Risk-Based Registration Technical Justification. August 26, 2014

Transcription

1 Risk-Based Registration Technical Justification August 26, 2014

2 Table of Contents Preface and NERC Mission... iv Executive Summary... v Introduction...1 Background...1 Functional Entities Considered...1 Technical Review Assignments...2 Chapter 1 Removal of Purchasing-Selling Entity from the NERC Compliance Registry...4 Background...4 Applicable Reliability Standards...4 Compliance Metrics...4 Regional Entity Survey Responses...5 Conclusion...5 Chapter 2 Removal of Interchange Authority from NERC Compliance Registry...6 Background...6 Applicable Reliability Standards...7 Compliance Metrics...7 Conclusion...7 Chapter 3 Removal of Load-Serving Entity from NERC Compliance Registry...9 Background...9 Applicable Reliability Standards Compliance Metrics Regional Entity Survey Responses Conclusion Chapter 4 Threshold Change for Distribution Providers Background Definition of Distribution Provider Applicable Reliability Standards Definition of Bulk Electric System Materiality Methodology Results Overview Approach Population Analyzed ii

3 Table of Contents Statistical Analysis Reliability Analysis Other Reliability Considerations Conclusions and Recommendations Chapter 5 Conclusion Appendix A: Mapping Document Appendix B: Technical Studies Appendix C: Proposed deactivations NERC Risk-Based Registration Technical Justifications August 2014 iii

4 Preface and NERC Mission This technical document 1 evaluates the technical justification conducted to support the proposals of the Risk-Based Registration initiative for the following: 1. Deactivation of registration of entities for three functional categories proposed for removal from the NERC Compliance Registry: Purchasing-Selling Entity, Interchange Authority, and Load-Serving Entity; and 2. Refinement of the thresholds for the functional category of Distribution Provider, consistent with the Bulk Electric System (BES) Definition. 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 or Commission), 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 eight Regional Entity boundaries, as shown in the map and corresponding table below. FRCC MRO NPCC RF SERC SPP-RE TRE 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 1 This document will be updated as additional technical studies are completed. Additional information will be available on the Risk-Based Initiative project page located at: Based%20Registration.aspx iv

5 Executive Summary NERC s Risk-Based Registration initiative seeks 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. To support the Risk-Based Registration initiative, NERC established the Risk-Based Registration Advisory Group (RBRAG) and the RBRAG technical Task Force (RBRAG Task Force), to provide input and advice for the Risk-Based Registration design and implementation plan. The analysis contained herein is provided to support the proposals of the Risk-Based Registration initiative. In the second quarter of 2014, the RBRAG team asked three independent sources: NERC, the Regional Entities, and select Reliability Coordinators to review the Phase 1 recommendations of the Risk-Based Registration initiative and provide input as well as technical justification for the following proposals: 1. Evaluation of potential reliability impacts from removal of the Purchasing-Selling Entity, Interchange Authority, and the Load-Serving Entity functional categories from the NERC Compliance Registry. This includes either that the Reliability Standard requirements followed by these organizations have relatively small impact on reliability or that necessary reliability activities are being conducted by other potential entities. 2. Evaluation of proposed revisions in the Distribution Provider registration criteria including: a. Raising the peak load threshold from 25 MW to 75 MW (directly connected to the BES) b. Establishing sub-sets of Reliability Standards for Underfrequency load-shedding (UFLS)-only Distribution Providers c. Evaluation of the potential reliability impact to UFLS programs The following initial analysis of phase 1 recommendations, supported by studies and review of data and information, demonstrates that the above proposals should not significantly increase the risk to the BPS reliability. The technical analysis will continue for phase 1 until the end of the fourth quarter of The analysis and studies for the next phase of the Risk-Based Registration initiative are ongoing. v

6 Introduction Background The NERC Registry Criteria provides for BPS owners, operators, and users that perform a function listed in the functional types identified in Section II of the Registry Criteria, meet the criteria in Sections III and IV of the Registry Criteria (if applicable), and have a material impact on BPS reliability to register as one or more of fifteen functions. 2 The NERC Compliance Registry identifies the functional categories and entities that are subject to compliance with mandatory NERC Reliability Standards. Of the fifteen 3 functional registration categories, the Risk-Based Registration initiative proposes three functional users of the BPS Purchasing-Selling Entities, Interchange Authorities, and Load-Serving Entities for removal from the NERC Compliance Registry. Based on analysis of these functional categories, the Reliability Standards pertaining to these functions generally do not pose a significant risk to reliability if they are no longer followed. Further, in many cases, these functions are commercial in nature, and Reliability Standards applicable to other functional entities, when considered in the aggregate (e.g., requirements to Balancing Authorities and Distribution Providers within the Resource and Demand Balancing (BAL) and other standards) address any potential reliability impacts of commercial transactions. The requirements contained in the NERC Reliability Standards for these functions are either already adequately addressed by other contracts or regulations (e.g., pro forma Open Access Transmission Tariff (OATT), North American Energy Standards Board (NAESB) Standards, commercial contracts, market rules) or are already being performed by another entity. In addition, the analysis demonstrates that a change in the threshold for Distribution Providers from 25 MW to 75 MW peak load in the NERC Compliance Registry will not materially impact the reliability of the BPS. This change in threshold is accompanied by materiality tests that ensure that those Distribution Providers who are less than 75 MW peak load and pose a potential significant risk to reliability will be registered. Functional Entities Considered Purchasing-Selling Entity Pursuant to the NERC Functional Model, Purchasing-Selling Entities are the functional entity that purchases or sells, and takes title to, energy, capacity, and reliability related services. Interchange Authority Pursuant to the NERC Functional Model, the term Interchange Authority was changed to Interchange Coordinator and Interchange Authorities/Coordinators are the functional entity that ensures communication of Arranged Interchange for reliability evaluation purposes and coordinates implementation of valid and balanced Confirmed Interchange between Balancing Authority Areas. 2 NERC Statement of Compliance Registry Criteria (Registry Criteria) at 2 ( Organizations will be responsible to register and to comply with approved Reliability Standards to the extent that they are owners, operators, and users of the Bulk Power System, perform a function listed in the functional types identified in Section II of this document, and are material to the Reliable Operation of the interconnected Bulk Power System as defined by the criteria and notes set forth in this document. ). See Registry Criteria at 3 The fifteen registration functional categories include: Reliability Coordinator; Transmission Operator; Balancing Authority; Planning Authority; Transmission Planner; Transmission Service Provider; Transmission Owner; Resource Planner; Distribution Provider; Generator Owner; Generator Operator; Load-Serving Entity; Purchasing-Selling Entity; Interchange Authority; and Reserve Sharing Group. 1

7 Introduction Load-Serving Entity Pursuant to the NERC Functional Model, Load-Serving Entities are the functional entity that secures energy and transmission service (and related Interconnected Operations Services) to serve the electrical demand and energy requirements of its end-use customers. Distribution Provider Pursuant to the NERC Functional Model, Distribution Providers are the functional entities that interconnect an end-use customer Load and the electric system for the transfer of electrical energy to the end-use customer. Distribution Providers provide and operate the wires between the transmission system and the end-use customer. For those end-use customers who are served at transmission voltages, the Transmission Owner also serves as the Distribution Provider. Thus, the Distribution Provider is not defined by a specific voltage, but rather as performing the distribution function at any voltage. Technical Review Assignments As discussed below, technical review is ongoing relating to changes applicable to four of the 15 functional categories Purchasing-Selling Entities, Interchange Authorities, Load-Serving Entities, and Distribution Providers. NERC conducted or facilitated independent technical analysis at the ERO, the Regional Entity, and the industry level. These independent sources reviewed the recommendations of the RBRAG team and provided input and technical justifications for removal of the three functional categories and evaluated the risks and potential reliability impacts of revising the Distribution Provider threshold criteria. The RBRAG conducted a three-step process to establish technical justification for the removal of the three functional categories from the NERC Compliance Registry. Step 1: A review of compliance data was performed to determine the number of instances of noncompliance relating to the proposed removals to determine what, if any, potential risk to the reliability of the BPS may result from removal of these functions from the NERC Compliance Registry. Step 2: Technical analysis was conducted by NERC and certain Reliability Coordinators to assess if the proposed thresholds for Distribution Providers or removal of the Purchasing-Selling Entities, Interchange Authorities, and Load-Serving Entities would have an adverse impact on the BPS and to what degree. Step 3: Survey responses were submitted by Regional Entities and industry to assess if the proposed thresholds for Distribution Providers or removal of the Purchasing-Selling Entities, Interchange Authorities, and Load-Serving Entities would have an adverse impact on the BPS and to what degree. NERC Considerations for Technical Justification Technical analysis was conducted to determine if the proposed thresholds would have a significant impact on the reliability on the BPS. NERC conducted a statistical analysis based on the Distribution Providers that would be deactivated from the NERC Compliance Registry as their peak load would be less than 75 MW. Additionally, NERC also analyzed the effects of losing the Under-Frequency Load-Shedding (UFLS) capability from those Distribution Providers which were less that the 75 MW peak load and had no other specific materiality to the bulk electric system reliability. This analysis was needed to assess the risk to reliability from Distribution Providers that do not meet any other DP registration criteria except having a UFLS program would only have to adhere to Protection and Control (PRC) PRC-006 and PRC-006 regional variances. Since this standard does not have a maintenance requirement, the RBRAG assessed the risk of not maintaining underfrequency load-shedding relays for this subset of small DPs, which might result in failure to operate or misoperated. Namely, as PRC requires testing of these relays once every 12 years, there appeared to be little increased risk to reliability resulting from testing and maintaining 1 in a thousand relays once every 12 years. 2

8 Introduction Regional Entity Considerations for Technical Justification Regional Entities provided responses to the following questions: If the Load-Serving Entity functional category is eliminated from the Registry Criteria, how much Load would be affected in your footprint? If the Purchasing-Selling Entity and Load-Serving Entity functions are eliminated from the Registry Criteria, will you be able to obtain needed information for modeling and studies? Please explain your response and provide data separated by the functional category. If the Distribution Provider threshold is increased to greater than 75 MW, how many entities would be eligible for deactivation for the Distribution Provider functional category? Please identify the number for affected Distribution Providers under 75 MW that have UFLS. Please also identify the number for affected entities that do not have UFLS. For the Distribution Providers above that would be deactivated, will you be able to obtain needed information for modeling and studies? Please explain and provide separate information regarding entities that have UFLS and those that do not have UFLS. Industry Considerations for Technical Justification Reliability Coordinators conducted studies to determine the effects of not receiving operational data from the Distribution Providers expected to be deactivated or deregistered from the NERC Compliance Registry due to the proposed 75 MW peak threshold. In addition to removing the Distribution Providers Load data from the study, an N-1 event was simulated in the area of missing data to determine if cascading outages would occur, if neighboring entities would be affected, or if additional contingencies emerged that could not be resolved without impact to the BPS. In addition, since November 2013, forty-three entities registered as Distribution Providers and Load-Serving Entities have been deactivated. Reliability Coordinators were asked if the deactivated Distribution Providers had stopped providing operational data from these entities and if any of these entities had intentionally refused to obey a reliability directive. Reliability Coordinators answered consistently that the risk to reliability did not increase after these entities were deactivated, no risks were created, and no instances of not providing operational data or complying with reliability directives had occurred. 3

9 Chapter 1 Removal of Purchasing-Selling Entity from the NERC Compliance Registry The Risk-Based Registration initiative proposes to remove Purchasing-Selling Entities as functional entities from the NERC Compliance Registry. The removal of this entity will be implemented as part of the registration process and the RBRAG recommends that for future consistency, conforming changes be made to Reliability Standards through the Standards Development Process. Background Many entities can fall within the category of a Purchasing-Selling Entity, including entities that may possess little or no operational or reliability data the host Balancing Authority and Transmission Operator may require. Fundamentally, this is a market function and not a reliability function. In considering elimination of the Purchasing- Selling Entity, the RBRAG took into account that total interchange (i.e., the sum of the individual transactions), rather than individual transactions, is important for reliability purposes. The BAL standards already require the Balancing Authority to manage total interchange. The RBRAG determined that this function should be removed as part of the registration process and recommends that for future consistency, conforming changes be made to Reliability Standards through the Standards Development Process. Applicable Reliability Standards Purchasing-Selling Entities are currently subject to the following NERC Reliability Standards: INT IRO IRO a TOP-005-2a The Balancing Authority is responsible for managing interchanges and obtains the necessary information from a variety of different mechanisms. Therefore, there is no risk to reliability created by removing the Purchasing- Selling Entity. The BAL standards, BAL-001-1, BAL-002-1, BAL-005-0, and the recently approved Interchange Scheduling and Coordination Reliability Standards in Docket No. RD mitigate the risk from deactivation of the Purchasing-Selling Entity because the Reliability Standards for Balancing Authorities to maintain system awareness, update the Area Control Error, and confirm/evaluate interchange schedules sufficiently incorporate the requirements in the afore-mentioned Reliability Standards. The proposed revised Standard IRO has removed the Purchasing-Selling Entity function from its applicability section. The Project (TOP/IRO) review team has proposed the retirement of IRO a and TOP-005-2a. 4 Compliance Metrics Since June 18, 2007, when the first set of NERC Reliability Standards became mandatory and enforceable, NERC has processed over 7,544 unique violations (filed, posted, or compliance exception). Of these, there have been 17 violations applied to solely Purchasing-Selling Entity function, 5 and another 2 for combined Purchasing-Selling Entity and Load-Serving Entity functions (11 unique registered entities). These violations consisted of: 1) INT See: pdf 5 In determining the scope of the compliance and enforcement history for these functions in order to determine potential risk to the BPS from noncompliance with these Standards by these functions, the RBRAG considered confirmed violations, posted Find, Fix, Track, and Report instances of noncompliance, and compliance exceptions. The results of this initial scope was further refined to include only violations that applied to solely functions recommended for removal from the NERC Compliance Registry. For example, if an entity had a single confirmed violation implicating both its Purchasing-Selling Entity and Generator Operator functions, the RBRAG would not include the violation as a part of its consideration. 4

10 Chapter 1 Removal of Purchasing-Selling Entity from the NERC Compliance Registry (4 violations); 2) INT (9 violations); 3) IRO-STD-006 (1 violation); and 4) TOP-005 (3 violations). All of these violations were considered posing only a minimal risk to the reliability of the BPS, in fact since the inception of the Administrative Citation Process and later the Find, Fix, Track and Report process, no Notices of Penalty have been filed applicable solely to a Purchasing-Selling Entity. After review of compliance history and the nature of the violations of these Requirements relating to Purchasing-Selling Entities, the RBRAG determined these pose an insignificant risk to the reliability of the BPS, and therefore support the removal of the Purchasing-Selling Entity from the NERC Compliance Registry. Regional Entity Survey Responses All of the Regional Entity responses confirmed that they would still receive the necessary information for reliability if Purchasing-Selling Entities were removed from the NERC Compliance Registry. The responses stated that if the function was removed from NERC s registration, that the Transmission Owners, Planning Coordinators, and Balancing Authorities have the sources of most of the needed data and would have separate methods to collect any remaining information from the responsible data sources. For example, in NPCC all market participants adhere to the Independent System Operator market rules and tariffs. These tariffs require participants to provide the Independent System Operators with Load data for their market operation activities. NPCC then collects its data through working groups for both short-term and long-term reliability studies. If the Purchasing-Selling Entity is removed, NPCC would be able to collect any necessary data through these alternative methods. Entities in the SPP RE region performing the activities described under the Purchasing-Selling Entity function, whether registered or not, are still responsible for entering information into the E-Tag system. The Transmission Operator function for the Load in its area sends real-time Load over Inter-Control Center Protocol to the Reliability Coordinator. Finally, in Texas RE, load data is provided each year via the regional planning and reliability analysis to meet NERC requirements. Real-time data and operational planning information would continue to be provided as required by the ERCOT regional rules. Conclusion Purchasing-Selling Entities can be removed from the NERC Compliance Registry with little to no impact on the reliability of the BPS. Purchasing-Selling Entity registrations can also be eliminated through deactivation, without awaiting the conclusion of the Standards Development Process and associated approvals. In considering elimination of the PSE, the RBRAG took into account that total interchange (i.e., the sum of the individual transactions), rather than individual transactions, is important for reliability purposes, and management of total interchange is within the purview of the Balancing Authority. To the extent there is currently no NAESB counterpart (i.e., INT-004, dynamic transfers), it is for NAESB to determine whether a standard is required for commercial purposes material reliability concerns are not raised, because the correct transfers are accounted for in Area Control Error and System Operating Limits. 5

11 Chapter 2 Removal of Interchange Authority from NERC Compliance Registry The Risk-Based Registration initiative proposes to remove the Interchange Authority as a functional entity from the NERC Compliance Registry. The removal of this entity will be implemented as part of the registration process and the RBRAG recommends that for future consistency, conforming changes be made to Reliability Standards through the Standards Development Process. Background Interchange refers to energy transfers that cross Balancing Authority boundaries. 6 An Interchange Transaction begins with a Request for Interchange, which is a collection of data for the purpose of implementing an energy transfer between one or more Balancing Authorities. The Source Balancing Authority is the Balancing Authority in which the generation (or source) is located. The Sink Balancing Authority is the Balancing Authority in which the load (or sink) is located. If there is another Balancing Authority on the scheduling path of an Interchange Transaction, it is known as an Intermediate Balancing Authority. The Interchange Authority essentially performs a quality control function in verifying and approving interchange schedules and communicating that information. The BAL standards already require the Balancing Authority to manage total interchange. Provided below is Figure A, which depicts the typical steps in coordinating Interchange and is provided for informational purposes. 6 See NERC Glossary, available at: 6

12 Chapter 2 Removal of Interchange Authority from NERC Compliance Registry An Interchange Schedule is the method by which the Source and Sink Balancing Authorities agree upon the Interchange Transaction size (measured in megawatts), the start and end time, beginning and ending ramp times and rate, and type required for delivery and receipt of the power and energy. Net Scheduled Interchange is the algebraic sum of all Interchange Schedules across a given path or between Balancing Authorities for a given period or instant in time. An Interchange Transaction Tag or Tag is an electronic tag that contains all of the transaction information and is used to populate the Interchange Distribution Calculator which identifies transactions that are impacting Flowgates. 7 Communication, submission, assessment and approval of a Tag must be completed for reliability consideration before implementation of the transaction. The Distribution Factor is the portion of an Interchange Transaction that flows across a transmission facility (Flowgate). The recent changes to the INT standards remove the requirements applicable to the Interchange Authority. RBRAG determined that this function should be removed as part of the registration process as the risk to reliability from any remaining Reliability Standards not being followed is minimal. Further, RBRAG recommends that for future consistency, conforming changes be made to Reliability Standards through the Standards Development Process. Applicable Reliability Standards Interchange Authorities are currently subject to the following NERC Reliability Standards: CIP CIP CIP-003-3a CIP CIP-004-3a CIP-005-3a CIP CIP-006-3c CIP CIP-007-3a CIP-007-3b CIP CIP CIP CIP CIP CIP CIP IRO-010-1a For the CIP Standards, the RBRAG has determined that all Interchange Authorities are also registered as either Balancing Authorities or Reliability Coordinators and therefore would still be responsible for compliance with those Standards. Proposed Revisions to IRO-010 include the removal of the Interchange Authority function from the applicability section. Compliance Metrics Of the approximately 7,500 unique confirmed violations or posted issues, there has been only one instance of noncompliance applied to solely the Interchange Authority function. This issue was of CIP-002, included in a Find, Fix, Track, and Report posting and posed a minimal risk to the reliability of the BPS. The entity at issue in this noncompliance is no longer included on the NERC Compliance Registry as an Interchange Authority. After review of compliance history and the nature of the issue, the RBRAG determined potential violations by Interchange Authorities pose little risk to the reliability of the BPS, and therefore supports the removal of the function from the NERC Compliance Registry. Conclusion Interchange Authorities can be removed from the NERC Compliance Registry with little to no impact on the reliability of the BPS. The Interchange Authority registration can be removed through the registration process, without awaiting the standards development process and associated approvals. With respect to the CIP standards, all of the Interchange Authorities are also registered as Balancing Authorities and/or Reliability Coordinators, 7 A Flowgate is defined in the NERC Glossary as: 1) A portion of the Transmission system through which the Interchange Distribution Calculator calculates the power flow from Interchange Transactions. 2) A mathematical construct, comprised of one or more monitored transmission Facilities and optionally one or more contingency Facilities, used to analyze the impact of power flows upon the Bulk Electric System. 7

13 Chapter 2 Removal of Interchange Authority from NERC Compliance Registry therefore no material reliability gap is created by eliminating the Interchange Authority registration prior to modifying the standards. Removal of the Interchange Authority references in the CIP standards can be addressed through after-the-fact cleanup. The removal of Interchange Authorities is consistent with the recently approved revisions to the Interchange Scheduling and Coordination Reliability Standards in Docket No. RD , which removed Interchange Authorities as applicable entities. 8

14 Chapter 3 Removal of Load-Serving Entity from NERC Compliance Registry The Risk-Based Registration initiative proposes to remove Load-Serving Entities as a functional entity from the NERC Compliance Registry. The removal of this entity will be implemented as part of the registration process and the RBRAG recommends that for future consistency, conforming changes be made to Reliability Standards through the Standards Development Process. Background In the NERC Glossary, a Load-Serving Entity is largely commercial contracting function that is responsible for acquiring sufficient energy and transmission service to serve the electrical demand and energy requirements of its end-use customers. Ownership of BES assets is not a criterion for Load-Serving Entity registration; owners and operators of BES Elements are registered under other functions. The Load-Serving Entity ensures an adequate power supply for its customers, including contracting for associated transmission service, to deliver that supply to a Distribution Provider, who is responsible for the final delivery to its end-use customers. Several NERC Reliability Standards are applicable to both Load-Serving Entities and Distribution Providers. In the Direct Energy case (Docket RC ), FERC found that a retail services provider did not qualify as the Load- Serving Entity under NERC s Registry Criteria, but FERC approved NERC s proposal to require that the [Distribution Provider] to whose system the electric loads in retail choice areas are connected are to be registered as the [Load- Serving Entity] for all loads connected to its system for the purpose of compliance with NERC s approved reliability standards applicable to the [Load-Serving Entity]. As a result, there is precedent that the currently assigned reliability activities of a Load-Serving Entity can be addressed by other registered entities. For BES reliability purposes, the RBRAG concluded that load-serving entity responsibilities have in practice been reassigned to other reliability functions. However, that reassignment varies depending on the market structure in place within each area and corporate structure decisions by registered entities. Three general types of Load- Serving Entities predominate:in addition, certain activities assigned to LSE are actually carried out by other functions. For example, load shedding is typically carried out by the Distribution Provider. 1. The first type of Load-Serving Entities located within the eastern Independent System Operator or Regional Transmission Organization area. These Independent System Operators and Regional Transmission Organizations are registered as Resource Planners and are responsible for procuring adequate resources for future service to all loads within their territories. For reliability purposes, Load- Serving Entity responsibilities are generally assumed by the Regional Transmission Organization. These Independent System Operators and Regional Transmission Organizations also act as Balancing Authorities, and as such they schedule resources to serve area load obligations. Therefore, Load-Serving Entity responsibilities are assumed by these Independent System Operators and Regional Transmission Organizations. In these Independent System Operators and Regional Transmission Organizations are only registered because of the co-registration requirement of Distribution Providers. Distribution Providers within market areas may enter into standard contracts under the supervision of their utility commission for provider-of-last resort power purchase contracts. In New Jersey, for example, the Board of Public Utilities of New Jersey holds annual basic generation service auctions for suppliers, and all New Jersey electric distribution companies are required to enter into basic generation service for their customers at common rates negotiated by the Board of Public Utilities. 2. The second type of Load-Serving Entities exists in areas where customer load is served by vertically integrated utilities with an obligation to serve. In these areas, the Load-Serving Entity s obligations are generally met within the integrated utility or affiliates that are registered as Resource Planners and Balancing Authorities. Planning and contracting for future resources is performed by these Resource 9

15 Chapter 3 Removal of Load-Serving Entity from NERC Compliance Registry Planners, and daily scheduling of resources is performed by the Balancing Authority. In these organizations, the Load-Serving Entity function is completely assumed by other functions. 3. The third type of Load-Serving Entity is presented by municipal and cooperatively-owned distribution utilities whose Load-Serving Entity obligations are met through contractual arrangements with other entities. These entities typically have full or partial requirements wholesale power supply contracts with another entity. The Resource Planner function may be performed by a vertically-integrated utility on behalf of the municipal or cooperative utility or by a municipal joint action agency or generation and transmission cooperative on behalf of its member Distribution Providers. These vertically-integrated utilities typically perform the Balancing Authority function as well. Independent System Operators and Regional Transmission Organizations other than the eastern Regional Transmission Organizations discussed above present a hybrid case, with elements of the three types described above. The default option would be that Load-Serving Entities are responsible for procuring sufficient capacity to meet their future load obligations and for making such resources available for dispatch by the Independent System Operators or Regional Transmission Organizations. In practice, this Resource Planner function is performed by each vertically-integrated utility on behalf of its own retail load or by a municipal joint action agency or generation and transmission cooperative on behalf of its member Distribution Providers. Applicable Reliability Standards Load Serving Entities are currently subject to the following NERC Reliability Standards: BAL b CIP CIP-002-3b CIP CIP-003-3a CIP CIP-005-3a CIP-006-3c CIP-007-3a CIP-007-3b CIP CIP EOP FAC INT IRO IRO a IRO-010-1a MOD MOD MOD MOD MOD MOD MOD MOD NUC TOP-001-1a TOP b PRC PRC

16 Chapter 3 Removal of Load-Serving Entity from NERC Compliance Registry Compliance Metrics Of the approximately 7,500 unique confirmed violations or posted issues, there have been 395 violations applied to solely Load-Serving Entity function, and another two (included in the PSE count) were for Load-Serving Entity and Purchasing-Selling Entity combined. Although there was an early history of noncompliance associated solely with Load-Serving Entities, there have been only six confirmed violations discovered since January 1, 2012 all were either of IRO-001 or TOP-001. The proposed new version of IRO-001 has already removed the Load-Serving Entity function from the applicability section and the RBRAG determined this function could also be removed from TOP-001 without creating a gap in reliability. After review of compliance history and the nature of the issues, the RBRAG determined the record supports the removal of the function from the NERC Compliance Registry, as it poses little risk to reliability. Regional Entity Survey Responses The Regional Entity responses supported the removal of the Load-Serving Entity function from the NERC Compliance Registry. ReliabilityFirst confirmed that if this function was eliminated from the Registry Criteria, it would still be able to obtain any necessary information for modeling and studies. In addition, ReliabilityFirst identified four Standard requirements for further review to determine if Load-Serving Entities were necessary for reliability. Two of these standards, EOP-002 R9.1 and TOP-002 R3, are already being revised to remove the Load-Serving Entity function. 8 The standard TOP-001 R4 already includes the Distribution Provider as an applicable function. Finally, VAR-001 R5 revision in Version 4, approved by the Commission, has removed the Load-Serving Entity function from its applicability section. Texas RE has determined that there would not be a reliability gap if Load-Serving Entities were removed from the NERC Compliance Registry. For example, there are 59 entities registered as a Load-Serving Entity in ERCOT region. Fifty-three of the 59 Load-Serving Entities are also registered for other functions. Consequently, there are only six Load-Serving Entities that are registered solely for that function in the ERCOT region. Texas RE determined that these six entities removal from the NERC Compliance Registry would not pose a reliability gap since these six entities have Market Participation agreements which can be more stringent than NERC Reliability Standards. Conclusion Load Serving Entities can be removed from the NERC Compliance Registry with little to no impact on the reliability of the Bulk-Power System. The Load Serving Entity registration can be removed through the registration process in parallel to the Standards Development Process and associated approvals. 8 Available at: and an_final.pdf 11

17 Chapter 4 Threshold Change for Distribution Providers Background Definition of Distribution Provider Pursuant to the NERC Functional Model, Distribution Providers are the functional entities that interconnect an end-use customer Load and the electric system for the transfer of electrical energy to the end-use customer. Distribution Providers provide and operate the wires between the transmission system and the end-use customer. For those end-use customers who are served at transmission voltages, the Transmission Owner also serves as the Distribution Provider. Thus, the Distribution Provider is not defined by a specific voltage, but rather as performing the distribution function at any voltage. Based on the Risk-Based Registration design, the Distribution Provider is proposed to be defined as follows: III(a) Distribution Provider: IIIa.1. Distribution Provider system serving > 75 MW of peak Load that is directly connected to the Bulk Electric System; 9 or III.a.2. Distribution Provider is the responsible entity that owns, controls, or operates Facilities that are part of any of the following Protection Systems or programs designed, installed, and operated for the protection of the BES: 10 A required Under-Voltage Load Shedding (UVLS) program and/or A required Special Protection System and/or; A required Transmission Protection System; or III.a.3. Distribution Provider that is responsible for providing services related to Nuclear Plant Interface Requirements (NPIRs) pursuant to an executed agreement; or III.a.4. Distribution Provider with field switching personnel identified as performing unique tasks associated with the Transmission Operator s restoration plan that are outside of their normal tasks. III(b) Distribution Provider with UFLS-only assets (referred to as UFLS-Only Distribution Provider ) IIIb.1. UFLS-Only Distribution Provider does not meet any of the other registration criteria for a Distribution Provider; and III.b.2 UFLS-Only Distribution Provider is the responsible entity that owns, controls, or operates UFLS Protection System(s) needed to implement a required UFLS Program designed for the protection of the BES. A UFLS-Only Distribution Provider shall be listed in the Compliance Registry as responsible for complying with PRC and any Regional Reliability Standard(s) whose purpose is to develop or establish a UFLS Program (excluding any then-existing Standard whose purpose is maintaining Protection Systems used for underfrequency load-shedding systems) in effect as of November 1, 2014, as well as any other Reliability Standards that identify UFLS-Only entities in their applicability section, but not the other standards applicable to a DP. 9 Ownership, control or operation of UFLS Protection System(s) needed to implement a required UFLS Program designed for the protection of the BES does not affect an entity s eligibility for registration pursuant to III.a As used in Section III.a.2, protection of the Bulk Electric System means protection to prevent instability, Cascading, or uncontrolled separation of the BES and not for local voltage issues (Under voltage load shedding) or local line loading management (Special Protection Systems) that are demonstrated to be contained within a local area. 12

18 Chapter 4 Threshold Change for Distribution Providers Applicable Reliability Standards Distribution Providers are currently subject to the following NERC Reliability Standards: CIP CIP CIP CIP CIP CIP CIP CIP CIP CIP COM COM COM * Pending regulatory approval EOP EOP FAC MOD NUC PRC a PRC b PRC PRC PRC-006-NPCC-1 PRC-006-SERC-01 PRC PRC PRC PRC-012-0* PRC PRC PRC PRC PRC PRC PRC PRC TOP-001-1a Definition of Bulk Electric System The revised Definition of BES went into effect on July 1, 2014 and includes processes for notifications of selfdetermined exclusions and inclusions, as well as exception requests to add elements to, or remove elements from, the BES on a case-by-case basis. Importantly, the BES Definition includes thresholds for transmission and generation owners and operators, but not users of the BES. Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements operated at 100 kv or higher and Real Power and Reactive Power resources connected at 100 kv or higher. This does not include facilities used in the local distribution of electric energy. o o o o o Inclusion I1 (Transformers): Transformers with the primary terminal and at least one secondary terminal operated at 100 kv or higher unless excluded by application of Exclusion E1 or E3. Inclusion I2 (Generating Resources): Generating resource(s) including the generator terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kv or above with: a) Gross individual nameplate rating greater than 20 MVA. Or, b) Gross plant/facility aggregate nameplate rating greater than 75 MVA. Inclusion I3 (Blackstart Resources): Blackstart Resources identified in the Transmission Operator s restoration plan. Inclusion I4 (Dispersed Power Producing Resources): Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and that are connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage of 100 kv or above. Thus, the facilities designated as BES are: a) The individual resources, and b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than 75 MVA to a common point of connection at a voltage of 100 kv or above. Inclusion I5 (Static or Dynamic Reactive Power Devices): Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at 100 kv or 13

19 Chapter 4 Threshold Change for Distribution Providers o o o o higher, or through a dedicated transformer with a high-side voltage of 100 kv or higher, or through a transformer that is designated in Inclusion I1 unless excluded by application of Exclusion E4. Exclusion E1 (Radial Systems): A group of contiguous transmission Elements that emanates from a single point of connection of 100 kv or higher and: a) Only serves Load. Or, b) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with an aggregate capacity less than or equal to 75 MVA (gross nameplate rating). Or, c) Where the radial system serves Load and includes generation resources, not identified in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating). Note 1 A normally open switching device between radial systems, as depicted on prints or oneline diagrams for example, does not affect this exclusion. Note 2 The presence of a contiguous loop, operated at a voltage level of 50 kv or less, between configurations being considered as radial systems, does not affect this exclusion. Exclusion E2 (Behind the Meter Generation): A generating unit or multiple generating units on the customer s side of the retail meter that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator Operator, or under terms approved by the applicable regulatory authority. Exclusion E3 (Local Networks): Local networks (LN): A group of contiguous transmission Elements operated at less than 300 kv that distribute power to Load rather than transfer bulk power across the interconnected system. LN s emanate from multiple points of connection at 100 kv or higher to improve the level of service to retail customers and not to accommodate bulk power transfer across the interconnected system. The LN is characterized by all of the following: a) Limits on connected generation: The LN and its underlying Elements do not include generation resources identified in Inclusions I2, I3, or I4 and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating); b) Real Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery through the LN; and c) Not part of a Flowgate or transfer path: The LN does not contain any part of a permanent Flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL). Exclusion E4 (Reactive Power Devices): Reactive Power devices installed for the sole benefit of a retail customer(s). As demonstrated above, the greater than 75 MW peak load threshold for the Distribution Provider function tracks as an equivalent to the 75 MW dispersed generation threshold in the BES Definition. 14

20 Chapter 4 Threshold Change for Distribution Providers Materiality If an entity meets the Registry Criteria, there is a rebuttable presumption that it has a material impact on the reliability of the BPS, and it is in a pool of eligible candidates that NERC and the Regional Entities may identify for registration. NERC and the Regional Entities may exercise discretion not to pursue registration of an entity that meets the Registry Criteria threshold criteria if not warranted by reliability considerations. Where registration is pursued, an entity that meets the Registry Criteria threshold criteria may nevertheless be able to demonstrate through a materiality test that it is not material to reliability and should not be registered. In addition, the materiality test may be used to establish that an entity that does not meet Registry Criteria should be registered because it does have a material impact on reliability. Such a process parallels the BES Definition and exception process, where after application of the bright-line criteria, exceptions can be justified (both above-the-line and below-the-line). Therefore, if a Distribution Provider does not meet the criteria outline above, but does have a material impact on reliability, it can be registered by NERC and the Regional Entities and would be subject to NERC Reliability Standards. Methodology NERC conducted a survey in order to assess the impact of modifying the criteria for Distribution Providers and an analysis was conducted by Reliability Coordinators to determine the consequences of not having operational data from Distribution Providers under 75 MW and to determine the consequences of not having a required maintenance standard for a small sub-set of Distribution Providers 1. For the Distribution Providers that have under 75 MW peak load and will no longer be on the NERC Compliance Registry, what would be the consequences these Distribution Providers not providing operational data to their Reliability Coordinators? 2. For the Distribution Providers that have UFLS under 75 MW peak load, if 25% of the UFLS did not respond what would the consequences be (e.g. cascading outages, etc.)? This analysis is designed to determine the extent to which Distribution Providers perform functions that have an impact on the reliability of the BPS. Results All survey respondents stated that no reliability gaps would be created by raising the Distribution Provider threshold to 75 MW. Reliability Coordinators have removed over 40 Distribution Providers/Load-Serving Entities from the NERC Compliance Registry since November 2013 and have continued to receive operating data necessary to properly monitor the BBPS. In addition, respondents stated there have been no instances of entities that have been removed disregarding reliability directives. Statistical analysis have determined that the removal of Distribution Providers from the NERC Compliance Registry and the effects of UFLS Distribution Providers not providing their load shedding obligation is statistically insignificant. Studies submitted indicate that the effects of not receiving operational data from Distribution Providers expected to be removed from the registry has no adverse impacts to the BPS. Additional analysis of the impact of modifying the criteria for Distribution Provides is ongoing. Please refer to Appendix B for actual studies. 15

21 Chapter 4 Threshold Change for Distribution Providers Reliability Impacts of Distribution Providers between MW peak load with UFLS Schemes Overview The RBR initiative proposes to increase the criteria for registration of Distribution Providers from the current 25 MW peak load value, to 75 MW, with a provision to retain registration of Distribution Providers below 75 MW if they have UFLS systems. The proposal would also retain registration of Distribution Providers below 75 MW which own or operate Protection Systems important for reliability such as Special Protection Systems, Remedial Action Schemes, UVLS, or other transmission Protection Systems, in addition to UFLS systems. Approach This assessment is a screening evaluation and designed to determine if there is any evidence to indicate whether the proposed changes significantly increase the risk to reliability. This assessment does not detail the potential impact for any individual system; rather, it explores the overall potential or increased likelihood, if any, of an adverse reliability impact (uncontrolled, cascading instability, etc.). NERC requested the following information from all (83) Planning Coordinators: List of Distribution Providers less than 75 MW in the Planning Coordinator s area Distribution Provider peak demand Planning Coordinator peak demand Planning Coordinator load armed for UFLS (total program) If any Distribution Providers (less than 75 MW) have a UFLS program, how much load is armed per Distribution Provider Other BES facilities/responsibilities (e.g., UVLS, SPS or RAS, transmission Protection Systems, etc.) Data was collected on a voluntary basis. Population Analyzed Of the 83 Planning Coordinators, which represent approximately 800 GW of load (based on the Summer Assessment), 63 Planning Coordinators responded representing 650 GW (76%) of NERC-wide non-coincident peak demand. Of those respondents, Planning Coordinators representing 310 GW of load have UFLS programs in which Distribution Providers under 75 MW participate. Those Distribution Providers located in these Planning Coordinators represent a total of approximately 2,650 MW of load. Details of the data analyzed are shown in Figure 1. As more Planning Coordinator data comes in, updated statistics and studies can be found on the Risk-Based Registration page available at: 16

22 Chapter 4 Threshold Change for Distribution Providers Figure 1 Population and Demographic Dispersion of the Analyzed Population Caveats NERC received limited or no information for two of the regions, and partial information for several others. Sample data is based on 76% (63 out of 83) of Planning Coordinators responding Sample data represents 81% (650 GW out of ~800 GW) of all NERC load in the United States Evaluation is based on "peak demand" value o It is unknown whether a forecasted or actual peak demand value was reported o Forecasted peak demand values are subject to assumptions of customer's electrical usage and load characteristics; whereas, actuals are highly sensitive to seasonal weather Statistical Analysis Projected load was used as the basis for the analysis. NERC-Wide Load Table 1: Evaluation of Peak Demand and DP UFLS Screening ~800,000 MW Total Planning Coordinator load reported (Population Analyzed) Total load of Planning Coordinators with Distribution Providers <75 MW Total Distribution Provider load <75 MW 650,000 MW 408,000 MW 2,650 MW Percentage of Distribution Provider load <75 MW to NERC-wide load <0.34 % Number of Distribution Providers <75 MW who contribute to Planning Coordinator s UFLS program Planning Coordinator load armed with UFLS (for Planning Coordinators with Distribution Providers <75 MW, 25% to 30% of total Planning Coordinator load) Reported load shedding contribution to UFLS Programs by those Distribution Providers <75 MW 38 (out of 485) 120,000 to 102,000 MW 800 MW Load contribution to the Planning Coordinator s UFLS program 0.78 % to 0.65 % 17