Click here for: Webinar Registration. Introductions and Chair s Remarks. NERC Antitrust Compliance Guidelines and Public Meeting Notice* Agenda

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1 Agenda Member Representatives Committee Pre-Meeting Informational Session Conference Call and Webinar July 16, :00 a.m. 1:00 p.m. Eastern Conference Line: Access Code: Broadcast Audio: Click here for: Webinar Registration Introductions and Chair s Remarks NERC Antitrust Compliance Guidelines and Public Meeting Notice* Agenda 1. Opening Remarks 2. Schedule of Quarterly NERC Meetings and Conference Calls* 3. Topics for the Board of Trustees, Board Committees and MRC Meetings* August 13-14, Overview of the Items Included in the Policy Input Letter a. Reliability Assurance Initiative (RAI)* b. Risk-Based Registration Initiative* c. Critical Infrastructure Protection (CIP) Version 5 Transition* d. Cybersecurity Risk Information Sharing Program (CRISP)* 5. Informational Items a. Long-Term Reliability Assessment and Emerging Issues Update* b. Polar Vortex Report Update* *Background materials included.

2 Antitrust Compliance Guidelines I. General It is NERC s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably restrains competition. This policy requires the avoidance of any conduct that violates, or that might appear to violate, the antitrust laws. Among other things, the antitrust laws forbid any agreement between or among competitors regarding prices, availability of service, product design, terms of sale, division of markets, allocation of customers or any other activity that unreasonably restrains competition. It is the responsibility of every NERC participant and employee who may in any way affect NERC s compliance with the antitrust laws to carry out this commitment. Antitrust laws are complex and subject to court interpretation that can vary over time and from one court to another. The purpose of these guidelines is to alert NERC participants and employees to potential antitrust problems and to set forth policies to be followed with respect to activities that may involve antitrust considerations. In some instances, the NERC policy contained in these guidelines is stricter than the applicable antitrust laws. Any NERC participant or employee who is uncertain about the legal ramifications of a particular course of conduct or who has doubts or concerns about whether NERC s antitrust compliance policy is implicated in any situation should consult NERC s General Counsel immediately. II. Prohibited Activities Participants in NERC activities (including those of its committees and subgroups) should refrain from the following when acting in their capacity as participants in NERC activities (e.g., at NERC meetings, conference calls and in informal discussions): Discussions involving pricing information, especially margin (profit) and internal cost information and participants expectations as to their future prices or internal costs. Discussions of a participant s marketing strategies. Discussions regarding how customers and geographical areas are to be divided among competitors. Discussions concerning the exclusion of competitors from markets. Discussions concerning boycotting or group refusals to deal with competitors, vendors or suppliers.

3 Any other matters that do not clearly fall within these guidelines should be reviewed with NERC s General Counsel before being discussed. III. Activities That Are Permitted From time to time decisions or actions of NERC (including those of its committees and subgroups) may have a negative impact on particular entities and thus in that sense adversely impact competition. Decisions and actions by NERC (including its committees and subgroups) should only be undertaken for the purpose of promoting and maintaining the reliability and adequacy of the bulk power system. If you do not have a legitimate purpose consistent with this objective for discussing a matter, please refrain from discussing the matter during NERC meetings and in other NERC-related communications. You should also ensure that NERC procedures, including those set forth in NERC s Certificate of Incorporation, Bylaws, and Rules of Procedure are followed in conducting NERC business. In addition, all discussions in NERC meetings and other NERC-related communications should be within the scope of the mandate for or assignment to the particular NERC committee or subgroup, as well as within the scope of the published agenda for the meeting. No decisions should be made nor any actions taken in NERC activities for the purpose of giving an industry participant or group of participants a competitive advantage over other participants. In particular, decisions with respect to setting, revising, or assessing compliance with NERC reliability standards should not be influenced by anti-competitive motivations. Subject to the foregoing restrictions, participants in NERC activities may discuss: Reliability matters relating to the bulk power system, including operation and planning matters such as establishing or revising reliability standards, special operating procedures, operating transfer capabilities, and plans for new facilities. Matters relating to the impact of reliability standards for the bulk power system on electricity markets, and the impact of electricity market operations on the reliability of the bulk power system. Proposed filings or other communications with state or federal regulatory authorities or other governmental entities. Matters relating to the internal governance, management and operation of NERC, such as nominations for vacant committee positions, budgeting and assessments, and employment matters; and procedural matters such as planning and scheduling meetings. NERC Antitrust Compliance Guidelines 2

4 MEETING LOCATION The Westin Bayshore NERC Third Quarter 2014 Meetings 1601 Bayshore Drive Schedule of Events Industry Vancouver, BC V6G 2V4 August 13-14, 2014 Vancouver, BC Canada All times are Pacific unless otherwise noted. Meetings and Conference Calls Prior to August Quarterly Meetings July 16, 2014; 11:00 a.m. 1:00 p.m. Eastern Member Representatives Committee Informational Webinar July 17, 2014; 10:30 a.m. 12:00 p.m. Eastern Finance and Audit Committee Business Plan and Budget Webinar Wednesday, August 13, :30 a.m. 8:30 a.m. Room name: TBD 8:45 a.m. 9:45 a.m. Room name: TBD 10:00 a.m. 11:00 a.m. Room name: TBD 11:15 a.m. 12:15 p.m. Room name: TBD 12:15 p.m. 1:15 p.m. Room Name: TBD 1:15 p.m. 5:15 p.m. Room name: TBD 5:30 p.m. Room name: TBD 8:30 a.m. 12:00 p.m. Room name: TBD Corporate Governance and Human Resources Committee OPEN Meeting Finance and Audit Committee OPEN Meeting Compliance Committee OPEN Meeting Standards Oversight and Technology Committee OPEN Meeting Lunch Member Representatives Committee OPEN Meeting Reception Thursday, August 14, 2014 Board of Trustees OPEN Meeting

5 Member Representatives Committee (MRC) Pre-Meeting and Informational Webinar July 16, 2014

6 Objectives Pre-Meeting and Informational Session Review preliminary agenda topics for August 13 MRC meeting Review preliminary list of agenda topics for the Board of Trustees (Board) and associated Board committee meetings (August 13-14, 2014) Receive updates on emerging and informational issues as part of today s informational webinar 2

7 Conference Calls, Prior to Vancouver Finance and Audit Committee Webinar, July 18 (10:30 a.m., Eastern) NERC and Regional Entities 2015 business plans and budgets 3

8 Corporate Governance and Human Resources Committee 7:30 8:30 a.m., August 13 Review savings and investment plan audit Review annual Board assessment Review criteria for Board composition Review employee reporting and document retention policies 2014 corporate goals update Staffing and recruiting update 4

9 Finance and Audit Committee 8:45 a.m. 9:45 a.m., August 13 Second quarter statement of activities CRISP/ISAC update NERC and Regional Entity proposed 2015 business plans and budgets and associated assessments Long-term assessment stabilization initiative 5

10 Compliance Committee 10:00 a.m. 11:00 a.m., August 13 Reliability Assurance Initiative (RAI) progress report Inherent risk assessment and risk element steps Timeline for documenting internal controls evaluation Timeline for training Schedule for full deployment and execution Enforcement program updates Physical security implementation Key compliance and enforcement trends 6

11 Standards Oversight and Technology Committee 11:15 a.m. 12:15 p.m., August 13 CIP Version 5 standard development process ERO Enterprise IT application strategy update Geomagnetic disturbance mitigation standard update Definition of Bulk Electric System implementation update Reliability Standard Audit Worksheet revision process update Review standards quarterly status report 7

12 Member Representatives Committee 1:15 5:15 p.m., August 13 Update from Board of Trustees Nominating Committee Schedule for MRC officer and sector elections Responses to the Board s request for policy input Reliability Assurance Initiative (RAI) Risk-Based Registration Initiative Critical infrastructure protection (CIP) version 5 transition Cybersecurity Risk Information Sharing Program (CRISP) Policy discussion of key items from the Board committees Issues discussed during CGHR, FAC, BOTCC, and SOTC Polar vortex report update CO2 strategic discussion 8

13 Committee membership and charter changes Standards items for adoption/approval FAC-001-2, FAC-002-2, NUC-001-3, PRC Section 1600 data requests: misoperations and critical infrastructure protection NPCC and WECC standards process manual revisions Approve WECC bylaws and data request process Approve FRCC bylaws Cybersecurity Risk Information Sharing Program Board of Trustees 8:30 a.m., August 14 ERO Enterprise Operating Model action items update 9

14 NATF reliability activities 345 kv breaker alert Effort to address misoperations 2014 GridSecCon Alberta Electric System Operator activities Update on Canadian Affairs Committee, forum and group reports Quarterly updates Approve SOTC mandate amendments Accept second quarter statement of activities Approve NERC s 2015 business plan and budget Board of Trustees 8:30 a.m., August 14 Approve Regional Entities and WIRAB 2015 business plans and budgets 10

15 July 16 MRC Informational Session Overview of Policy Input Letter items Reliability Assurance Initiative (RAI) Risk-Based Registration Initiative Critical infrastructure protection (CIP) version 5 transition Cybersecurity Risk Information Sharing Program (CRISP) Long-term reliability assessment and emerging issues update Polar vortex report status 11

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17 Agenda Item 4a MRC Informational Session July 16, 2014 Reliability Assurance Initiative (RAI) Action Information Background The goal of RAI is to fully implement a risk-based program for compliance monitoring and enforcement of Reliability Standards that provides reasonable assurance through compliance monitoring, appropriate deterrence through enforcement, and a feedback loop to improve Reliability Standards. The case for a risk-based approach has been previously outlined by the ERO Enterprise in its white paper Incorporating Risk Concepts into the Implementation of Compliance and Enforcement. 1 Essentially, it is not practical, effective or sustainable for the ERO Enterprise to monitor all compliance issues to the same degree or to treat all noncompliance in the same manner. Compliance monitoring and enforcement must be right-sized based on a number of considerations, discussed further below, including risk factors and Registered Entity management practices related to the detection, assessment, mitigation and reporting of noncompliance. Compliance Monitoring The end state for the compliance monitoring program involves the use of risk based audit and monitoring practices similar to those utilized in other industries. The scope, method and frequency of monitoring engagements are based on a common ERO Enterprise approach to assess a Registered Entity s risk to the reliability of the Bulk Power System (BPS) and is further refined based on the strength of the Registered Entity s management controls related to compliance with Reliability Standards. The RAI activities associated with the compliance monitoring program have resulted in the development of a common framework for oversight of Registered Entities, based on the identification of risk elements, assessment of an entity s inherent risk and evaluation of internal controls, where appropriate, each of which enables the appropriate choice and scoping of compliance monitoring and enforcement program (CMEP) tools. Each of these are discussed under the status of compliance monitoring activities below. Enforcement The end state for the enforcement program involves reserving the enforcement process for those issues that pose a serious or substantial risk to the reliability of the BPS and, as to other issues, allowing NERC and the Regional Entities to exercise appropriate discretion whether to initiate an enforcement action or address an issue outside of enforcement. Therefore, RAI will 1 See %20The%20Need%20for%20Change%20(paper%201).pdf.

18 allow the ERO Enterprise to oversee the activities of Registered Entities in a more efficient manner and to focus limited resources where they can result in the greatest benefit for reliability. Specifically, this approach will allow the ERO Enterprise to focus on the higher risks to the reliability of the BPS, providing clear signals to Registered Entities about identified areas of concern and risk prioritization, while maintaining the ERO Enterprise s existing visibility into potential noncompliance issues. This approach also will encourage the enhancement of internal controls and self-identification of noncompliance by Registered Entities (since these practices will be appropriately valued and rewarded). It is important to note that this is not meant to eliminate oversight or visibility regarding any noncompliance but rather, in appropriate circumstances, to allow NERC and the Regional Entity to address lesser risk issues outside of traditional enforcement actions. To achieve this end state, NERC and the Regional Entities have implemented processes that build on the success of the Find, Fix, Track and Report (FFT) program. In particular, these processes allow the ERO Enterprise to leverage existing internal practices at Registered Entities related to selfmonitoring and assessment of compliance with Reliability Standards as well as encourage further dissemination or enhancement of such practices throughout the industry. As discussed below, all of the RAI enforcement activities have been implemented. Two programs in particular, aggregation/logging and compliance exceptions, are being expanded gradually over the course of Status of Compliance Monitoring Activities The RAI Oversight Plan Framework (Framework) was presented at the May NERC Board of Trustees (Board) meeting to describe the single oversight design adopted by the ERO Enterprise. The Framework consists of four modules, each one based on lessons learned from the completed compliance pilots. The first two modules, Risk Elements and the Inherent Risk Assessment (IRA), are being documented for publication and industry comment so that IRA can be implemented in the second half of 2014 and Risk Elements for use in 2015, informing the development of the Annual Implementation Plan (IP) and the Actively Monitored List (AML). The first two elements support focusing limited regulatory resources on the greatest risks. It is also important to emphasize that these processes are not re-inventing anything. The practices associated with RAI such as assessing risk and developing effective compliance oversight are well established through a number of authoritative bodies. The final two modules, Internal Control Evaluation (ICE) and Compliance Tool selection, will be documented and published for industry comment in the second half of 2014 for deployment during Next steps that will result in the full implementation of the compliance monitoring activities under RAI by 2016 include: incorporating the processes into the 2015 IP and AML; developing and delivering training through the second half of 2014; deploying Framework elements across the ERO Enterprise through 2015; and conducting effective Regional Entity oversight to support full implementation by The four modules in the Framework are:

19 Risk Elements Module NERC is currently working on designing and documenting processes related to the Risk Elements module. The Risk Elements module will be published in draft form prior to the August Board meeting and aspects of the module (aligning risks with functions and standards) will be reviewed and demonstrated at the Board meeting. The purpose of identifying risk elements is to look across the industry and assure finite compliance resources and appropriate oversight tools are coordinated and correctly applied to those organizations and functions that have the potential to pose the greatest level of risk to the BPS. Risk Elements will modify the existing IP and AML, removing a static, one-size fits all list of standards and incorporating a risk-based methodology that prioritizes functions and standards based on risk to determine the appropriate oversight methodology. Inherent Risk Assessment Module In addition to the work on Risk Elements, the ERO Enterprise is completing the documentation of the single design for IRA based on lessons learned from the regional pilots. The guide will be published for feedback and comments from industry during July and included in the policy input letter for MRC feedback. The IRA is the second module and serves as an important part of the Framework. The IRA utilizes information specific to the Registered Entity and the Risk Elements from the first module to select the applicable standards and requirements to appropriately scope oversight. Internal Control Evaluation Module The ERO Enterprise expects to present the ICE approach in October Registered Entities that choose to share their management practices and internal controls for evaluation in the determination of their oversight scope as well as testing will proceed through the ICE process. The evaluation process for management practices and internal controls does not prescribe a design, compare designs, or determine the quality of one program versus another. Rather, the process to perform an ICE takes into consideration that no one size fits all and allows each Registered Entity to tailor a control model to fit its needs. In this regard, ICE will establish a principled-based approach for the evaluation of the necessary components in a system of internal controls. The primary factors that are being considered in the finalization of the evaluation and control testing design include: Does the control activity or combination of control activities mitigate the risk? Are the controls deployed through policies that establish expectations? Do procedures exist that put policies into action? Is there a design to determine if the components of the control are present and functioning? Do processes exist to evaluate and communicate non-compliance? Is there a process to take corrective action?

20 CMEP Tools The final module is based on selecting the proper oversight tool and frequency of application to appropriately address the risks and residual risk identified through the first three modules. CMEP tools consist of audits, self-certification, and spot checks. Understanding risks and the controls that mitigate those risks allows for the proper selection of a tool that may be used to obtain reasonable assurance of compliance. The CMEP Tools module will be developed to support the 2015 IP and AML. Status of Enforcement Activities Self-Report and Mitigation User Guides NERC and Regional Entity staff prepared self-report and mitigation user guides that, among other things, explain the type and quality of information that should be submitted with a self-report and mitigation plan in order to allow for a prompt evaluation and, as appropriate, prompt disposition of noncompliance (in particular of noncompliance that posed a minimal risk to the reliability of the BPS). In December 2013, an industry focus group reviewed the draft user guide and provided comments to the working group. Among other things, the focus group suggested that the document be submitted in draft form to a broader audience of stakeholders prior to being finalized. In response to the feedback, the draft guide was posted in January 2014 for broader comment. NERC and the Regional Entities reviewed the comments received and posted final documents in May Improved Process Flow (Triage) As of January 1, 2014, all Regional Entities implemented a triage process. As part of the triage, Regional Entities review incoming instances of noncompliance to make an initial determination as to whether an issue will proceed through enforcement or additional information is needed. On average, it should take 60 days from discovery of the noncompliance for the Compliance Enforcement Authorities (CEAs) to make the initial determination. The goal of the triage process is to add efficiency to the processing of all noncompliance but especially noncompliance posing a minimal risk to the reliability of the BPS. The triage allows CEAs to off ramp minimal risk issues more efficiently, where appropriate. Preliminary data indicates that the triage process has resulted in initial determinations being made within the 60-day timeframe for more than half of the noncompliance submitted in The success of the process change, however, will be measured on its impact in the overall processing efficiency of the ERO Enterprise. NERC will continue to track the implementation of this process and its impacts, and will be reporting on results at the August Board meetings. Multi-Region Registered Entity (MRRE) Process The goal of this activity is to establish guidelines to harmonize existing compliance monitoring and enforcement coordination practices and specify those Regional Entities that would serve as primary contacts for MRREs in connection with self-reports and other aspects of the compliance monitoring and enforcement process in certain types of

21 cases. The ERO Enterprise management approved guidelines for formalizing such coordination. The ERO Enterprise is documenting the processes associated with MRREs these documents are expected to be finalized by August 2014 and full implementation is expected by January 1, In the meantime, Regional Entities continue to coordinate compliance monitoring and enforcement for a significant number of MRREs, including a few MRREs which are participating in the logging program described below. Compliance Exceptions As noted above, FFT was the first step in implementing a risk based strategy that recognizes that not all instances of noncompliance require the same type of enforcement process. The natural evolution of the FFT program is to get to the point where an instance of noncompliance that poses a lesser risk to the reliability of the BPS does not have to trigger an enforcement action. Rather, NERC and the Regional Entity exercise discretion as to whether or not to initiate an enforcement action. The exercise of discretion is informed by the facts and circumstances of the noncompliance, the risk posed to the reliability of the BPS, and the deterrent effect of an enforcement action and/or a penalty, among other things. These are very similar to the considerations that have been used since 2011 to determine whether noncompliance should be processed as an FFT. The similarity in the criteria allows the ERO Enterprise to rely on the successful experience of the last two and a half years in which over 2,000 FFTs were processed. Given this successful history, it is appropriate at this time to further streamline the processes associated with resolving lesser risk issues. Therefore, FFT serves as the platform for moving toward a process in which an instance of noncompliance that poses a minimal (and in the future, moderate) risk to the reliability of the BPS may, at the discretion of NERC and the Regional Entity, be corrected by the Registered Entity, recorded in the Regional Entity portal, and excluded from the enforcement process. Issues excluded from the enforcement process are referred to as compliance exceptions. Since November 2013, Regional Entities have been processing a small number of minimal risk noncompliance found at or by specific Registered Entities as compliance exceptions. The limited scope was intended to allow the ERO Enterprise to implement the program gradually and refine the program requirements and processes. In May 2014, Regional Entities expanded the number of Registered Entities from which compliance exception candidates could be selected and continue to gradually expand the scope of the program. Beginning in 2015, the ERO Enterprise expects to further expand eligibility for compliance exception treatment to minimal risk issues regardless of the Registered Entity involved. Aggregation/Logging Beginning in October 2013, NERC and certain Regional Entities began to allow specific Registered Entities to aggregate and log minimal risk noncompliance which would

22 otherwise be individually self reported. Specifically, the entities selected were those that previously demonstrated effective management practices to self identify, assess and mitigate instances of noncompliance. Logged items will presumably be resolved as compliance exceptions. This is consistent with the notion that noncompliance that is self-identified through internal controls, corrected through a strong compliance culture, and documented by the entity, should not be resolved through the enforcement process or incur a penalty absent a higher risk to the BPS. This program also builds on the ERO Enterprise s experience with the FFT program, as the record collected in the logs is similar to that of an FFT. Specifically, information regarding these instances of noncompliance as well as associated risk and mitigation is logged by the Registered Entity for periodic review and approval by the Regional Entity. Once the Regional Entity confirms that the issue and associated risk has been sufficiently described and mitigated, the issue is processed as a compliance exception. The program relies on and promotes a closer understanding by Regional Entities of Registered Entities management practices, and rewards Registered Entities for demonstrated, effective controls in place to detect and correct issues as they arise. Entities currently participating in the program report that they see a significant potential benefit, particularly associated with the presumption that logged items will be resolved as compliance exceptions.

23 Reliability Assurance Initiative (RAI) Jerry Hedrick, Director of Regional Entity Assurance and Oversight Sonia Mendonca, Associate General Counsel and Director of Enforcement MRC Informational Session July 16, 2014

24 RAI Progress Report Auditor Resources and Tools Develop industry and auditor training for risk elements and Inherent Risk Assessment Single Compliance Design Finalizing the Inherent Risk Assessment Guide and examples Developing the Risk Elements methodology and procedures for the IP/AML Beginning work on the Internal Control Evaluation Guide Improvements to Self-Reporting User guides to support improved self-reporting process finalized in May 2014 Triage, Aggregation and Compliance Exceptions Compliance and Enforcement Integration 2 Triage process implemented across ERO enterprise in 2014 Expansion of aggregation/logging and compliance exception programs under way Inform eligibility for aggregation/logging program Integrate control evaluations with enforcement processes Finalize integrated program design feedback loops and processes

25 Single Compliance Approach Timeline July Aug Sep Oct Nov Dec Jan Feb Dec July Publish the Inherent Risk Assessment Guide (IRA) for comment August Publish the Risk Elements Methodology for the modified IP/AML September Finalize IRA based on industry feedback October Publish the 2015 AML and IP Develop and begin delivering training on completed modules to industry and regional auditors Publish the Internal Control Evaluation (ICE) and CMEP Tools Modules 2015 Deploy ICE and CMEP Tools

26 2014 Timeline for Selected Activities May June July Aug Sep Oct/ Dec Jan Feb Dec May August Oct/Dec January User guides posted; Compliance Exceptions and Aggregation programs reviewed and expanded (throughout 2014) MRRE templates finalized (monitoring and enforcement activities) FERC informational filing submitted MRRE process implemented 4

27 Please send any questions or comments to: 5

28 Agenda Item 4b MRC Informational Session July 16, 2014 Risk-Based Registration Initiative Action Information Background NERC launched the Risk-Based Registration (RBR) initiative in The ultimate end-state vision for the registration program is to ensure the right entities are subject to the right set of applicable Reliability Standards, using a consistent approach to risk assessment and registration across the ERO Enterprise. The RBR Advisory Group (RBRAG), comprised of representatives from NERC staff, Regional Entity staff, and Federal Energy Regulatory Commission staff, along with U.S. and Canadian industry representatives, has continued to provide valuable input and advice on the RBR design and implementation plan. The RBRAG technical task force also has made significant contributions to date and is continuing to work on technical support for the proposed design framework. Status Update On June 2, 2014, a draft design and implementation plan, draft NERC Rules of Procedure (ROP) Appendix 5B, and specific questions focused on key areas of the draft design were posted for public comment. NERC conducted an industry webinar on June 6, 2014 to provide an overview of the general project and answer general questions. Several hundred people attended the industry webinar. In addition, approximately fifty sets of comments were submitted by industry stakeholders. The RBRAG will post revised documents that take into account the comments received to date, as part of the MRC policy input package. The draft documents will be discussed at the MRC meeting in August. The draft design incorporates an evaluation of the risks and benefits provided by a given entity to ensure reliability, and identifies a corresponding properly tailored set of NERC Reliability Standard requirements for certain functional categories. The draft design also includes an implementation plan supporting a 2016 or sooner launch, along with business practice and IT requirements, with the possibility of early adoption options. These options result in addressing industry burden, while preserving reliability of the Bulk Power System. The second stage will address any remaining non-design issues or issues requiring a longer lead-time. Existing flexibility in the application of threshold criteria, the Functional Model categories, and scaled sets of applicable Reliability Standards provide opportunities for accelerated reform within the existing ROP. However, possible modifications to the ROP are being assessed and will be pursued as necessary. The final versions of registration criteria, implementation plan, and any necessary ROP changes will be presented to the MRC and Board of Trustees in November with an anticipated filing date at the end of that month.

29 Risk-Based Registration Initiative Earl Shockley, Senior Director, Compliance Analysis and Certifications Terry Brinker, Manager of Registration Services MRC Informational Session July 16, 2014

30 Content Current registration challenges Risk-based registration (RBR) vision RBR benefits Proposed RBR design highlights Feedback and comments RBR implementation timeline Next steps 2

31 Current Registration Challenges Follow all standards according to Function, regardless of impact Some Functions may have minimal impact on reliability Conservative criteria and thresholds used to register entities Flexibility to use entity risk, but limited application to date 3

32 RBR Vision Differentiate entities exhibiting different levels of risk: Clear thresholds Registration using consistent risk assessment methods Focused Reliability Standard requirements Align with: Bulk Electric System definition Reliability Assurance Initiative Reliability Standard reform 4

33 RBR Benefits Align registration and compliance with reliability impacts Reduce registration burden while sustaining BES reliability Increase consistency in registration across the ERO Provide feedback to Reliability Standards development Improve use of NERC, Regional Entity and industry resources 5

34 Proposed RBR Design Highlights Eliminate functions that are commercial in nature PSE, LSE, IA Raise the Distribution Provider (DP) threshold to 75 MW (directly connected to the BES) Specific characteristics for DP inclusion is below 75 MW threshold Create a new UFLS Only DP registration Threshold synchronization with the new BES definition Centralized review process for threshold determinations Consistent risk-based methods to assess entity s impact Improve the attestation process with a one-time attestation 6

35 Feedback and Comments Draft Design, Implementation Plan, and redlines to Rules of Procedure (ROP) Appendix 5B posted for industry comment from June 2, 2014 to June 23, 2014 Approximately 50 comments submitted Most commenters supportive of the RBR project Initial technical analysis and comments from Regional Entities and Reliability Coordinators submitted on June 27, 2014 Additional technical studies being conducted 7

36 Highlights of Key Comments Suggestions to provide more detail and provide areas for expansion for the Implementation Plan including: JRO/CFR impacts Certification Standards/glossary projects Suggested language to address concerns over applicable governmental authority (Canada and US) Several comments focused on the proposed tiering for Transmission Operators (TOP) and whether Transmission Owners (TO) could be tiered further Joint ownership/control over BES elements and facilities were raised by several entities One entity questioned removing entities from the INT standards 8

37 RBR Implementation Timeline 9

38 Next Steps Incorporate MRC policy input Solidify technical validations Post Design, Implementation Plan, and ROP changes for 45 days Recommend NERC Board of Trustees approval in November Move forward with Implementation Plan 10

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40 Agenda Item 4c MRC Informational Session July 16, 2014 Critical Infrastructure Protection (CIP) Version 5 Transition Action Information Background Since October 2013, NERC has been actively collaborating with Regional Entities and industry to support transition from version 3 of the Critical Infrastructure Reliability Standards (CIP Version 3) to implementing the version 5 of the Critical Infrastructure Reliability Standards (CIP Version 5) in a manner that is timely, effective, and efficient. NERC established a transition program with the following goals and key elements: Periodic Guidance. To keep industry informed of various implementation and transition matters throughout the transition period. Implementation Study. To work closely with a small number of Responsible Entities to implement aspects of CIP Version 5 in an accelerated timeframe, and share lessons learned. Compliance and Enforcement. To further develop approaches that demonstrate compliance consistent with the Reliability Assurance Initiative (RAI) 1. Outreach and Communications. To keep all stakeholders informed of developments related to the implementation of CIP Version 5 and invite input throughout the transition period. Training. To provide timely training to Regional Entities and industry on CIP Version 5 implementation. As part of NERC s CIP Version 5 transition program, NERC staff posted a draft updated Cyber Security Standards Transition Guidance (Transition Guidance) document for industry and Regional Entities to review through June 25, The primary objective of the Transition Guidance is to address questions related to compliance preparation activities for industry and Regional Entities as they transition from Version 3 to Version 5. A Transition Guidance presentation was also provided to the Critical Infrastructure Protection Committee in June The documents are available on the transition program website 2 and will be updated based on stakeholder input as the transition program continues. The Implementation Study, another component of the transition program, is particularly important. The field work ended on June 26, 2014, providing an opportunity for NERC, Regional Entities, and certain Responsible Entities to experience what is required to implement the CIP Version 5 standards in operational environments. NERC, with input from Regional Entities and stakeholder participants, will be drafting an Implementation Study report to summarize lessons learned, 3 highlight certain implementation processes, and discuss CIP Version 5 resource impacts. NERC anticipates completion of that report in the third quarter of Ref. NERC website

41 NERC and the Regions, with stakeholder input, also developed Reliability Standard Audit Worksheets (RSAWs), which cover the approved CIP Version 5 standards and the proposed modifications to those standards developed as part of the CIP Version 5 revisions project. The RSAWs were posted concurrently with the CIP Version 5 revisions for comment through July 16, In response to feedback on the RSAWs and Transition Guidance, NERC is developing auditor training to ensure that all Regional Entity CIP auditors have been trained on the CIP Version 5 standards (and revisions) and the RSAWs use. In addition, NERC produced an RAI-based Frequently Asked Questions 4 document to assist industry in understanding how RAI integrates with the concepts of CIP Version 5. Next Steps in Managing Transition to CIP Version 5 With the field work of the Implementation Study complete, along with closure of the comment period on the Transition Guidance, NERC, the Regional Entities, and industry have an opportunity to assess understanding of transition expectations and opportunities for increased engagement in specific areas. NERC is committed to a ensuring smooth transition to CIP Version 5, but it also understands that there is more work needed to increase confidence amongst entities that their transition activities and efforts will meet future compliance and enforcement expectations. NERC is initiating a collaborative effort involving NERC staff, Regional Entity staff, Implementation Study participants, and other stakeholders to coordinate monthly through the transition period to identify and address pressing industry questions about CIP Version 5. Input from these activities will result in coordinated guidance for the transition, which may include development of supporting documents approved under section 11 of the Standard Processes Manual. Among the priorities for this group will be identification of any obstacles and challenges to increasing transitioning entities confidence, along with partnering with the Regions and stakeholders through continued communication and engagement. There will also be a number of training and outreach sessions planned for industry and Regional Entity staff, which will include industry readiness reviews by regional staff, webinars and other opportunities to discuss technical questions. As these are developed, they will be announced and posted on the NERC calendar. Extensive auditor training is being prepared, with initial sessions occurring in September Additionally, as RAI concepts are finalized, NERC will ensure continued outreach and education to support continued alignment between industry and NERC s CIP compliance monitoring approaches. Additional Information A link to the CIP V5 Transition Program and files is included here for reference: [ 4

42 CIP Version 5 Transition Steven Noess, Associate Director of Standards Development MRC Informational Session July 16, 2014

43 Purpose of the transition program Address V3 to V5 Transition issues Provide a clear roadmap for V5 steady-state Justifies budget for V5 implementation and compliance Foster communication and knowledge sharing Support all entities in the timely, effective, and efficient transition to CIP Version 5 2

44 CIP V5 transition program elements Periodic Guidance Implementation Study Compliance and Enforcement Outreach & Communications Training 3

45 Recent and near-term activities Recent: RAI and CIP Version 5 June webinar Draft Cyber Security Standards Transition Guidance (June 2014) o Reviewing input o Collaborative approach with Regions and industry for revisions Field work for Implementation Study complete (June 2014) Near-term: Draft Implementation Study report (Q3) CIP Auditor Workshop (September 2014) Related activities: Project : CIP Version 5 Revisions Reliability Standard Audit Worksheet development 4

46 Focused collaboration NERC, Regions, and stakeholder group to meet monthly (beginning August 2014) Priorities: Address pressing topics to support transitioning entities confidence in implementing Version 5 Partnering with the regions and stakeholders through continued communication and engagement 5

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48 Agenda Item 4d MRC Informational Session July 16, 2014 Cybersecurity Risk Information Sharing Program Background The Cybersecurity Risk Information Sharing Program (CRISP) is a voluntary program to facilitate the exchange of detailed cybersecurity information between electric utilities, the Electricity Sector-Information Sharing and Analysis Center (ES-ISAC), the US Department of Energy (DOE), and Pacific Northwest National Laboratory (PNNL), to enable electric power critical infrastructure operators to better protect their networks from sophisticated cyber threats. The program uses passive sensors to collect and transmit cybersecurity information from each site for analysis. CRISP also incorporates additional information exchange capabilities that support sharing some outputs from the analysis more broadly with the entire electricity sector, improving the overall sector cybersecurity posture. CRISP has two differentiators from other commercially available cyber risk monitoring services. The first is the intent to integrate other cyber related threat information provided through governmental sources with the cyber threat information gathered from the CRISP devices installed at the participant sites. Second is the ability of the program to look across electric utilities within the electricity subsector, identifying correlations and trends. Scope CRISP technology was deployed across DOE networks over ten years ago. During the past several years, the technology has been deployed across five electric organizations through a DOE pilot program. Under the direction of DOE and in coordination with the Electricity Subsector Coordinating Council (ESCC), the deployment of CRISP is now transitioning from a pilot to a broader deployment across the electric utility industry. While it will initially only be deployed to a relatively small subset of the industry, it is intended that anonymized information derived from CRISP would be disseminated broadly to the entire electricity subsector through the ES-ISAC, enhancing the entire electric power industry s cybersecurity posture. The ESCC has endorsed this program and twenty eight (28) electric utility organizations have preliminarily been identified for deployment of the CRISP capability in 2014 or early Roles and Responsibilities ES-ISAC Under the structure that is being proposed, the ES-ISAC would assume the role of program manager for CRISP, be responsible for providing certain agreed upon services to the participating electric organizations, and serve as a central point for coordination as well as a hub for collaborative analysis of CRISP data. Initially NERC would subcontract substantially all of these services to PNNL with the potential to take a more active and direct role in the future. The ES-ISAC would also share unattributed CRISP reports and data to the broader industry participants who are registered users of the ES-ISAC portal and other ISACs which broadens the stakeholder benefit associated with NERC s participation in CRISP.

49 PNNL and Argonne National Labs PNNL is a United States DOE National Laboratory, operated by Battelle Memorial Institute with oversight by the DOE's Office of Science. The main campus of the laboratory is in Richland, Washington. PNNL was the federal government s primary technical partner in establishing CRISP and, under the structure being proposed, would be the primary subcontractor to NERC in connection with the provision of CRISP services to participating utilities. PNNL would be responsible for the deployment of the required technology, supporting infrastructure, analysis, and the technical capabilities. Argonne National Lab, another DOE National Laboratory, supports and maintains certain core components necessary to support CRISP and would provide this support through an inter-lab agreement with PNNL. Technology CRISP has three main technology elements. Together these elements provide the site with analysis of cybersecurity information, the ability to exchange cybersecurity threat information, and a means for secure data and voice communications across all CRISP participants. CRISP supplements a site s existing cybersecurity program and enables a level of collaboration that does not currently exist in the sector. The three technology elements include Information Sharing Devices ( ISDs ), the Cyber Federated Model ( CFM ) and CONRAD and are further summarized below. An ISD is hardware installed at the site that captures cybersecurity threat information for transmission to PNNL for analysis. The CRISP ISD is a network device that uses commercial off the shelf hardware. It s placed at the transmitting site s (e.g. utility) network border, just outside the corporate firewall. Once the ISD is configured and activated, the data is encrypted and transmitted for further analysis. The ISD is not an intrusion prevention or detection system. It is a completely passive device that works with the ISD software suite to gather various types of non-content related network traffic information and extract information necessary to understand cyber threat tactics, techniques and procedures. PNNL and the ES-ISAC then correlate information from across the CRISP sites with other cyber threat information made available by the government and other sources, communicating the results of these analyses with the CRISP participant. Anonymized information will be shared through the ES-ISAC with the industry as a whole. CFM is software that enable the secure communication of cybersecurity threat information between PNNL, Argonne National Laboratory ( ANL ), ES-ISAC, sites, and other participating organizations (government and non-government). Developed and operated by ANL, CFM is a software program that is installed on the site s computer and enables the exchange of cyber threat information with other CFM sites. ANL will support CFM installation at the sites through an inter-lab agreement with PNNL and installations can be done in conjunction with ISD installations. CONRAD is a secure out-of-band communications device comprised of hardware and software that enables the secure voice and data transmission from the ISDs.

50 Figure 1 provides a visual overview of the interaction between the three technical elements of CRISP. Figure 1: Visual of CRISP Technologies and Capability INDUSTRY ANALYSIS GOVERNMENT INFORMED ANALYSIS CFM DATABASE ALERTS AND REPORTING NEAR REAL TIME THREAT INFO DATA SHARING SECURE COMMS THREAT SHARING ISD CONRAD CFM CRISP SITE

51 Budget and Assessment Impact NERC management is working with representatives of potential CRISP participants and PNNL to develop a draft budget for CRISP. NERC s participation in the CRISP program and budget will be subject to review and approval by NERC s Finance and Audit Committee and Board of Trustees. As currently contemplated and subject to the receipt of necessary corporate authorizations and approval of the CRISP participants, NERC s 2015 budget will provide that substantially all of the services under NERC s contract with participating utilities will be subcontracted to PNNL and paid for directly by participating utilities. Assuming NERC participation, NERC would include the projected expenses for the CRISP program in its 2015 budget and offset the majority of the assessment funding requirements through funding provided directly to NERC by participants in the CRISP program. The amount of CRISP funding requirements recovered through assessments is not expected to exceed approximately $600 1 k in The funding of a portion of CRISP costs through assessments is considered appropriate since load serving entities which are registered with the ES-ISAC will have access to CRISP derived information which NERC will make available through the ES-ISAC portal. This sharing of CRISP derived data also will benefit users, owners and operators of the Bulk Electric System (BES) by assisting industry in making individual systems more secure and the BES as a whole more secure against cyber-attacks. The total expenses NERC projects to incur in 2015 in connection with the CRISP program would be set forth in the final draft of its 2015 budget, together with a projection of CRISP participant funding which is expected to significantly offset overall costs. NERC and participating utilities are also discussing the potential of commencing the CRISP program during Should this take place, the entire 2014 cost would likely need to be funded directly by participating utilities, with any use of existing operating reserves by NERC limited and subject to applicable prior corporate and governmental authorizations. 2 Further information regarding the projected overall CRISP budget and assessment impact will be included in the final draft of NERC s 2015 business plan and budget which will be posted for review and comment on July 15, A conference call and webinar will also be conducted on July 17, 2014 to provide an overview of NERC s final draft, including additional detail regarding the proposed CRISP budget, as well as any changes in the Regional Entity final business plans and budgets. 1 NERC s preliminary budget to serve in the role of CRISP program administrator is expected to exceed $600k per annum. Limiting the recovery of NERC s CRISP budget through assessments in 2015 to no more than $600k, which represents a relatively small fraction of the overall projected cost of the CRISP program (which will, other than the $600k, be paid for directly by participating utilities), is both an effort to limit the impact of the total costs of the CRISP program on assessments and in recognition there should be some sharing of the CRIP-related costs through assessments given the benefits the CRISP Program is expected to provide to load serving entities that will not be directly participating in, or directly paying for, the CRISP Program. 2 Given the newly contemplated role as administrator of the overall CRISP program, NERC is re-evaluating whether it will install an ISD on its own network. To the extent it chooses to install an ISD on its network the cost would be paid from its budget, with the expenditure subject to applicable corporate and regulatory authorizations.

52 Agenda Item 5a MRC Informational Session July 16, 2014 Action Information Long-Term Reliability Assessment and Emerging Issues Update Status Update The Long-Term Reliability Assessment (LTRA) report provides insights about emerging issues that could potentially affect reliability of the Bulk Power System. These issues also are input to and support the strategic reliability issue prioritization conducted by the Reliability Issues Steering Committee (RISC). The MRC and RISC members were asked, in an open-ended question set, to provide input describing identified emerging issues as well as any new reliability topics important to be considered in NERC's LTRA report. Through working with the Operating Committee (OC) and the Planning Committee (PC), ongoing insights about the key reliability aspects and emerging issues were also provided. Importantly, open-ended aspects of the survey provided the opportunity for policy level guidance about long-term planning issues. Summary The long-term and emerging issues are summarized below and include MRC members' comments and viewpoints, which reflect fairly uniform survey participation throughout the regions. Given the geographical and distinctive nature of the North American electric system, each area and region exhibits a range of inherent and diverse challenges. Some areas or regions may be more vulnerable to certain emerging issues than others; for example, the increasing penetration rate of variable generation (wind and solar) differs from area-to-area. The southwest has experienced a greater addition of such resources to its resource mix, along with challenges in operation and increasing operational flexibility needs. Among other inputs provided, consideration of the aggregated reliability impacts of a combination of system resource mix changes, for instance, the significant retirement of coal-fired power plants, was identified. This retired capacity is being increasingly being replaced with natural gas power plants and variable generation each with their own reliability considerations. A common theme appearing across the survey results, was the suggestion to expand analysis associated with the Essential Reliability Services Task Force (ERSTF) efforts and to conduct a more granular and detailed model-based resource mix studies to gain a better perspective of future system needs and challenges. In addition, a second aspect was to focus on continued monitoring and identification of system reliability risks by addressing planning tools, continued assessment and increased communications to inform industry, regulators, and policy makers about the reliability concerns from a changing and evolving Bulk Power System. Overall these inputs are continuing to be carefully evaluated and a complete depiction of these emerging issues will be incorporated in the LTRA. In addition, to the extent that these aspects

53 are directed at a policy or strategic perspective, the development of the LTRA will reflect the emerging issue considerations in the completed report. Overview of MRC Survey and Responses: 2014 Long-Term Reliability Challenges and Emerging Issues Accommodating System Needs and Adapting to Change The composition of resources needed to supply North America has rapidly changed and is anticipated to continue at an even greater pace over planning horizon, requiring changes to operations and planning of the Bulk Power System. The traditional resource adequacy models do not sufficiently address the range of reliability risks resulting from this evolution. As a result, more sophisticated planning tools are needed to evaluate the reliability implications as the industry adapts to these transitions and changes in energy policies. Similarly with operations of the system, the newer resources and impact of the fuel mix need to be understood so modifications can be made to operating practices. Generation Retirements and Coordination of Outages Environmental regulations and retirement of aging infrastructure challenges resource availability, as well as shifts the composition of the resource mix. Uncertainty in future regulations with less investment market assurances as well as lack of a well-defined regulation implementation plan can potentially increase the reliability risk. Continued Integration of Variable Generation The rate of integration of variable generation into the existing resource mix, coupled with overall changes in the resource composition, has created issues which are unique to each area within some interconnections. The top identified issues with variable generation can be categorized into frequency support and active power control. Increased Dependence on Natural Gas Environmental regulations and coal-fired generation retirements coupled with the availability of natural gas have led to an expansion of natural gas fueled resources. This increases reliance on natural gas, affecting the reliability of the electric system, which reinforces gas-electric interdependency as a systemic issue. Transportation and supply of natural gas, especially in harsh weather conditions with lack of sufficient fuel inventory to cover multi-day shortage events, are among the underlying issues surrounding the gas-electric interdependency. Increasing Use of Demand-Side Management With increasing use of demand-side management, reliable dependence on these resources has gained more attention. Factors that could impact the reliability of the Bulk Power System correlate with the lack of granularity in various components of demandside management, and lack of data in performance capability of these resources under various weather conditions over consecutive days.

54 Wide-Scale Nuclear Generation Retirement and/or Long-Term Outages In case of a wide-scale retirement of nuclear generation, the offset substitute capacity replacement would require sufficient time to be placed in-service in order to maintain reliability. There are also associated risks with possible coincidental timing of other base load generation retirements or transitions. Possible Areas for Consideration A range of reliability topics including changing load characteristics, impacts of aging infrastructure on performance and transmission adequacy, and more in depth assessment of reliability impacts of a changing resource mix were provided.

55 Long-Term Reliability Assessment and Emerging Issues Update John Moura, Director of Reliability Assessment MRC Informational Session July 16, 2014

56 LTRA Background NERC s Long-Term Reliability Assessment (LTRA) provides a comprehensive assessment of industry forecasts of supply and loads LTRA also provides assessment of identified broad emerging reliability issues Emerging issue topics aid the strategic prioritization by the Reliability Issues Steering Committee (RISC) MRC s input used for policy-level and strategic perspective guidance 2

57 2014 LTRA Preliminary Data Overview Peak Season Reserve Margins 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% Preliminary Data 2015 Anticipated Prospective Adjusted-Potential Reference Margin Level Winter-Peaking 3

58 2014 LTRA Preliminary Data Overview Peak Season Reserve Margins 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% Preliminary Data Anticipated Prospective Adjusted-Potential Reference Margin Level Winter-Peaking 4

59 2014 LTRA Preliminary Data Overview Peak Season Reserve Margins 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% Preliminary Data Anticipated Prospective Adjusted-Potential Reference Margin Level Winter-Peaking 5

60 2014 LTRA Preliminary Data Overview Anticipated Margin Falling Below Reference Level MISO (Summer 2016) Retirements/suspensions due to environmental regulations and gas prices Increased exports and removal of non-firm imports Plans for new capacity in the later years of the assessment period are uncertain TRE-ERCOT (Summer 2018) Recently energized gas-fired capacity (2.1 GW) contributes to remaining above the Reference Margin through Additional capacity (1.4 GW) added in 2015 and 2016 will address forecasted load growth through NPCC-New York (Summer 2015) New York will meet the Reference Margin Level for all years with Prospective Resources, expected to be available according to NYISO Planning Criteria. Long-Term Planning Considerations ( ) Load forecasts revisions to reflect changing economic conditions. Prospective resources including less certain capacity additions and non-firm contracts or capacity transfers can be firmed-up to address potential shortfalls. 6

61 Regionality Inherent regional and interconnection reliability characteristics and trends present distinct challenges Effects of emerging issues can result in aggregated reliability impacts or challenges specific to the underlying region Rate of resource and load changes differs from area to area: o Gas transportation and availability [Northeast, Southwest] o Rate of penetration of variable generation [Southwest, Upper Midwest] o Pace of resource mix changes resulting from retirements [various] 7

62 Emerging Issues Categories Accommodating System Needs and Adapting to Change Changes in composition of resource mix Requires changes to operations and planning Generation Retirements and Coordination of Outages Environmental regulations; GHG regulations and others Uncertainty in future regulations Continued Integration of Variable Generation Continual rapid integration prompting regionally specific reliability issues Frequency support, active power control and ERS Increased Dependence on Natural Gas Increase reliance on natural gas for electric power production Lack of firm supply and transportation increases reliability risk 8

63 Emerging Issues Categories Increasing Use of Demand-Side Management Historical data and performance capability testing Wide range of DSM reliability attributes Planning vs. operations utilization Nuclear Generation Retirement and/or Long-Term Outages Reliability impacts of decreasing fuel diversity Requires sufficient time for resource replacement to maintain reliability Other Possible Areas for Consideration Changing load characteristics (i.e. EV, power electronics, etc.) Aging infrastructure on future performance and transmission adequacy Analysis on resource mix trends and reliability impacts 9

64 10

65 2014 NERC Assessment Areas 11

66 2014 LTRA Preliminary Data Overview Anticipated Margins below Reference Margin Levels MISO (S)2016 MRO- MAPP (S)2020 NPCC-New York (S)2015 SERC-N (S)2016 SERC-E (S)2016 TRE-ERCOT (S)

67 Agenda Item 5b MRC Informational Session July 16, 2014 Polar Vortex Report Update Action Information Summary In early January of 2014, the Midwest, South Central and East Coast regions of the United States experienced a weather condition known as a Polar Vortex where frigid artic conditions dipped down to much lower latitudes than normal, resulting in extreme cold weather. These weather conditions resulted in many areas experiencing temperatures 20 to 30 degrees below the average high and low temperatures normally experienced, with some areas experiencing more than 35 degrees below their average low. This resulted in record high winter electrical peak demand for these areas on January 6, 2014 and again on January 7, During the polar vortex, cold weather and fuel issues had a significant impact on the amount of generation available to Balancing Authorities and Load Serving Entities. From January 6, 2014 through January 8, 2014, there was significant generation capacity reduction either through the unavailability of the unit to start-up, stay online, or reduced capacity. NERC, in conjunction with the Regional Entities, will continue to analyze these capacity reductions to determine if they were the direct or indirect result of the extreme cold weather. During these challenges, Balancing Authorities and Load Serving Entities in both the Texas and Eastern interconnections were mostly able to maintain their reserve margins and continue to serve their load. Through the use of voltage reduction, interruptible and demand side management techniques, and the NERC EEA process, only one Balancing Authority shed less than 300 MW of Firm Load, representing less than 0.1 percent of the total load experienced by the impacted areas on that day. NERC has gathered information and data on what happened during the Polar Vortex and many Registered Entities have provided an initial analysis of the challenges they faced. NERC has continued its assessment and analysis using the data gathered from the generating availability data system (GADS). In September, NERC will release a full report on the system impacts from the Polar Vortex. The report will contain a historical assessment of how this event compared to previous cold weather events and normal winters, a detailed analysis of forced generation outages, a review of the Operating Committee Reliability Guidelines, an assessment of demand response effectiveness, and recommendations.

68 Polar Vortex Report Update James Merlo, Director Reliability Risk Management and Training MRC Informational Session July 16, 2014