base loading. With the
expansion in variable generation, base load plants are
needed to provide operating reserves during periods of
generation fluctuations (solar and wind). The loss of
these plants will increase generation availability risk and
grid volatility.
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O&P Reliability Standards Subject to WECC Monitoring
Regional Risk
Justification
Standard & Requirement
Focus Area
Protection System A failure of the protection system reliability could result PRC-001-1.1 R3
Reliability
in increased risk of cascading events, system instability, PRC-001-1.1 R4
and interconnection separations. While protection PRC-001-1.1 R5
systems continue to be upgraded to microprocessor PRC-001-1.1 R6
based systems, the older Electro-Mechanical and solid PRC-004-2.1a R1
state designs are still used and, given their age, impose PRC-004-2.1a R2
a risk to reliability.
PRC-004-WECC-1 R1
PRC-004-WECC-1 R2
Additionally, interaction of Remedial Action Scheme PRC-005-1 R2
(RAS) poses a challenge. RAS are designed and tested for PRC-005-2 R3
specific systems or parts of systems, so their operation PRC-005-2 R4
in protecting those systems is well understood. But PRC-008-0 R1
understanding of how RAS interact or impact one PRC-008-0 R2
another is less well understood. Evaluating the potential PRC-011-0 R1
interactions, and then managing those interactions that PRC-016-0.1 R1
present a risk, is important for reliability.
PRC-016-0.1 R2
PRC-017-0 R1
PRC-023-3 R1
PRC-025-1 R1
Situational
Situational Awareness refers to the ability to see and COM-002-2 R1
Awareness
comprehend what is happening on the system. There EOP-010-1 R2
are a number of processes necessary to maintaining EOP-006-2 R1
situational awareness, including real-time monitoring EOP-006-2 R9
and real-time and near-term contingency analysis EOP-006-2 R10
studies. The coordination and sharing of data is critical EOP-008-1 R3
to situational awareness because each process relies on EOP-008-1 R4
various types of data. The lack of adequate situational IRO-002-2 R6
awareness limits entities’ ability to identify and plan for IRO-002-2 R7
the next most critical contingency, which, in turn, IRO-002-2 R8
impacts the reliability of the entire system.
IRO-005-3.1a R1
IRO-008-1 R1
IRO-008-1 R2
PER-005-1 R3
TOP-002-2.1b R4
TOP-002-2.1b R11
TOP-002-2.1b R19
TOP-004-2 R6
TOP-006-2 R2
TOP-007-WECC-1a R1
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O&P Reliability Standards Subject to WECC Monitoring
Regional Risk
Focus Area
Changing Load
Composition
Justification
Load composition refers to the combination of energy
consumption patterns, e.g., peaks, and types of
demand, e.g., residential or commercial. Both
consumption patterns and types of demand are
changing. Future changes to load composition could
present operational and planning challenges like
mechanism for reducing demand, mechanism for
removing load, high penetration of new types of
demand and load changes that affect stability
considerations.
Vegetation and
Vegetation management and Right of Way issues refer
Right of Way
to the encroachment of vegetation due to lack of
issues
trimming or due to incorrect clearances of the
transmission lines. Aging transmission lines might not
adhere to the minimum clearances. Having less
clearance along with vegetation growth issues could
lead to vegetation related outages. Per NERC Technical
Reference, trees that have grown out of specification
could contribute to a cascading grid failure, especially
under heavy electrical loading conditions.
Transmission
Maintaining a healthy transmission system is vital for
Planning
reliability of the grid. Transmission Planning adequacy
Adequacy
refers to accuracy and reliability of various study models
to study load forecast, transmission system behavior for
addition or retirement of generating facilities and facility
designs. A coordinated and accurate transmission model
becomes important for identifying system behaviors and
planning for future load demand. Additionally, planning
and operational models that use different
representations lead to inconsistent understanding of
contingencies and duplication of modeling efforts, both
of which may lead to inaccurate prediction of power
system behavior.
High-Impact Low- High-impact low-frequency events refer to events such
Frequency Events as coordinated physical or cyber-attack, pandemic,
geomagnetic disturbance, or large-scale disasters. A
coordinated attack on the electric system could result in
damage to key systems and components and render
part or all of the system inoperable for an extended
period of time.
Standard & Requirement
BAL-002-WECC-2 R1
BAL-002-WECC-2 R2
BAL-002-WECC-2 R3
BAL-002-WECC-2 R4
PER-005-1 R3
TPL-001-0.1 R1
TPL-002-0b R1
TPL-003-0b R1
TPL-004-0a R1
FAC-003-3 R1
FAC-003-3 R2
FAC-003-3 R6
FAC-003-3 R7
FAC-014-2 R5
FAC-014-2 R6
TOP-004-2 R6
TOP-006-2 R2
TOP-008-1 R4
TPL-001-0.1 R1
TPL-002-0b R1
TPL-003-0b R1
TPL-004-0a R1
EOP-001-2.1b R2
EOP-001-2.1b R3
EOP-001-2.1b R4
EOP-003-2 R8
EOP-005-2 R1
EOP-005-2 R6
EOP-005-2 R9
EOP-005-2 R10
EOP-005-2 R11
EOP-005-2 R17
EOP-006-2 R1
EOP-006-2 R9
EOP-006-2 R10
EOP-008-1 R3
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O&P Reliability Standards Subject to WECC Monitoring
Regional Risk
Focus Area
Adequacy of
Reserves
Justification
Plant retirements due to implemented environmental
regulations increase uncertainty in future resources.
Additionally, other potential environmental regulations
are leading to cases where resources may be inadequate
to ensure firm demand is served at all times. As the
system continues to change, some concerns are
identified with insufficient reserve margins by some
entities.
Standard & Requirement
EOP-008-1 R4
PER-005-1 R3
BAL-002-WECC-2 R1
BAL-002-WECC-2 R2
BAL-002-WECC-2 R3
BAL-002-WECC-2 R4
4. Compliance Oversight Plan
WECC will perform all on-site audits during 2015 as scheduled, as required by the NERC Rules of Procedure.
Entities scheduled for on-site audits during 2015 are included in the table titled “2015 Audit Schedule” below.
For all such audits, WECC will apply a risk-based approach in accordance with the RAI.
For Entities due for an off-site audit during 2015, WECC has conducted a risk assessment. Based on that
assessment, WECC has, for most of these entities, substituted the annual Self-Certification process for
reporting year 2014 combined with a focused validation of the Self-Certifications. WECC will conduct off-site
audits as scheduled for all other Entities. Entities still scheduled for an off-site audit are included in the 2015
Audit Schedule below
Compliance Audits
WECC will conduct scheduled Compliance Audits for 2015 using the Reliability Standard Requirements listed
in the tables titled “CIP Reliability Standards Subject to WECC Monitoring” and “O&P Reliability Standards
Subject to WECC Monitoring” in Section 3 above (collectively, the “Reliability Standards Subject to WECC
Monitoring in 2015”) as a baseline, as well as an Entity’s Registered Functions. A summarized list of CIP and
O&P Reliability Standards subject to Audit for 2015 is included in the Reliability Standards Subject to WECC
Monitoring – 2015 document on the WECC website. The scope of each audit, however, may be adjusted
based on WECC’s risk IRA (and ICE if available) of the registered entity.
Annual Self-Certification
As noted in WECC’s 2014 CMEP Implementation Plan, the annual Self-Certification for reporting year 2014 will
begin December 15, 2014, when WECC will post the Self-Certification Schedule and Forms and send
notification to registered entities. The submittal period will run from January 1 through March 2, 2015.
In 2016, WECC will conduct the annual Self-Certification for reporting year 2015. WECC will post the SelfCertification Schedule and Forms and send the Self-Certification notification to registered entities on
December 15, 2015. The notification will inform Entities of the reporting period (January 1 through December
31, 2015) and the submittal period (January 1 through March 1, 2016), as well as provide information on the
Reliability Standard Requirements covered. Subject to an entity’s Registered Functions, the Reliability
Standards Requirements for Self-Certification will be determined, in part, by those listed in the tables titled
“CIP Reliability Standards Subject to Regional Monitoring” and “O&P Reliability Standards Subject to Regional
Monitoring” in Section 3 above. In addition, Reliability Standard Requirements listed in the table titled
“Additional Reliability Standards Subject to Self-Certification” below is included to make up the SelfCertification baseline. A summarized list of Reliability Standards subject to Self-Certification for 2015 is
included in the Reliability Standards Subject to WECC Monitoring – 2015 document on the WECC website. The
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scope of each Self-Certification, however, may be adjusted based on WECC’s IRA (and ICE if available) of the
registered entity.
WECC may also validate the accuracy of Self-Certification submittals of Compliant, Not Applicable and/or Do
Not Own through various analyses, including sending data requests to registered entities for randomly
selected Self-Certifications for certain Reliability Standard Requirements and Registered Functions.
Additional Reliability Standards Subject to Self-Certification
Regional Risk
Focus Area
Repeat Violations
Justification
Reliability Standard Requirements with repeat violations
over the most recent 12-month period can be one
indication of the possibility of increased risk. These
Standard Requirements are included in addition to those
listed in the tables in Section 3 titled “CIP Reliability
Standards Subject to Regional Monitoring” and “O&P
Reliability Standards Subject to Regional Monitoring” to
form the baseline of Reliability Standard Requirements
subject to Self-Certification for reporting year 2015.
Standard & Requirement
CIP-002 R4
CIP-003 R2
CIP-004 R3
CIP-005 R5
CIP-006 R2
CIP-006 R6
CIP-007 R9
CIP-009 R5
EOP-001 R5
FAC-008 R2
FAC-008 R3
FAC-010 R1
FAC-010 R4
FAC-010 R3
IRO-010 R3
PER-005 R1
PRC-005 R1
VAR-001 E.A.14
VAR-002 R3
VAR-002 R2
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Periodic Data Submittals (PDS)
As part of the CMEP, registered entities must submit Periodic Data Submittals (PDS) on schedules required
by applicable Reliability Standards, or as established by NERC, or on an as-needed basis where requested by
WECC. These Reliability Standards are listed in the table below titled Reliability Standards Subject to
Periodic Data Submittal. A summarized list at the Sub-Requirement level is also included in the Reliability
Standards Subject to WECC Monitoring - 2015 on the WECC website.
Reliability Standards Subject to Periodic Data Submittal
Justification
Standard & Requirement
These Reliability Standards include requirements for registered entities with BAL-001-1 R1
applicable Registered Functions to submit data on a periodic basis as BAL-001-1 R2
indicated in the Requirement or relevant Sub-Requirement.
BAL-002-1 R1
BAL-002-1 R2
BAL-002-1 R3
BAL-002-1 R4
BAL-002-1 R5
BAL-002-1 R6
BAL-003-0.1b R1.2
BAL-006-2 R4
COM-002-2 R2
EOP-004-2 R2
FAC-003-3 R1
FAC-003-3 R2
FAC-003-3 R6
FAC-003-3 R7
IRO-006-WECC-1 R1
IRO-006-WECC-1 R2
PRC-004-2.1a R3
PRC-004-WECC-1 R3
PRC-021-1 R1
PRC-023-3 R5
PRC-023-3 R6
TPL-002-0b R3
TPL-003-0b R3
TPL-004-0a R2
VAR-002-WECC-1 R1
VAR-002-WECC-1 R2
VAR-501-WECC-1 R1
VAR-501-WECC-1 R2
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Appendix A8 - Western Electricity Coordinating Council (WECC) 2015 CMEP Implementation Plan
2015 Audit Schedule
Note that the WECC audit schedule may be revised from time to time during 2015. Thus, the “2015 Audit
Schedule” shown below for both on-site and off-site audits applies only as of November, 2014. The most
up-to-date audit schedule, including all revisions and updates, is on the WECC’s website here: WECC 2015
Audit Schedule. The on-line schedule should be consulted to ensure accuracy as this 2015 IP will not be republished and re-posted to reflect each change to the audit schedule during 2015.
2015 Audit Schedule
NCR #
NCR05335
NCR11458
NCR10292
Registered Entity
Public Utility District No. 1 of Snohomish County
RockTenn
Shiloh Wind Project 2, LLC
NCR05402
Southwest Transmission Cooperative, Inc.
NCR05321
NCR05441
NCR05441
NCR10310
NCR10311
NCR10347
NCR11150
NCR10289
NCR05282
NCR05153
NCR05106
NCR05465
NCR05430
NCR10323
NCR11054
NCR10350
Platte River Power Authority
US Bureau of Reclamation
US Bureau of Reclamation
Brush Cogeneration Partners
Colorado Energy Management - BCP
Panoche Energy Center LLC
GenOn Delta
Peak Reliability
NorthWestern Corporation
Eugene Water & Electric Board
Colorado Springs Utilities
Western Area Power Administration - Sierra Nevada Region
Transmission Agency of Northern California
Midway Peaking, LLC
South Feather Power Project
Windy Flats Partners, LLC
Tri-State Generation and Transmission Association, Inc. Reliability
Intermountain Rural Electric Association
San Diego Gas & Electric
Pend Oreille County Public Utility District No. 1
Sunray Operating Services, LLC
EthosEnergy Group
Three Buttes Windpower LLC
Black Hills Corporation
Klickitat County PUD
NextEra Energy Resources, LLC
Idaho Power Company
Rocky Mountain Reserve Group
Northwest Power Pool Reserve Sharing Group
Colorado Energy Management - MPC
Western Area Power Administration - Rocky Mountain Region
Basin Electric Power Cooperative
NCR10030
NCR11226
NCR05377
NCR05315
NCR10348
NCR10349
NCR10345
NCR05030
NCR05206
NCR05163
NCR05191
NCR05366
NCR05281
NCR10378
NCR05464
NCR05023
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Appendix A8 - Western Electricity Coordinating Council (WECC) 2015 CMEP Implementation Plan
2015 Audit Schedule
NCR #
NCR05315
NCR05299
NCR05398
NCR10396
NCR11104
NCR05377
NCR05299
NCR05048
NCR03036
Registered Entity
Pend Oreille County Public Utility District No. 1
Pacific Gas and Electric Company
Southern California Edison - Transmission & Distribution
Business Unit
Otay Mesa Energy Center, LLC
NAES Corporation - Harvest Wind Project
San Diego Gas & Electric
Pacific Gas and Electric Company
California Independent System Operator
Trans Bay Cable LLC
5. Compliance Outreach
WECC conducts seminars and workshops for Registered Entities to assist them in their compliance activities.
The seminars and workshops are important learning exercises for those subject to Reliability Standards.
During 2015, WECC will continue its outreach efforts to provide education, seminars, workshop and panel
discussions to increase registered entities’ awareness of and understanding of Reliability Standards. A few
of WECC's outreach efforts are as follows:
Compliance Outreach Activities
Outreach Activity
Compliance User Group (CUG)/Critical Infrastructure Protection User Group
(CIPUG)
Compliance User Group (CUG)/Critical Infrastructure Protection User Group
(CIPUG)
Compliance User Group (CUG)/Critical Infrastructure Protection User Group
(CIPUG)
CIP 101 Seminar
CIP Low Impact Assets Seminar
WECC Open Webinar
Compliance 101 Webinar
Anticipated Date
January 27-29, 2015
Anaheim, CA
June 2-4, 2015
Portland, OR
October 13-15, 2015
San Diego, CA
Sept. 9-10, 2015
Salt Lake City, UT
Feb. 3-5, 2015
Salt Lake City, UT
Third Thursdays of most
months
Three times a year prior
to CUG/CIPUG
Monthly Open Webinars
Since many of the questions the WECC Compliance Staff receives are very similar, WECC answers questions
in an open forum for greater efficiency. WECC Compliance Subject Matter Experts participate on this
webinar and respond to questions. In fairness to everyone on the call, WECC does not address entityspecific questions and issues.
Compliance User Group (CUG)
The CUG meeting provides in-depth, in-person, and detailed training and education through structured
lecture and presentation, panels of experts, interactive dialog in an open forum, direct question and
answer sessions and invaluable networking opportunities. Workshops cover the entire compliance sphere
with focus reflecting the attendees’ and industries’ issues. These meetings provide direct access to the
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Appendix A8 - Western Electricity Coordinating Council (WECC) 2015 CMEP Implementation Plan
WECC Compliance management team, staff, and Subject-Matter Experts. Participants may also attend
telephonically or via webinar.
Critical Infrastructure Protection User Group (CIPUG)
The mission of the CIPUG is to provide an open forum for the exchange of information regarding the WECC
Compliance Program's enforcement of mandatory CIP Standards in the Western Interconnection. Its
meetings are structured similarly to those of the Compliance User Group, and it is a forum for WECC to
provide information regarding NERC and WECC CIP activities and related training and workshops for
registered entities on an as-needed basis.
Information for these workshops and seminars (and others as they are finalized) and the dates on which
they are scheduled to occur will be posted on the WECC website.
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Appendix B - Compliance Assessment Report
Compliance Assessment Process for Events and Disturbances
The ERO encourages registered entities to perform an initial compliance assessment (CA) concurrent with the
registered entity’s event review and analysis. When completing a CA, the registered entity should follow these
steps:
1. Refer to the causes and contributing factors of the event as determined by the registered entity’s events
analysis process.
2. Identify all applicable NERC Reliability Standards and Requirements that may have been implicated by the
causes and contributing factors of the event.
3. After reviewing the facts and circumstances of the event, develop conclusions that are relevant to step 2
above as they apply to the applicable NERC Reliability Standards Requirements.
4. Self-report any findings of noncompliance to the RE per the CMEP procedures.
5. Provide a copy of its CA report to the RE Compliance organization. The CA should be accompanied by the
separate Event Analysis Report, “Brief Report,” or similar document that provides sufficient information
for the RE to understand the event.
Sample Compliance Assessment Report Template
Event Cause or
Contributing Factor
Applicable Reliability Standards
and Requirements
Cause–Example 1
AAA-000-0 R 1
Details of CA Efforts
1. Identify the process used to assess
compliance with this Requirement.
Findings
Finding conclusion
2. Identify any evidence that
demonstrates compliance
Equipment failure of
a high side
transformer—
cleared along with
two transmission
lines.
TOP-002-2a
R6. Each BA and TOP shall plan to
meet unscheduled changes in
system configuration and
generation dispatch (at a
minimum N-1 contingency
planning) in accordance with
NERC, Regional Reliability
Organization, sub-regional and
local reliability Requirements
3. Identify any evidence that suggests
noncompliance
Established transfer limits were
followed such that the event did not
result in instability. The limit for
operating across this internal interface
is established in the RC. “XYZ Interface
All Lines In Stability Guide” (document
provided)
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No findings of
noncompliance
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