agenda item 4.a: update on regional challenges highlights and...• planning tasks task 1.1 –...

NERC Planning Committee Meeting June 10-11, 2014, Orlando, FL

Agenda Item 4.a: Update on Regional Challenges MRO Region Challenge: Transition of Modeling Responsibilities per MOD-032-1 NERC Modeling Data Standard MOD-032-1 has been approved by the Commission on May 1, 2014. Requirement R1 of the approved Standard, which becomes effective July 1st, 2015, requires that Planning Coordinators and Transmission Planners jointly develop data reporting requirements for the data owners in their Planning Area. Requirement R4 of the new standard requires that the Planning Coordinators provide their model data to the Interconnection model builder. For the Eastern Interconnection, this will likely be the MMWG group under the ERAG.

Identification of Challenges The following bullets highlight the concerns raised in transitioning from the MRO subcommittee-led model building approach to multiple PC models:

• Exchange of data between all five Planning Coordinators o PCs have intermingled geographic boundaries o Coordination of mixed planning area tie-lines and transactions o Accurate modeling in the greater Dakotas and along other model seams o Example: There are approximately 1,000 intermingled PSS/E model buses in the Dakotas

that will be split about 50/50 between SPP-RTO (WAPA/BEPC) and MISO/MAPP. Similar issues exist in MN and IA.

• How will MISO provide data to ERAG as it spans multiple regional entities?

• Per R1.1, can the PCs identify their respective planning areas?

• How are the PCs and TPs collaborating to develop model procedures?

• Model Building Schedules o PCs presently have different model building schedules. o Business practices suggest leaving schedules as-is.

• PCs feel they must house their member data in their own Models on Demand (MOD) database

due to data confidentiality/market sensitive information.

• PCs must agree to a common denominator of necessary models so that their individual business practice modeling needs can be met.

• What role should MRO play, if any, in providing the PC models to the ERAG MMWG?

• Explicit PC model construction would create many data coordination issues, represented in the image below. The standard does not preclude implicit model practices where better suited.

MRO Model Task Force Formed

In May of 2014, the MRO Planning Committee proposed the creation of a new MRO Model Task Force (MMTF). The task force will determine how the five Planning Coordinators in MRO (Manitoba Hydro, MAPP, MISO, SPC, and SPP-RTO) will develop model building processes under the new MOD-032-1 requirements. The MMTF shall report to the Midwest Reliability Organization Planning Committee.

MRO recommendations for discussion by the MMTF include:

• PCs should develop common procedural manuals (based on MMWG manual). Cases should be generic enough that PCs can create their own study models as needed by the TPL standard.

• Encourage alignment of data pools with definite, not mixed, planning areas. • Consider a common custodian and data repository for mixed planning areas.

• Discourage tariff criteria which conflicts with the plain meaning or implementation of ERAG/MMWG model requirements. Requirements and processes for planning models should be developed independent to market/operations requirements.

• Discourage support of uncoordinated or unsanctioned models derived from Model on Demand database. This means the models provided by the PCs must have clear boundaries and be capable of being readily merged into the interconnection-wide cases. This is currently done by submitting Region Entity footprint models with inter-regional tie lines coordinated via spreadsheet.

• Assign all MRO data submitters their own PSS/E area number to facilitate the coordination of tie lines and interchange between SPP/MISO/MAPP entities in the greater Dakotas and elsewhere. Currently in the MRO models, multiple entities can be assigned the same PSS/E area number. Unique area numbers for each company may promote streamlined model review, communication, and sharing of data between planning coordinators.

Essential Reliability Services NERC Staff Report & Work Plan Planning Committee/Operating Committee MeetingsJune 10-11, 2014

RELIABILITY | ACCOUNTABILITY2

• Expected resource mix has different characteristics: Variable energy-only resources, derated capacity Limited inertial rotating mass Less operator flexibility Displace large machines and their inherent contributions to reliability

2013 LTRA Recommendation• Develop primer on essential reliability services (ERS): Develop a reference document on ERS Operational requirements needed to ensure bulk power system (BPS)

reliability

Resource Change key to ERS


• Task Force formed as a joint effort between PC and OC• Scope was approved in December 2013• First deliverable near completion – ERS Tutorial• Next step is to develop approach and framework for the long-

term assessment of ERS• Team Ken McIntyre – Chairperson Todd Lucas – Vice Chair NERC Lead – John Moura (PC), Larry Kezele (OC) Incredible mix of technical support staff from NERC, industry experts and

vendors.

Essential Reliability Services Task Force


Objectives of ERS Tutorial

• Identify each of the essential reliability services Simple tutorial Functional, technology neutral, and performance-

based • Importance of ERS for reliability How does the resource mix change ERS? What happens when you don’t have ERS?

• Target Audience: regulators, policy makers, and industry leadership

• Moving to final comments & approvalhttp://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERS%20Draft%20Concept%20Report.pdf

http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERS%20Draft%20Concept%20Report.pdf


• Reliability “Building blocks” • Accentuated by resource changes• Partly covered through ancillary services• Accommodate local/regional needs• Focus on the ‘What’

ERS Fundamentals

Resource Adequacy

Essential Reliability Services

Reliability


Six Essential Reliability Services identified:• Operating Reserve • Frequency Response • Ramping Capability • Active Power Control • Reactive Power and Voltage Control • Disturbance Performance

“Are there others, now – future?”

Identified Essential Reliability Services


Important Research

• Physics of the Bulk Electric System remain constant Voltage, frequency and load/resource balance require ERS to be supported

at all times

• Not all MWs are equal Having adequate reserve/capacity does not equate to having the essential

functional capabilities and inherent characteristics

• Changing resource mix requires evaluation of ERS “Reliability building blocks” are integral to a reliability BES and must be

addressed regardless of the resource mix


• Task Force Face to Face Meeting (June 2014) Finalize schedule to have the ERS Tutorial approved Technical discussion on each ERS and their attributes Develop and initiate ‘a’ framework:o Measures for planning and operations timeframeso Identify parameters and performance needso Develop reference and guidance documents o Coordinate initiatives, guidelines, and standards

• Collect data from industry using framework after Q4 2014, with ongoing assessment, and tentatively completed by Q4 2015.

Next Steps

IVGTF RecommendationsReportJohn Moura, Director of Reliability Assessment, NERCPlanning Committee Meeting June 10-11, 2014


Variable Resources Fuel• North America is anticipating a significant growth in VG resources over the

coming ten years, making it clear that the need to reliably integrate these resources into the grid is no longer a question, it is a priority.

• Nameplate renewable capacity (including wind, solar, hydro, biomass, and geothermal) will grow by approximately 55 GW by 2023. With over 35 GW of planned nameplate capacity, wind accounts for over half (64 percent) of these additions. Driven in large part by new policies and environmental priorities, this growth will drive one of the largest new resource integration efforts in the history of the electric industry.

Overview


• The ongoing efforts brought together by NERC and its stakeholders have the potential to fundamentally change how the system is planned, operated, and used – from the grid operator to the average customer. It has truly been a pioneering effort, lead by NERC’s Integration of Variable Generation Task Force or IVGTF over a period of 4 years plus.

• Recognizing the increasing long term VG trend and the accomplishment of the 12 IVGTF efforts that address broader and detailed aspects of the effect of VG on the reliability of BPS will require significant changes to traditional methods used for system planning and operation

About IVGTF


• Planning Tasks Task 1.1 – Generic Wind Turbine Models Task 1.5 – Incorporating PHEV, Storage, DR into Planning Process Task 1.8 – Incorporating Variable DER into the Planning Process

• Interconnection Tasks Task 1.3 – Interconnection Requirements Task 1.7 – Reconciliation of Order 661-A and IEEE 1547 Task 2.2 – BA Communication Requirements

IVGTF Work Plan Organization


Operations Tasks Task 2.1 – VG Power Forecasting for Operations Task 2.3 – Ancillary Service and BA Solutions to Integrate VG Task 2.4 – Improved Operating Practices with VG

• Probabilistic Tasks Task 1.2 – Capacity Value Methods Task 1.4 – Flexibility Requirements and Metrics Task 1.6 – Probabilistic Methods

IVGTF Work Plan Organization


IVGTF Objectives


• IVGTF Recommendations Categories: Consideration for Specific Standards Modifications Consideration for Potential Standards Considerations for Planning Guidelines Considerations for Operating Practice Guidelines Enhancement to Modeling More Research and Development Education and Training Data Collection

• Each task force incorporate more than one category• In some cases, decision is needed to warrant specific

recommendation category to standards or to planning/operating guidelines

IVGTF Recommendations Categories


• NERC MOD Standards Development Task 1-1: Standard Models for Variable Generation Task 1-3: Interconnection Requirements for Variable Generation

• VG for Resource Adequacy In Operation and Planning Task 1-2: Methods to Model and Calculate Capacity Contributions of

Variable Generation for Resource Adequacy Planning. Task 1-4: Flexibility Requirements and Metrics for Variable Generation:

Implications for Planning Studies Task 1-5: Potential Reliability Impacts of Emerging Flexible Resources Task 1-6: Probabilistic Methods

IVGTF Recommendations Topics


• Interconnection Requirements Task 1-2: Methods to Model and Calculate Capacity Contributions of

Variable Generation for Resource Adequacy Planning. Task 1-3: Interconnection Requirements for Variable Generation Task 1-7: Performance of Distributed Energy Resources During and After

System Disturbance Voltage and Frequency Ride-Through Requirements. Task 2-2: Reliability Considerations for BA Communications with Increased

Variable Generation

• Flexibility Requirements Task 1-4: Flexibility Requirements and Metrics for Variable Generation:

Implications for Planning Studies Task 1-5: Potential Reliability Impacts of Emerging Flexible Resources Task 1-6: Probabilistic Methods Task 2-1: Variable Generation Power Forecasting for Operations Task 2-4: Operating Practices Procedures and Tools



• Recommendations for Reactive Power & Voltage Control Requirements Task 1-1: Standard Models for Variable Generation Task 1-3: Interconnection Requirements for Variable Generation

• Recommendations for Disturbance Requirements Task 1-3: Interconnection Requirements for Variable Generation Task 1-7: Performance of Distributed Energy Resources During and After

System Disturbance Voltage and Frequency Ride-Through Requirements. Task 2-4: Operating Practices Procedures and Tools

• Recommendations for Active Power Control Capabilities Task 1-1: Standard Models for Variable Generation Task 1-3: Interconnection Requirements for Variable Generation Task 1-7: Performance of Distributed Energy Resources During and After

System Disturbance Voltage and Frequency Ride-Through Requirements.



• Recommendations for Communications Requirements Task 1-3: Interconnection Requirements for Variable Generation Task 1-5: Potential Reliability Impacts of Emerging Flexible Resources Task 2-1: Variable Generation Power Forecasting for Operations Task 2-2: Reliability Considerations for BA Communications with Increased

Variable Generation Task 2-4: Operating Practices Procedures and Tools.

• Recommendations for Data Collections Task 1-2: Methods to Model and Calculate Capacity Contributions of

Variable Generation for Resource Adequacy Planning. Task 2-2: Reliability Considerations for BA Communications with Increased

Variable Generation



• Recommendation for Harmonics and SubsynchronousInteraction Task 1-3: Interconnection Requirements for Variable Generation

• Recommendations for VG Power Forecasting Task 1-4: Flexibility Requirements and Metrics for Variable Generation:

Implications for Planning Studies Task 1-5: Potential Reliability Impacts of Emerging Flexible Resources Task 2-1: Variable Generation Power Forecasting for Operations

• Recommendations for Ancillary Services Requirements Task 2-3: Ancillary Services and Balancing Authority Area Solutions to

Integrating Variable Generation Task 2-4: Operating Practices Procedures and Tools



NERC MOD Standards Development and Reconciliation Provide sufficient clarity to model variable generation Support simulation of power system with high amounts of variable

generation aiming to incorporate variable generation considerations in the next release of the following draft standards.

Task 1-1 and Task 1-3

IVGFT Recommendations Topics


• VG for Resource Adequacy In Operation and Planning Resource adequacy models (e.g. LOLP models) that reflect the much lower

availability or lower load carrying capability of variable generation Measure variable generation performance factors such as capacity factors

and peak coincidence. More Research using probabilistic methods for reserve calculations,

dispatch , unit commitment, maintenance, generation and transmission planning

Task 1-2, 1-4, 1-5, 1-6



Interconnection Requirements Enhancements to current models and provide guidelines. NERC should enhance its Reliability Standards by organizing Standard

Authorization Requests or supporting existing Standard development processes including but not limited to the following Standards requiring potential changes - Revisions to existing interconnection standards Models for facility interconnections studies - consideration for MOD 24 to MOD 27 enhancements

Detailed dynamic (and possibly transient) models for the specific equipment may be needed for the System Impact Study and Facilities Study to represent the facility and other equipment in the electrical vicinity Provide sufficient clarity to model variable generation.

Support simulation of power system with high amounts of variable generation

DER interconnection standards revision efforts Interconnections for breaker requirements Tasks 1-2, 1-3, 1-7, 2-1and 2-2



Flexibility Requirements Probabilistic planning methods being developed in NERC’s IVGTF Task 1-6

will be a vital improvement to assess required flexibility. set of best planning practices to design systems with sufficient system

flexibility to accommodate targeted levels of variable generation should be documented.

Develop and collect metrics that measure flexibility needs for variable generation. For example, calculating a set of ramp and intensity metrics can provide insights on flexibility trends.

The electric power industry should pursue research and development activities to assess the flexibility needs for the regional and interregional systems of North America as well as evaluate the benefits of flexible resources and technologies (i.e., Demand Response (DR), electric and thermal energy storage, and plug-in electric vehicles (PEVs)) on their respective systems

IVGFT Recommendations


Flexibility Requirements Advances and enhancements that inform all resources of the value of

needed flexibility services and incent desired response while discouraging undesired response will be needed -For example, the development of a tariff for PEV owners that would discourages charging during peak hours and encourages charging during off-peak hours.

Maintenance: maintenance scheduling may be more difficult in market regions where there is limited central authority to coordinate scheduled maintenance, and high levels of VG will likely have a significant influence. Methods to quantify the risk of both capacity shortfalls and flexibility shortfalls can be developed and tested in industry.

Generation planning: there have been new methods developed to begin quantifying flexibility needs and risks of insufficient flexibility within generation expansion planning algorithms, so that results balance investment in VG with investments in technologies providing the flexibility that VG requires.



Flexibility Requirements The IVGTF suggests that those balancing areas who face significant

integration of variable resources consider studying the benefits of sub-hourly scheduling to manage the integration of variable generation. Depending on the current or projected BA system characteristics, assuming sufficient transmission is available, there may be benefits to intra-hour interchange scheduling, in the form of reduced ancillary services, more flexibility and ability to manage the variability, while still meeting the requirements of NERC’s Reliability Standards.

Tasks 1-4, 1-5, 1-6, 2-1, 2-4



Recommendations for Reactive Power & Voltage Control Requirements MOD-025-1 "Verification of Generator Gross and Net Reactive Power

Capability" Recommendation: Clarification may be needed. NERC should consider revisions to FAC-001 NERC should consider revisions to VAR-001 standards NERC should promote greater uniformity and clarity of reactive power

requirements contained in connection standards. NERC should consider initiating a Standards Authorization Request (SAR) to

establish minimum reactive power capability standards for interconnection of all generators, and provide clear definitions of acceptable control performance.

Applicability Recommendations for Generator interconnection requirement for reactive power

Specification of Reactive Range defined over the full output range, and it should be applicable at the point of connection



Recommendations for Reactive Power & Voltage Control Requirements

Impact of System Voltage on Reactive Power Capability: It should be recognized that system voltage level affects a generating plant’s ability to deliver reactive power to the grid and the power system’s requirement for reactive support

Specification of Dynamic Reactive Capability: The standard should clearly define what is meant by “Dynamic” Reactive Capability by specifying the portion of the reactive power capability

Definition of Control Performance: Expected volt/var control performance should be specified.

Specification of Dynamic Reactive Capability: The standard should clearly define what is meant by “Dynamic” Reactive Capability by specifying the portion of the reactive power capability that is expected to be dynamic



Recommendations for Reactive Power & Voltage Control Requirements

Definition of Control Performance: Expected volt/var control performance should be specified, including minimum control response time for voltage control, power factor control and reactive power control. An interim period for the application of precisely defined control capabilities should be considered.

Task 1-1, More details in Task 1-3



Recommendations for Disturbance Requirements In the short-term, NERC should engage in current efforts to revise DER

interconnection standards by providing information, supporting the efforts of IEEE with transmission reliability subject-matter experts, raising industry, regulator, and policy maker awareness, and encouraging the consideration of the explicit VRT and FRT for DERs.

The initial focus should be on potential ways to adopt minimum tolerance thresholds for VRT and FRT in the IEEE Standard 1547 while balancing against other important distribution issues such as safety and protection/coordination.

The task force also offers general guidelines on VRT and FRT specifications for distributed VERs and other DERs, for consideration in the P1547a process or future IEEE Standard 1547 revision.

Generator Frequency and Voltage Protective Relay Settings Control Performance and Disturbance Control Requirements Tasks 1-3,1-7, and 2-4



Recommendations for Active Power Control Capabilities NERC should investigate variable generating plants to at an active power

level where dynamic reactive capability is limited or zero. Active power requirement during a voltage disturbance unless there is a

reliability concern – PRC-024 standards Require VG Curtailment Capability.o Variable generation plants should be required to have the capability to limit the

rate of power increase. o Plants must be able to accept commands to enable pre-selected ramp rate

limits. Encourage or Mandate Reduction of Active Power in Response to High

Frequencies Consider Requiring the capability to provide Increase of active Power for

Low Frequencies Summary of Facility Connection Model Grid Code Requirements:. tests

shall be performed: Power Ramping and Power Curtailment Tasks 1-1, 1-3, 1-7



Recommendations for Communications Requirements Communications between Variable Generation Plants and Grid Operators Technical Developmentso Development of an operational infrastructure that provides visibility and control

(direct or indirect) of distributed resources such as Demand Response and PEVs For the Industryo Wind and solar plants require real-time meteorological and electrical data

through SCADA systems using standard communication protocols for use in forecasting and system operation, including power, availability, curtailment and meteorological data.

For the Standards: COM-002 (Communication and Coordination) Communication Recommendations for Wind Resourceso Data and communication capabilities should be provided to the BA by all

generation operating in the BA Wind and solar plants should have the capability to send and receive real-

time data (meteorological and electrical) through SCADA systems. Tasks 1-3, 1-5, 2-1, 2-2, 2-4



Recommendations for Data Collections NERC should design and implement a way to collect high-quality variable

generation data that would help inform calculations of capacity value.o Covered in Task 1-2

Data and communication capabilitieso Covered in Task 2-2

Recommendation for Harmonics and Subsynchronous Interaction

design study reports that assess the harmonic performance of all wind and solar plants

understanding of the control interactions, assess the risk, and if necessary mitigation, of wind and solar plants located near series compensated transmission lines or HVDC terminals.

Task 1-3



Recommendations for VG Power Forecasting Wind forecast error model New NERC Reliability Standards that provides for regional forecasts and

local Use of the forecast in unit commitment planning is very important Covered in Task 1-5, 2-1 Standards revisions:o FAC -001: Facility Connection Requirementso TOP-002-2.1b:Normal Operations Planningo TOP-006-2: Monitoring System Conditionso BAL-002-1: Disturbance Control Performanceo COM-002-2Communications and Coordinationo IRO-005-3.1a: Reliability Coordination – current day operation

Tasks 1-4, 1-5, and 2-1



Recommendations for Ancillary Services Requirements• Each region or reserve-sharing group should permit Contingency Reserve

deployment under imbalance energy circumstances • The task team recommends that the generator interconnection

requirements be modified to require this dispatchable control capability interfaced .

• Regional market operators and other grid operating entities should develop the ability to consider transmission service by prioritizing variable resources when allocating curtailment responsibility to variable output resources during reliability-limited operating conditions.

• Depending on the current or projected BA system characteristics, assuming sufficient transmission is available, benefits to intra-hour interchange scheduling, in the form of reduced ancillary services, more flexibility and ability to manage the variability, while still meeting the requirements of NERC’s Reliability Standards.

• Tasks 2-3, 2-4


Wind GADS Reporting White PaperGary S. Brinkworth, Chair, GADS Working GroupPlanning Committee Meeting June 10-11, 2014


Purpose

• The winds GADS reporting white paper provides a forum to address 3 key issues associated with the increasing contribution of wind generation in the resource portfolio: To highlight the need to include wind resources in mandatory GADS

reporting

To seek PC endorsement for completing the Data Reporting Instructions (DRI) for wind currently being drafted by a subteam of the GADSWG

o Implications for the GADSWG work plan & RAPA budget

To explore the possible timeline for capturing wind data for use in reliability assessments


GADS Overview

• Generator Availability Data System (GADS) came from the Edison Electric Institute in 1979 and became the database for NERC in 1982.

• Started as an equipment reliability database with the goal of improving the performance of generating plants.

• Mandatory GADS reporting started in January 2012 for all conventional (fossil & hydro) generating units 50 MW & larger. Reporting for units 20 MW & larger started in January 2013. This reporting includes design information, performance and outage event

records

• Renewable resources (wind and solar) presently not included in mandatory GADS reporting


GADS Reporting Framework

• Before the mandatory GADS, generating companies reported GADS data on a voluntary basis.

• Changes and updates to the GADS Data Reporting Instructions (DRI) were presented at workshop or by email for comments and discussions.

• All data collection, editing and data storage was provided by NERC staff.

• OATI has taken over the data collection aspect; changes to the GADS DRI will now go through the GADSWG.


Purpose of GADSWG

• The Generating Availability Data System Working Group (GADSWG) is to implement a uniform approach to reporting and measuring North American generating plant availability, performance and other related reliability data.

• GADSWG was formed by the NERC PC in late 2011

• To accomplish its purpose, the GADSWG will perform the following activities:• Review and recommend new

generation availability data that should be subject to mandatory collection by NERC.

• Review additions and changes to the GADS Data Reporting Instructions (DRI).

• Analyze, assess and report on trends and risks to reliability from generator availability and performance.


How Did We Get Here?

• Mandatory reporting of NERC-GADS Wind data was evaluated by the GADSTF Wind Subgroup in the fall of 2010, and a draft report was prepared recommending a phased-in approach for including wind resources in mandatory GADS reporting, similar to the approach recommended for fossil and hydro resources.

• However, after consulting with the NERC Reliability Issues Subcommittee (RIS), it was decided that renewable units would be investigated separately


How Did We Get Here?

• Shortly after the GADSTF report was submitted to the NERC PC (July 2011), the standing committees were reorganized and the NERC RIS was disbanded.

• No subsequent report was ever completed on the appropriate strategy to incorporate wind resources into the mandatory GADS collection process

• The GADSWG has developed a strategy for incorporating wind resources into mandatory GADS. Wind is a growing component in the resource mix and needs to be tracked


The Contribution of Wind

The 2013 LTRA projected a significant contribution from wind and other variable generation resources thru 2023:

Currently there is no consistent reporting of wind generator data or performance that would enable NERC to assess the implications to BES reliability


The Case for Wind Reporting

Wind generation continues to grow at a robust pace and will probably exceed hydro generation around 2017.

As a result some bulk power distributors are already seeing impacts to their planning and reserve requirements.

The challenge for transmission managers and power distributors is to integrate the variable nature of wind generation into the energy mix.

This analysis can’t be properly completed without accurate data


The Reliability Business Case

The Reliability Business Case

• As the contribution from wind in the resource mix grows, data collection becomes more important to the full assessment of BES reliability

• Performance data on wind turbines, along with outage data, will be key to understanding the impacts from this intermittent resource on system response characteristics and operational planning/reliability targets as well as more traditional resource adequacy assessments

• Additional benefits from benchmarking & trend analysis will be available to inform best practices for operations and maintenance functions similar to the benefits available from thermal/hydro GADS

• A paper on the reliability business case for wind GADS data collection is being finalized


Key Sections of the White Paper

• Status of the Wind Data Reporting Instructions (DRI)• Mandatory Wind Data Collection• Consequences of Further Delay• Challenges for Implementation• Recommendation & Proposed Work Plan


Wind GADS Action Plan

• Complete the development of the wind DRI Requires some technical support funded

by NERC• Conduct an internal review of the DRI GADSWG, PAS and PC at a minimum

• Solicit industry comment on the DRI and revise as necessary

• Implement a phased approach to data collection following NERC BOT approval to add wind to mandatory GADS


Challenges

• DRI Process – Completion of the revised Wind DRI depends upon the perceived urgency by the PC. If the PC review and public comment go smoothly, mandatory reporting for wind could occur as early as 2016.

• Budget – Funds are needed for software development, implementation, training and maintenance.

• Implementation – Implementation itself requires several steps: 1) Having a finalized Wind DRI 2) Fully developed software specifications 3) Completed data collection and reporting software development 4) Testing` the software with actual plant data 5) Training for NERC staff and data reporters.

Delaying the start of a process to bring wind resources into mandatory GADS compromises NERC’s ability to effectively assess the reliability implications of this resource


In Conclusion

This presentation had 3 objectives: To highlight the need to include wind resources in mandatory GADS

reporting To seek PC endorsement for completing the Data Reporting Instructions

(DRI) for wind currently being drafted by a subteam of the GADSWG To explore the possible timeline for capturing wind data for use in

reliability assessments


Appendix


Wind Facts

• Commercial wind development began in the early 1980’s with small 15 – 45 kW turbines.

• Over the next 30 years turbine size has increased to as much as 3.6 MW with the largest plant containing 338 turbines, for a total of 845 MW.

• In 2012, wind generation provided 3.5% of U.S. generation up from 2.9% in 2011.

• According to an NREL report, by 2050 this could reach almost 30%.


Wind Plants by MW Size

Table 1 - Installed Cumulative Wind Plant Capacity Distribution

Installed Capacity (MW) 2007 2008 2009 2010 2011 2012

2013est.

2014est.

2015est.

2016est.

2017est.

<25 48 93 143 208 255 340 435 535 637 744 854

25-49.9 51 64 77 83 96 114 133 153 173 195 218

50-74.9 33 50 67 77 86 98 118 140 162 187 214

75-99.9 23 38 48 58 66 81 97 117 138 166 198

100-149.9 29 52 71 81 93 125 158 191 224 259 295

150-199.9 10 25 37 43 55 67 87 109 127 146 165

>200 22 23 28 33 38 56 75 98 112 128 145

Total 216 345 471 583 689 881 1103 1343 1573 1825 2089Note: 2007 to 2012 derived from AWEA Market Reports.

Table 1 shows the cumulative number of Wind Plants for various installed MW capacities. The table not only demonstrates the rapid growth in wind but also the number of plants for each implementation phase (Yellow) (January 2016 we estimate 112 – 200 MW plus plants, 421 – 100 MW or greater MW plants January 2017 and 270 - 75 MW plants or greater January 2018.)

2014 Long-Term Reliability Assessment PC Update

Layne Brown, RAS ChairPC Meeting – Orlando, FloridaJune 10-11, 2014


• Review 2014 LTRA schedule and PC expectations• Review supplemental requests (Gas-Electric; Smart Grid

Transmission System Devices and Applications)• Overview of MRC Survey: 2014 Long-Term Reliability Challenges

and Emerging Issues

Overview


2014 LTRA Schedule

Date DeliverableMon, Jan 6 Data and Narrative RequestWed, May 7 MRC Input via SurveyFri, May 23 Data and Narratives due to NERCFri, May 30 MRC Survey ClosesTue-Wed, Jun 17-18 RAS Meeting: Peer Review of NarrativesFri, Jun 27 Final Narratives and Data Due to NERCTue-Wed, Aug 12-13 RAS Meeting: Final Review of ReportMon, Sep 8 Report Sent to PC, OC, and MRC for ReviewTue-Wed, Sep 16-17 PC Meeting: LTRA Report Highlights PresentedThu, Sep 25 PC Vote to AcceptTue, Sep 30 Report Sent to Board of Trustees for ReviewTue, Oct 14 BOT Teleconference & VoteTue, Oct 21 Target Release


Smart Grid Transmission System Devices & Applications• NERC, in collaboration with the EIA, is requesting data to identify ongoing

operational and planning impacts of these new technologies, which will be of paramount importance to the future reliability of the system. Data includes: Dynamic Capability Rating Systems (DCRSs) currently on the transmission system Total number of Phasor Measurement Units (PMUs) in each Assessment Area Application of PMUs for both planning and real-time operations

Gas-Electric Information• NERC is requesting qualitative information on the following topics: Current planning and operation coordination efforts between gas and electric

industries; particularly during extreme weather Fuel transportation risks and fuel switching capabilities Current and planned activities for pipeline expansion

2014 LTRASupplemental Data and Information Requests


Long-Term Reliability Challenges and Emerging Issues• Accommodating system needs and adapting to change Continued integration of variable generation Generation retirements and coordination of outages

• Increased dependence on natural gas • Increased use of demand-side management• Possible Nuclear generation retirements and/or long-term outages

MRC Input• Survey collected open-ended input and policy guidance from MRC• May 7 – May 30 (survey is now closed)• NERC staff is reviewing responses, which will be used as input for the front

section of the LTRA and will aid the strategic prioritization conducted by the Reliability Issues Steering Committee (RISC)

2014 LTRALong-Term Reliability Challenges and Emerging Issues

NERC 2014 Probabilistic Assessment

Noha Abdel-Karim, Senior Engineer of Reliability Assessment, NERCPlanning Committee Meeting June 10-11, 2014

2 RELIABILITY | ACCOUNTABILITY

Why Probabilistic Assessment

• An area of very active and vibrant research.• Many power system planning and operating problems are

implicitly probabilistic, and while deterministic assumptionsand approximations have served industry reasonably well inthe past, it is very likely that probabilistic methods will berequired to ensure more optimal and effective solutions in thefuture.

• More informative, giving estimates of how much, how long,and how often the expected consequences of investments(planning) or operator actions (expected cost of operation) willbe, as well as quantifying them.

• Requires significant amounts of data that may not exist or aredifficult and expensive to acquire.


Probabilistic Assessment History

• Sept. 2010 – PC approves GTRPMTF recommendation for NERC-wide probabilistic resource adequacy self assessments including transmission limits as to supplement LTRA

• 2011 Pilot Assessment on 2010 LTRA for 2011 & 2014• June 2012 – PC Approves biennial reporting• June 2013 – 1st NERC-Wide Probabilistic Assessment

on 2012 LTRA for 2014 & 2016• Now – 2nd Prob. Assessment to supplement 2014 LTRA

for years 2016 & 2018


Changes in 2014 ProbA

• Accelerated Schedule (PC approval in Mar. 2015)• ProbA Data Spreadsheet

• Better align with LTRA to facilitate comparison• Echo data from LTRA to participants

• Reporting Area reports – incremental changes• Methods & Assumptions Table – incremental

changes• Require One Scenario

• Calculate LOL without reducing operating reserve

• Study request issued May 12, 2014


2014 ProbA Scenario

No Emergency Operating Procedures ScenarioCalculate LOL while maintaining Operating ReservesPurpose Report inability to supply Firm Load + Spinning & Non-

Spinning (10 & 30 min.) Reserve Roughly equivalent to increasing load 3% to 5% Other Operating Procedures may still be used


2014 ProbA Schedule

Date ProbA 2014 DeliverablesMonday, March 3 Conference Call with RAS-ProbA May 12 Request sent to Regional ExecutivesMonday, July 21 ProbA Data Sheet with LTRA data preloaded sent to RegionsThursday, September 18, 2014 RAS-ProbA Team Conference Call: Pre-submission Inquiries Thursday, September 25 First Draft Due to NERC RAS - New York, NY, October 7-8 RAS-ProbA Team: Peer Review (Meeting around RAS)Monday, November 3, 2014 Final Assessment Area Reports Due to NERCPC Meeting, Dec 9-10 Update Presentation on the ProbA RAS to PCRAS - Atlanta, Dec 10-11 Presentation to RAS meetingTuesday, January 6, 2015 Draft Report Submitted to RAS-ProbA TeamTuesday, January 20, 2015 RAS-ProbA Team Comments DueFriday, January 23 , 2015 Draft Report Submitted to RASMonday, February 9, 2015 RAS Comments Due (Meeting)Friday, February 13, 2015 Final Draft Report to PCPC Meeting, March 2015 PC Approval of Final ReportMarch, 2015 Public Release


2014 Probabilistic Assessment

Questions?

NERC 2014 Probabilistic AssessmentPC Update – Background Information

June 2014


2012 ProbA Observations

• Report successful!• Want a study of ‘As Is’ system• Some areas need more practice/experience• Consistent results with LTRA• Wider area studies possible• Coordination between areas is possible• Some studies lacking any consideration of

transmission


2012 ProbA Recommendations

• Wide diversity in approaches may indicate room to improve especially for Load forecast uncertainty Intermittent resources Demand-side resources Emergency operating procedures (operating reserve)

• Detailed data sheet needs improvement. Needs to Show consistent data with LTRA Report specific data used in ProbA

• It is too early to comment on reliability trends• Desire to “leverage” analysis

Possibly study other scenarios


2014 Schedule – ProbA vs LTRALTRA 2014 Deliverables Date ProbA 2014 Deliverables

Data and Narrative Request to Regional Executives and RAS Monday, January 6 —Monthly Calls with Regions--Track Progress, Address Challenges January–May —

— Monday, March 3 Conference Call with RAS-ProbA Seek MRC Input for LTRA Risks Early May Request sent to Regional Executives and RAS and RAS-ProbAData and Narratives due to NERC Friday, May 23Narratives with Basic Data Posted by NERC to RAS Shared Drive Monday, June 2Peer Reviewer Comments Due to RAS Thursday, June 12RAS Meeting: Peer Review of Narratives RAS - Tampa,FL, June 17-18Final Narratives and Data Due to NERC Friday, June 27Complete Draft Posted by NERC to RAS Shared Drive Monday, July 21 ProbA Data Sheet with LTRA data preloaded sent to RegionsRAS Meeting:Final Review of Report RAS - Toronto,ON, August 12-13NERC Editor Review Begins Monday, August 25NERC Editor Review Completed Wednesday, September 3Report Sent to PC,OC, and MRC for Review Friday, September 5Senior Management Input for Key Findings and Recom. Early SeptemberReport Presented to the PC PC Meeting, September 16-17

— Thursday, September 18, 2014 RAS-ProbA Team Conference Call: Pre-submission Inquiries Planning Committee Vote to Approve Report Thursday, September 25 First Draft Due to NERC Report Sent to Board of Trustees for Review Tuesday, September 30 —

— RAS - New York,NY, October 7-8 RAS-ProbA Team: Peer Review (Meeting around RAS?)BOT Teleconference and Vote to Approve Report Tuesday, October 14 —Target Release Tuesday, October 21 —

— Monday, November 3, 2014 Final Assessment Area Reports Due to NERCPC Meeting, Dec 9-10 Update Presentation on the ProbA RAS to PC

RAS - Atlanta, Dec 10-11 Presentation to RAS meetingTuesday, January 6, 2015 Draft Report Submitted to RAS-ProbA Team

Tuesday, January 20, 2015 RAS-ProbA Team Comments DueFriday, January 23 , 2015 Draft Report Submitted to RAS

Monday, February 9, 2015 RAS Comments Due (Meeting?)Friday, February 13, 2015 Final Draft Report to PCPC Meeting, March 2015 PC Approval of Final Report

March, 2015 Public Release

LTRA 2015 Annual Process Start

ProbA model development; Awaiting LTRA data finalization

Conduct ProbA analysis


Short Listed Scenarios

1. No Emergency Operating Procedureso Addresses RAS & PC concern over forgoing Operating Reserveo Resulting LOL values will be higher facilitating trendingo Straight forward to implement

2. LOL without internal transmission limitationso Directly considers influence of transmission on resource adequacyo Difficult to interpret resultso Results in smaller LOL values so may have no observable impact

3. Restricted gas supplyo Significant issue in 2014o Not applicable in all areaso Difficult to achieve a consistent definitiono Does not require probabilistic evaluation


Data Spreadsheet

• Purpose Acquire additional information

o EFORo Operating Procedureso Operating Reserves

Reports data used in study to compare to data reported in LTRA

• Problems in 2012 Structural inconsistencies on data reporting Repetition of data entry

• Changes for 2014 Prefill sheet with LTRA data where possible More consistency with LTRA


Methods & Assumptions Matrix

• Adding more specific instructions• Adding ‘Response Suggestions’ Easier to complete Easier to read

• Allow additional answers if Assessment Areas within a regional study have differing treatments

• Discuss on next ProbA conference call


Main Report Structure

• Introduction (3p)• Probabilistic Assessment Methods

Modeling Requirements (1p) Overview of Methods used (1p)

• Summary Results Overview (context) (1p) By Assessment Area (1p each mostly – 17p)

• Observations & Recommendations (2p)• App. 1 – Methods & Assumptions Matrix (7p)• App. 2 – Assessment Area Reports

Separate Report (100p) 10 Areas or Region Reports


Assessment Area Section

• 1 Para. – Area description from LTRA• 1 Para. – Discussion of results• Graphic:

Report 2010 Report 2012 Report

2011 2014 2014 2016

LTRA Anticipated Reserve Margin 18.8% 21.6% 30.8% 21.2% Prospective Reserve Margin 20.0% 22.6% 30.8% 21.2%

ProbA

Forecast Planning Res. Margin 10.9% 12.2% 21.9% 13.1% Adjusted Planning Res. Margin 30.5% 21.0% EUE (MWh) 63.40 1.50 0.80 6.70 EUE (ppm) 0.45 0.01 0.01 0.04 LOLH (hours/year) 0.10 0.00 0.00 0.01

0%

10%

20%

30%

40%

2011 2014 2014 2016

2010 Report 2012 ReportLTRA Anticipated Reserve MarginLTRA Prospective Reserve MarginProbA Adjusted Planning Res. Margin

0.00

0.10

0.20

0.30

0.40

0.50

0.00

0.05

0.10

0.15

0.20

0.25

2011 2014 2014 2016

2010 Report 2012 Report

MW

h/TW

h

hour

s/ye

ar

LOLH (hours/year) EUE (ppm)


App2 - Regional Reports

• Based on outline from GTRPMTF Changes between the GTRMTF structure and the ProbA

structure.

• Consistency of report structure not required• Specific Questions on Transmission Modeling Indicate current and future transmission planning

development, if any, during the ProbA process. Discuss any impact (internal/external flows, LOL

indices)under the transmission line section

Geomagnetic DisturbancesUpdate on Project 2013-03

Frank Koza, PJM InterconnectionNERC Planning CommitteeJune 10, 2014


GICs can cause:Increased reactive power consumption, transformer heating, and P&C misoperation

GMD Concern for the Power System


TPL-007 Deliverables Summary

• Requires a GMD Vulnerability Assessment of the system for its ability to withstand a Benchmark GMD Event without causing a wide area blackout, voltage collapse, or damage to transformers, once every 5 years. Applicability: PCs,TPs

• Requires a Transformer thermal impact assessment to ensure that all high-side, wye grounded transformers connected at 200kV or higher will not overheat based on the Benchmark GMD Event Applicability: GOs, TOs


Changes Made to the Draft Standard

• Reordered the requirements Comments indicated some confusion as to the order in which the

requirements would be executed

• Established a floor of 15 Amperes for Transformer Thermal Assessment If calculated GIC is 15A or less, no further transformer thermal analysis

is required Technical justification: Continuous 15A exposure does not result in

temperatures of concern, based on transformer testing

• Tweaked Implementation Plan Moved earlier implementation steps (determine responsibilities, build

models) Maintained 4 years duration to develop Corrective Action Plan


Suggested Changes NOT Included

• Include RCs as an applicable entity But, RCs included as a recipient of the analyses for information and for

situational awareness

• Establish an exemption for lower latitude systems Benchmark definition includes adjustment factors for earth conductivity

and geomagnetic latitude, but assessment is required Technical justification not available at this point

• Change the Benchmark GMD Event geoelectric field magnitude


Comments on the GMD Benchmark

• Benchmark geoelectric field is too low Earlier work by GMD TF had peak fields of 20V/km or more “Spatial averaging” technique is not documented in peer-reviewed

technical papers

• Benchmark geoelectric field is too high Statistical analysis calculates out to a field of 5.8V/km Visual extrapolation implies a field of 3-8V/km (why not 3V/km or

5.8V/km?)


GMD Benchmark Geoelectric Field

Epeak = Ebenchmark x α x β (in V/km)

where,Epeak = Benchmark Geo-electric field magnitude at System

locationEbenchmark = Benchmark Geo-electric field magnitude at

reference location (60° N geomagnetic latitude, resistive ground model)

α = Factor adjustment for geo-magnetic latitudeβ = Factor adjustment for regional Earth conductivity

model


Reference Geoelectric Field Amplitude

Statistical occurrence of spatially averaged high-latitude geoelectric field amplitudes from IMAGE magnetometer data (1993 – 2013)

1-in-100 Year Occurrence3-8 V/km at 60⁰ N

geomagnetic latitude8 V/km to be conservative


Response to the Benchmark Comments

• Statistical analyses (GMD TF and Standard Work) are based on the same data

• Spatial averaging is a peer-reviewed technique (Authors are preparing a technical paper to address its use in this context)

• Calculated electric fields for the 1989 Quebec storm (~2V/km) are in line with the Benchmark

• Benchmark is conservatively “high” to provide for margin, given the uncertainties associated with these types of calculations


Integrated View of the GMD Assessment Process

Transformer Model

(Electrical)

dcSystemModel

GIC vars

Transformer Model

(Thermal)

Temp(t)

Power FlowAnalysis

E(t)Earth Conductivity

Model

Geomagnetic Field

B(t)

Hot Spot Temp.

PotentialMitigationMeasures

Bus Voltages Operating

Proceduresand

Mitigation Measures(if needed)

AssessmentCriteria

Pass

Fail

Line Loading &var Reserves

GIC(t)


• Review by the NERC Standards Committee and approval to post for initial ballot—this week

• Post for initial ballot--mid-June• SDT reviews ballot results and comments—August• Post for a second ballot—September• Seek NERC BOT approval at November meeting• Submit to FERC ahead of January 2015 deadline

Next Steps

Protection CoordinationRevisions to Power Plant and Transmission System Report

Phil Tatro, SPCS Coordinator, NERCNERC Planning Committee MeetingJune 10-11, 2014


• Power Plant and Transmission System Protection Coordinationreport approved by PC in December 2009 Revision approved in July 2010 Report addresses and expands upon protection system coordination

concerns from the August 14, 2003 blackout

• IEEE Power System Relaying Committee formed working group J3 to review the SPCS report J3 published its report in 2012 Provides recommendations for future revisions to IEEE guides Provides recommendations for revisions to the NERC report

• SPCS has reviewed the PSRC recommendations and other stakeholder comments and revised its report where deemed appropriate

Background


• Technical Expanded discussion of GSU transformer overcurrent protection Expanded discussion of voltage-controlled and voltage-restrained

overcurrent protection Expanded discussion of stator ground fault protection Expanded discussion of under/over-frequency protection Clarified that certain generator protections are set based on equipment

limitations and system protection/operation must be coordinated with the generator protection; e.g.,o Loss of fieldo Negative sequenceo Under/over frequency

Summary of Revisions


• Technical Clarified that coordination for fault detecting relays does not preclude use

of dedicated overload protection Clarified that out of step protection is generally necessary for larger

generators, and application is up the Generator Owner Noted limitations of generator protection for detecting transmission

system faults Relocated and revised breaker failure example

• Editorial Revised introduction to clarify basis for the report Corrected references to IEEE guides Corrected CT connections in several diagrams

Summary of Revisions


• Report approved previously as a technical reference• NERC standing committees subsequently established a

Report/Reliability Guideline Approval Process• The report appears to meet the Reliability Guideline definition Reliability guidelines are documents that suggest approaches or behavior

in a given technical area for the purpose of improving reliability. Reliability guidelines are not binding norms or mandatory requirements. Reliability guidelines may be adopted by a responsible entity in accordance with its own facts and circumstances.

• Publishing as a revision to the existing report may expedite the delivery to the industry

• Publishing as a Reliability Guideline may result in a higher level of industry awareness

Document Type


• SPCS requests the following: Assignment of PC members to review the report Confirmation whether the report should classified as a revision to the

existing report or as a new Reliability Guidelineo If as a Reliability Guideline,

– Approval to post for 45-day comment period, and– Consideration to limit comments to revisions to the document

• Next Steps Consider comments and revise report where appropriate Present the report for approval at the December or March PC meetingo Schedule dependent on document type and number of comments received

Requested Action and Next Steps

Order No. 754 Data RequestPreliminary Observations from Data 200 kV and Above



• This presentation contains PRELIMINARY conclusions based on review of a portion of the data (200 kV and above) obtained through the Order No. 754 data request

• This information is presented to facilitate discussion with the NERC Planning Committee and does not constitute a formal position regarding interpretation of the data or potential future actions

Disclaimer


• SPCS and SAMS members are supporting review of data Preliminary review complete for buses operated 200 kV and higher Data for buses operated 100 – 199 kV is due September 30, 2014

• A review of the data confirms: The data supports qualitative conclusions rather than quantitative

conclusionso A consequence of providing latitude to Transmission Planners and asset owners

to ease burden The data request assesses a representative sample of buses

Status Report


• Reliability risk warrants consideration of further action Risk is a function of the exposure to, and impact of, a single point of failure Exposure: the percentage of protection systems containing a single point

of failure Impact: the probability that a single point of failure will lead to instability,

uncontrolled separation, or cascading outages Exposure and impact vary as a function of system voltage level due to

differences in system characteristics (e.g., power transfer and impedance), and resulting protection system design practices

• The data supports the FERC Technical Conference conclusion that the concern is with the study of single points of failure The data does not indicate a need for redundant protection systems on all

BES Elements Planning assessments provide a means to make risk-based decisions

Conclusions and Consensus Points


• The exposure to single points of failure is broader than the specific list of devices in TPL-001-4 TPL-001-4 considers protective relays, lockout relays, and auxiliary tripping

relays Data indicates exposure for other protection system components,

especially below 400 kV

• Use available data (e.g., Misoperations and Event Analysis) to assess whether reliability risk is dependent on the type of protection system component that fails i.e., correlate component type (protective relay, ac inputs, communication

system, dc control circuitry, station dc supply) to misoperation category (failure to trip, slow trip, unnecessary trip)

Use data to determine which component types to consider when studying protection system failures in planning assessments

Conclusions and Consensus Points


• Reliability Standards – TPL-001 Expand study of relay failure to include protection system failure for a

broader range of components and revise footnote 13 Increase emphasis on study of three-phase faults accompanied by a

protection system failure – options include:o Elevate to a Planning Event with its own system performance criteriao Keep as an Extreme Event, but restructure so studies of single point of failure are

required – address system performance in the standard or a Reliability Guidelineo Keep as an Extreme Event with no change except the list of components to be

studied

• Reliability Guideline May include information from the 2008 SPCTF report, Protection System

Reliability: Redundancy of Protection System Elements

• Industry Alert

Potential Paths Forward


• Investigate availability of data to assess trends for single point of failure events

• Investigate data sources to assess the probability of: Three-phase faults compared to single-line-to-ground and multi-phase

faults Three-phase faults accompanied by a protection system failure compared

to other extreme events

• Develop alternatives for addressing the concern, which may include one or more of the following as deemed appropriate: Industry Alert Reliability Guideline Reliability Standard revisions

Next Steps


• Develop a draft report and recommendations for presentation at the September PC meeting Based on data for buses operated at 200 kV and higher

• Evaluate data for buses operated 100 – 199 kV during the 4th

quarter Confirm whether 100 – 199 kV data follows the trends observed at 200 kV

and above Update report based on PC input and evaluation of 100 – 199 kV data

• Present a final report and recommendations at the December PC meeting

Next Steps


• Planning Committee confirmation of: Proposed next steps and schedule Any interim steps needed prior to September meeting Discussion at the upcoming RISC meeting

Requested Action

Relay Loadability: GenerationUnit Auxiliary Transformer Load-Responsive Relays



• PRC-025-1 applicability includes load-responsive protective relays applied at high-side terminals of the unit auxiliary transformer (UAT)

• The NERC Board of Trustees has asked if a potential reliability gap exists because the standard does not apply to relays installed on the low-voltage side of the UAT

Background


• The drafting team performed a study, including: Computer simulations validated with recorded event data Analysis of Generator Availability Data System (GADS) data

• The study results were indicative that a reliability gap does not exist; however, were not conclusive due to: Variations in industry practice Potential inaccuracies and uncertainties in relay settings were not fully

offset by conservatism in the simulation model

Drafting Team Assessment


• The drafting team recommended a tiered approach with three options to further address this issue:1. Investigate use of GADS to track UAT outages caused by operation of

load-responsive relays2. Establish a guideline for setting load-responsive UAT low-side protective

relays to account for increased loading during depressed voltages3. Revise PRC-025-1 or create a new standard to address the loadability of

the load-responsive UAT high-side and low-side protective relays

• The approach is to begin with option 1• Subsequent options would be initiated only if a previous option

is infeasible or identifies a reliability gap

Drafting Team Recommendation


• NERC staff has investigated Option 1 Creating GADS cause codes to monitor operation of UAT load-responsive

protective relays is not practical GADS is designed to collect equipment availability, not equipment

operations GADS is not intended to record event data for analysis, and not to the

granularity needed to appropriately monitor such causes

• Pursuant to the report, NERC is proceeding with Option 2 since GADS monitoring is not feasible

• NERC requests the Planning Committee to solicit industry input through an appropriate technical subcommittee to establish guidelines for setting load-responsive UAT low-side protective relays to account for increased loading during depressed voltages

Status and Next Steps


• SPCS discussed this pending request at its May 6-8 meeting• SPCS could develop a report that addresses the following: Considerations for setting low-side UAT relays for dependable protection

of plant equipment Comparison of existing setting practices with increased load current during

depressed voltages Comparison of existing setting practices and reliability risk for UAT high-

side and low-side relays

SPCS Discussion

Seasonal Assessments and Modeling of Sub-100 kV ElementsSouthwest Outage Recommendations 5, 6, 7, & NERC2

John Simonelli, SAMS ChairPlanning CommitteeJune 10-11, 2014


Update:

• SW Outage Recommendations 5, 6, 7, & NERC2 on Seasonal Assessments and sub-100 kV Elements – covered in today's PC presentations

• SW Outage Recommendation 9: Procedures for near- and long-term planning studies Models – covered in today's PC presentations

SAMS/MWG PC Update


• Benefit Analysis for Node-Breaker Representations in Off-line and Real-time Study Models Traditional cost benefit analysis not available, entities making the

conversion not tracking dollars Initial drawbacks include manpower, lengthy timeline, centralized

coordination authority required, ancillary application changes, training, size constraints, etc.

Entities reporting reduced effort to maintain data, improved analysis due to common modeling between planning and operations, efficiency gains in model validation and event analysis, use of automated contingency tools, and facilitation of real-time case creation for conducting stability analysis using off-line analysis tools

SAMS/MWG PC Update


SAMS/MWG PC Update

• Model Validation Field Trial SAMS reached out to NATF core Modeling Group Additional nine entities now interested in participating

• SW Outage Recommendation 16: Consistency in model parameters MWG continuing to review change management practices MWG to reach out to NATF which has a group looking at the same issues

• FIDVR & Composite Load Model Workshop Looking at Q2 2015 workshop Expecting an industry update on FIDVR including DOE progress on

developing improved manufacturing standards for AC Various SME’s to discuss efforts to develop composite load models to more

accurately capture voltage and dynamic response of load


• Standardized Component Models MWG effort beginning in earnest MWG doing outreach to various NATF groups working on similar effort to

leverage work and personnel

• Annual review of Interconnection Frequency Response Obligation (IFRO) NERC staff beginning annual review of IFRO Expect to present results to SAMS in Q3 2014 for review

• Distributed Resources (IEEE 1547) Revisions SAMS to serve as monitoring and commenting group for IEEE This is expected to be a lengthy effort

SAMS/MWG PC Update


• Order No. 754 SAMS reviewing (provided four SMEs) survey results as they become

available from SPCS Evaluation moving down into sub 200 kV systems now

• Southwest Outage Recommendation 27 SAMS finished reviewing the recommendation

“TOPs should have: (1) the tools necessary to determine phase angle differences following the loss of lines; and (2) mitigation and operating plans for reclosing lines with large phase angle differences. TOPs should also train operators to effectively respond to phase angle differences. These plans should be developed based on the seasonal and next-day contingency analyses that address the angular differences across opened system elements.”

Recommendation is geared towards Operations, both real-time and seasonal studies. SAMS recommends task be remanded to the Operating Committee, Operating Reliability Subcommittee, and Real-time Application of PMUs to Improve Reliability Task Force

SAMS/MWG PC Update


Seasonal Assessments & Sub-100 kV

• September 8, 2011 – AZ-Southern CA Outages• April 2012, FERC & NERC issued joint report, Arizona-Southern

California Outages on September 8, 2011 (Southwest Blackout Report)

• 27 key recommendations presented in report• WECC responded with NERC activities in September 28, 2012

report, Response to the “Arizona-Southern California Outages on September 8, 2011”

• Proposal addresses recommendations 5, 6, & 7 and WECC Activity NERC2

http://www.nerc.com/pa/rrm/ea/September%202011%20Southwest%20Blackout%20Event%20Document%20L/AZOutage_Report_01MAY12.pdf

http://www.nerc.com/pa/rrm/ea/September%202011%20Southwest%20Blackout%20Event%20Document%20L/WECC_Response_to_the_Arizona-Southern_California_Outages_on_September_8_2011_Repor.pdf


• Recommendation 5:“WECC RE should ensure better integration and coordination of the various subregions’ seasonal studies for the entire WECC system. To ensure a thorough seasonal planning process, at a minimum, WECC RE should require a full contingency analysis of the entire WECC system, using one integrated seasonal study, and should identify and eliminate gaps between subregional studies. Individual [Transmission Operators] TOPs should also conduct a full contingency analysis to identify contingencies outside their own systems that can impact the reliability of the [Bulk Power System] BPS within their system and should share their seasonal studies with TOPs shown to affect or be affected by their contingencies.”

The following key concepts were extracted from this recommendation:

1. TOPs should utilize an integrated and coordinated study model2. TOPs should collaborate to identify internal reliability impacts due to

contingencies outside of their systems

Recommendation 5


Recommendation 5

SAMS & MWG findings that address key concept 1:• Integrated study model addressed in FAC-011-2, R3/R3.1 • Integrated study model is coordinated between affected TOPs

and RCs pursuant to FAC-014-2, R2 & proposed TOP-002-3 and TOP-003-2


Recommendation 5

SAMS & MWG findings that address key concept 2:• Collaboratively identify contingencies outside TOP system that

impact internal reliability: FAC-011-2, R2 - contingencies to assess (internal & external) TOP-002-2.1b, R6 & proposed TOP-002-3, R1 - evaluation

• FAC-014-2, R5, TOP-002-2.1b, R4, & proposed TOP-003-2, R1, R3, & R5 facilitate sharing of seasonal studies, data, SOLs, & IROLs

• TOPs should share the results of their seasonal studies with all affected TOPs and RCs, pursuant to standard TOP-003-2 and Project 2007-03 Mapping Document


Recommendation 6 & NERC2

• Recommendation 6:“TOPs should expand the focus of their seasonal planning to include external facilities and internal and external sub-100 kV facilities that impact BPS reliability.”

• NERC2:“To maintain consistency continent-wide, WECC recommends that NERC identify technically-based criteria for identifying which sub-100-kV elements must be modeled in the real-time, next day, seasonal, and near-and long-term horizons. NERC should also identify technically-based criteria for which sub-100-kV elements should be included in the Bulk Electric System. Such criteria must be consistent with any FERC-approved definition of the Bulk Electric System, and should clarify which facilities may be included through any FERC-approved exception process.”


The following key concepts were extracted from recommendation 6 and NERC2:1. TOPs need to include in their studies the following to accurately ascertain

the impact on BES reliability: External facilities Internal and external sub-100 kV facilities

2. NERC should identify consistent criteria for which sub-100-kV elements must be modeled in the real-time, next day, seasonal, and near- and long-term horizons




SAMS & MWG Findings that address the key concepts:• External facilities rated above 100 kV should already be in study

models (Recommendation 5)• NERC-wide criteria for modeling & assessment of sub-100-kV

elements not appropriate due to regional differences

SAMS & MWG Gap Recommendations to address key concepts:• Each TP/PC should conduct periodic assessments to identify

internal/external sub-100 kV facilities impacting their BES reliability• TPs/PCs should then model these facilities and submit them to

applicable TOPs and RCs for their consideration• Suggest that OC review recommendation for operational time

horizons


Recommendation 7

• Recommendation 7:“TOPs should expand the cases on which they run their individual planning studies to include multiple base cases, as well as generation maintenance outages and dispatch scenarios during high load shoulder periods.”

The following key concepts were extracted from recommendation 7:1. TOPs should utilize representative base cases2. TOPs should model generation maintenance outages3. TOPs should model dispatch scenarios during high load shoulder periods


SAMS & MWG Findings (base cases/parameters):• TOP-002-2.1b, R5 covers modeling system configurations,

generation dispatch, and load scenarios• TOP-002-3, R1 addresses transmission and generation

outages, load forecasts(s), and planned dispatch scenarios (i.e., generation output levels)

SAMS & MWG Gap Recommendations• Regions & TOPS should: Model shoulder periods capturing appropriate load sensitivities relevant to their area Model projected power transfers (interchange scheduling) and clarify study procedures (for

TOP-002-3) Load forecasts should incorporate Reactive Load as well as Real Power Load (Mvar load or

Load Power Factor data) Reactive resources should be modeled with reactive/voltage schedules consistent with

VAR-001-2/proposed VAR-001-4

Recommendation 7


• NERC Standards references in the SAMS/MWG findings and recommendations: Many current and proposed NERC Standards already address issues

raised in the Southwest Outage Report recommendations 5, 6, 7, and NERC2

Can be further enhanced by following SAMS’ and MWG’s gap recommendations

• In some areas findings and recommendations cover operational time frame; SAMS suggests that the OC review these areas

Conclusions

Near- and Long-Term Planning StudiesSouthwest Outage Recommendation 9

Chuck Chakravarthi, SAMS Vice-ChairPlanning CommitteeJune 10-11, 2014


• September 8, 2011 – AZ-Southern CA Outages• April 2012, FERC & NERC issued joint report, Arizona-Southern

California Outages on September 8, 2011 (Southwest Blackout Report).

• 27 key recommendations presented in report• SAMS was assigned Recommendation 9 to provide further

guidance

Background

http://www.nerc.com/pa/rrm/ea/September%202011%20Southwest%20Blackout%20Event%20Document%20L/AZOutage_Report_01MAY12.pdf


• “WECC RE should take actions to mitigate these and any other identified gaps in the procedures for conducting near- and long-term planning studies. The September 8th event and other major events should be used to identify shortcomings when developing valid cases over the planning horizon and to identify flaws in the existing planning structure. WECC RE should then propose changes to improve the performance of planning studies on a subregional- and Interconnection-wide basis and ensure a coordinated review of TPs’ and PCs’ studies. TOPs, TPs and PCs should develop study cases that cover critical system conditions over the planning horizon; consider the benefits and potential adverse effects of all protection systems, including RASs, Safety Nets (such as the SONGS separation scheme), and overload protection schemes; study the interaction of RASs and Safety Nets; and consider the impact of elements operated at less than 100 kV on BPS reliability.”

Recommendation 9


• The recommendation covered four key areas: Improved study process and coordinated review of studies Development of valid cases Consideration of all protection systems Impact of sub-100 kV elements

• New TPL-001-4 addresses first three areas• Current PRC-001-1.1 and pending PRC-001-2 address the

consideration of protection systems SDT on SPS will cover the consideration of SPS

• New BES standard allows for the inclusion of sub-100 kV elements

Recommendation 9


• SAMS Conclusions All the key items in the Recommendation 9 are addressed by the

standards

• SAMS Recommendations Transmission Planners and Planning Coordinators (Planning Authorities)

conduct periodic assessments to identify sub-100 kV facilities either internal or external to their area that impact BES reliability of their system.

Any sub-100 kV facilities so identified should be modeled in the long-term planning models.

Recommendation 9

Energy Ventures Analysis1901 N. Moore St. Arlington, VA 22209(703) 276 8900

I D E N T I F Y I N G E N V I R O N M E N T A L P L A N N I N G R I S K S F O R F U T U R E P O W E R S Y S T E M R E L I A B I L I T Y

NERC Planning Committee Meeting Orlando, Florida

Presented By: Thomas Hewson, PrincipalPhillip Graeter, Analyst

June 11, 2014

1

ABOUT ENERGY VENTURES ANALYSIS

EVA, Inc. is an energy consulting firm located in Arlington, VA. EVA is focused on economic, financial andrisk analysis for the electric power, coal, natural gas, petroleum, and renewable, and emissions sectors.

Since 1981, EVA has been publishing supply, demandand price forecasts as part of its FUELCASTsubscription service for these energy sectors.

EVA performs various analyses for an array of clientsthat include:• power utilities,• fuel producers,• fuel transporters,• commodity traders,• regulators, and• financial institutions.

2

OUTLINE

EPA GREENHOUSE GAS REGULATIONS FOR POWER INDUSTRY

MERCURY AND AIR TOXICS STANDARD (MATS)

UTILITY PLANNING ENVIORNMENTAL RISKS

316 B – COOLING WATER INTAKE STRUCTURES RULE

RECOMMENDATION

OTHER POTENTIAL EPA REGULATIONS

3

IDENTIFYING ENVIRONMENTAL PLANNING RISKS FOR FUTURE POWER SYSTEM RELIABILITY


4


• Several pending environmental regulations will require additional environmental control investmentsfor continued operation

• Potentially forces power suppliers to retire large amounts of existing generating capacity to avoidcapital investments

• System reliability issue when reserve margins drop below required levels

• 2 NERC Special Reliability Assessments released:• Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential US

Environmental Regulations – October 2010• 2011 Long Term Reliability Assessment- Potential Impacts of Environmental Regulations –

November 2011

• NERC Studies examined 4 EPA draft proposals:• Mercury and Air Toxics Standard (MATS) – Finalized Dec. 2011, Apr. 2013 (new plant)• 316 B Cooling Water Intake Structures – Finalized May 2014• Clean Air Transport (CATR) final rule – Stranded in Court of Appeals as of Apr. 2014• Coal Combustion Residuals (CCR) rule – To be finalized by Dec. 19, 2014

EPA continues to underestimate retirement risks by examining each regulation individuallyand not their cumulative impact!

5



6


• Sets emission limits for mercury, particulate matter, hydrogen chloride and other air toxics on allexisting and new coal and oil-fired electric generating units >25 MW

• Finalized in December 2011, April 2013 for new plants

• Final rule improvement upon draft rule analyzed in NERC study• Allows sources to apply for 1 year extension from Apr. 2015 deadline for electric reliability

and/or construction delays• 107 applications submitted – 98 extensions granted

• Allows some plants to comply through upgrading ESPs and avoid costly bag-houseparticulate controls retrofits

• Most compliance strategies are now known

• Power suppliers announced to retire 36.9GW of coal capacity in the next 2.5 yearslargely due to MATS rule

• EVA expects an additional 20 GW to retirebefore 2017

7



8


• Requires 544 electric power plants with once-through cooling water systems and use more than 2million gallons per day (MGD) of which more than 25% is used for cooling purposes to operate besttechnology available (BTA) options to reduce fish impingement

• Requires plants with >125 MGD actual intake flow (≈305 plants) to operate BTA options to reduceentrainment

• Fish Impingement Rule allows 7 compliance options:• Only 2 options are preapproved (closed loop systems, <5 feet/sec design intake velocity)• Remaining options require applicant to submit detailed information for state permit decision• Allows state flexibility and consider less strict BTA for units with CF<8%

• Entrainment greatest potential impact and will be decided on a site specific basis based uponapplicant detailed information

• Permit director must at minimum examine closed cycle cooling, fine mesh screens (<2mm),water reuse or alternate source options (§122.21(r)(10))

• Final rule provides states much greater flexibility insetting BTA standards

• This discretion makes it difficult to model• Permit writer can force closed loop cooling

systems

• Some current industrial power load could potentiallybe switched from onsite to purchased power Example of a closed loop cooling system

9


EPA GREENHOUSE GAS REGULATIONS FOR POWER INDUSTRY

1 0

EPA JUNE 2 DRAFT PROPOSAL FOR GREENHOUSE GAS EMISSION RATES FOR EXISTING POWER PLANTS

3,104 Existing (started construction prior to 1/8/2014) fossil fired power units (702,381 MW) will be subject to CO2 emission rates beginning in 2020 . A total of 17,472 Existing generating units are exempted. – Fuel Input > 250 MMBtu/hour– >1/3rd of potential output on grid– ->219,000 MWh/year – EVA Initial estimate is draft program would reduce incremental annual affected unit CO2 emissions by 510 million

tons/year (2020) to 600 Million tons/year (2030)

Proposal provides CO2 credit for – State Renewable Energy Generation – State Energy Efficiency Programs.– 5 Nuclear Plants Under Construction – Watts Bar, Vogle (2 units), Summer (2 units)– “Preserved” Nuclear Units – 5.8% of state nuclear capacity – Switching from existing coal to lower carbon alternatives

Implications on grid system operations– Forced environmental dispatch of system units– Additional steam unit retirements likely– Higher natural gas prices from greater natural gas demand – Higher proportion of power supply from variable resources (wind, solar) – Greater energy efficiency program incentives

E N E R G Y V E N T U R E S A N A L Y S I S , I N C .

1 1



1 2


• Regional Haze ruling• EPA required additional post combustion controls on western coal units• Most focus on retrofitting additional NOx controls as part of state regional haze plans

• Ozone NAAQS• State SIP plans may require additional NOx controls on power industry to comply• E.g. Dickerson/Chalk Point

• Power Industry Effluent Guidelines• Draft published in April 2013

Regional haze in West Virginia Ozone pollution in Salt Lake City

1 3


RECOMMENDATION

1 4

RECOMMENDATION

• Updated NERC reliability assessment examining the cumulative impacts of multiple new EPAregulations on power industry resource decisions and mix

• EPA new GHG regulations may have greatest new reliability risk from combination of triggeringmore early plant retirements and promoting more variable resource renewable generationcapacity

Energy Ventures Analysis1901 N. Moore St. Arlington, VA 22209(703) 276 8900

A N A L Y S I S A N D P R E S E N T A T I O N B Y

Thomas Hewson, Principal

Phillip Graeter, Analyst

1901 N. Moore StreetSuite 1200Arlington, VA 22209(703) 276 8900 - Main(703) 276 9541 - Fax

PAS 2014 Work Plan

Howard Gugel, Director of Performance Analysis, NERCPlanning Committee Meeting June 10-11, 2014


• Assignments of SOR Recommendations • TADS work plan• GADS work plan• DADS work plan• ACSETF work plan• PAS work plan

Overview


• Frequency Response NERC will examine and develop root causes for incidents in 2013 where

frequency response was less than the IFRO – FRI report Additional actions to maintain and improve FR – PAS after FRI analysis

• Misoperations Complete PRC-004-3 – Standards Develop plan to address three most common causes of misoperations –

NERC staff, TADS, NATF, ERO-RAPA

• AC Substation Equipment Failures Assess effectiveness of 345kV Breaker Alert – NERC EA Plan to address findings of ACSETF – PAS after ACSETF report Facilitate data collection – TADS after ACSETF report

SOR Recommendations


• BES Implementation 2015 Data Reporting Instruction (DRI) changes 2015 Inventory Worksheet Finalize webTADS changes

• Misoperations Develop plan to address three most common causes of misoperations –

NERC staff, TADS, NATF, ERO-RAPA (Due Dec 2014)

• “Unknown” outage cause code Work with regions to understand use of cause code for sustained outages

TADS Work Plan


• Finalize Wind GADS Reporting Whitepaper• Update DRI• Update NERC FAQ page• Develop error checking process• Develop metrics for 2015 SOR report – September 2014• Develop GADS dashboard• Develop Solar GADS collection process

GADS Work Plan


• Update DADS glossary• Validate data for reliability analysis• Obtain consensus on iDashboard screens

DADS Work Plan


• Complete analysis of equipment outages• Prepare draft report – August 2014• Reconcile comments and present results at September PC mtg• Submit final report to OC/PC for approval – December 2014

ACSETF Work Plan


• Track SOR recommendations• Develop lessons learned for 2014 SOR• Integrate GADS, DADS, and ACSETF into 2015 SOR• Annual Review of Metrics • Work with CCC on replacement of KCMI metric

PAS Work Plan

Project 2014-03 UpdateTOP/IRO Reliability Standards

David Souder, PJMPlanning Committee MeetingJune 10-11, 2014


Agenda

• Background• SDT Roster• SDT Inputs• Issue Summary• Impacted Standards• Industry Role• Project Schedule• Questions


Background

• April 16, 2013 – NERC petition for approval of three revised TOP, four revised IRO standards

• November 21, 2013 - FERC Notice of Proposed Rulemaking (NOPR) proposes to remand revised TOP and IRO standards

• December 20, 2013 – NERC motion to defer action on NOPR until January 31, 2015

• January 14, 2014 – FERC grants motion to defer action until January 15, 2015

• February 12, 2014 – Standards Committee appoints SDT for Project 2014-03 Revisions to TOP/IRO Reliability Standards


SDT Roster

• Chair – Dave Souder, PJM• Vice Chair – Andrew Pankratz, FP&L• David Bueche, CenterPoint Energy • Jim Case, Entergy • Allen Klassen, Westar Energy • Bruce Larsen, WE Energies • Jason Marshall, ACES Power Marketing • Bert Peters, Arizona Public Service Co.• Robert Rhodes, SPP • Kyle Russell, IESO• Eric Senkowicz, FRCC • Kevin Sherd, MISO


SDT Inputs

• Previous work by Projects 2006-06 and 2007-03• FERC NOPR (November 21, 2013)• Independent Experts Review Project• Southwest Outage Recommendations• Order 693 directives• IRO Five-Year Review Team• SAR Comments• Technical Conferences• NERC OC IERP Gap analysis


Issue Summary

• Clarification of SOL exceedance (white paper)• Clarified and strengthened definitions of Operational Planning Analysis and

Real-time Assessment • Real-time Assessment every 30 minutes• Incorporated “Operating Instruction” consistent with proposed COM-002-4• Consolidation of standards: 5 existing TOP, 5 existing IRO, and 1 existing PER

standard proposed for retirement• Clean-up of applicability: Transmission Operator/Balancing Authority

responsibilities in TOP standards, Reliability Coordinator responsibilities in IRO standards

• Elimination of redundancy • New Outage Coordination Standard


Impacted Standards

• Revised Standards: TOP-001-3, TOP-002-4, TOP-003-3 IRO-001-4, IRO-002-4, IRO-008-2, IRO-010-2, IRO-014-3

• Retired Standards: TOP-004-2, TOP-005-2a, TOP-006-3, TOP-007-0, TOP-008-1 IRO-002-4, IRO-003-2, IRO-004-2, IRO-005-3.1a, IRO-015-1, IRO-016-1 PER-001-1

• New Standard: IRO-017


Industry Role

• Thorough review of the many standards involved There are many inter-relationships here

• Specific comments Suggested language changes Provide technical rationale Don’t duplicate comments and increase work for the SDT Stay on scope

• Participate in mid-posting webinar to hear SDT intent and responses to questions


Project Schedule

• 5/19 – 1st 45 day posting – combined comment and ballot • 7/1 - Comment period ends• 8/6 - 2nd 45 day posting – combined comment and ballot• 9/19 - Comment period ends• 10/13 – Final 10 day ballot• 11/12 - Board approval• 12/1 - FERC filing


Website http://www.nerc.com/pa/Stand/Pages/Project-2014-03-Revisions-to-TOP-and-IRO-Standards.aspx

http://www.nerc.com/pa/Stand/Pages/Project-2014-03-Revisions-to-TOP-and-IRO-Standards.aspx

Project 2014-01Dispersed Generation Resources Standard Drafting Team (DGR SDT)

Brian Evans-Mongeon, Utility Services Inc.NERC PC Meeting - OrlandoJanuary 10-11, 2014


• Standard Authorization Request (SAR) posted for formal comment on November 20, 2013

• FERC approved the BES Phase 2 Definition on March 20, 2014 The order recognizes this project

• Address all Generation Owner (GO)/Generator Operator (GOP) standards and some other functions that rely on GO/GOP data Currently enforceable and pending regulatory approval Coordinate activity among active SDTs and committees White paper posted on April 2014 Comments received on May 5, 2014 High-priority standards planned posting in mid June 2014o PRC-004, PRC-005, and VAR-002 (relevant versions)

Project Overview


• April 28, 2014: Industry Webinar• May 5, 2014: White paper comments received Industry generally approves of direction of DGR SDT

• June 2014: Initial “high-priority” standards posted for comment and ballot June 10, 2014: Standards Committee meeting

• February 2015: Anticipated project completion dates• November 2014 and February 2015 targeted for NERC Board of

Trustees (Board) approval High-priority standards approved in November 2014 Medium- and low-priority standards approved in February 2014

Project Timeline


• BES Definition Phase 2 The BES definition includes the following inclusion criterion addressing

dispersed generation resources:o I4. 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.

Concepts Applied to the Standards


• Intent is to not modify content of requirements Focus on applicability to dispersed generation resources

• Applicability Options As stated in BES Definition At point of aggregation >=75MVA At connection to “Grid” net at the point of interconnection

• Necessary for Reliability• Technical Justification for departure from “Status Quo”• Standards grouping/buckets by timeframe or functionality and

priority

Concepts Applied to the Standards


• Appendix A overview: Approval status of the standards which include: Subject to Enforcement Subject to Future Enforcement Filed and Pending Regulatory Approval Pending Regulatory Filing Designated for Retirement (Two standards—MOD-024-1 and MOD-025-1

—officially listed as Filed and Pending Regulatory Approval but will be superseded by MOD-025-2)

Proposed for Remand (Four standards—IRO-001-3, IRO-005-4, TOP-002-3, and TOP-003-2—officially listed as Filed and Pending Regulatory Approval but, as of April 10, 2014, proposed to be remanded)

Standards Reviewed and Priority Groupings


• Three Categories for Dispersed Generation Resources:



• Three Categories for Dispersed Generation Resources: The existing standard language is appropriate when applied to dispersed

generating resources and does not need to be addressed;




generating resources and does not need to be addressed; The existing standard language is appropriate when applied to dispersed

generating resources but additional NERC guidance documentation is needed to clarify either how to implement the requirements for dispersed generating resources or how to demonstrate compliance for such resources; and




generating resources and does not need to be addressed; The existing standard language is appropriate when applied to dispersed

generating resources but additional NERC guidance documentation is needed to clarify either how to implement the requirements for dispersed generating resources or how to demonstrate compliance for such resources; and

The existing standard language needs to be modified in order to account for the unique characteristics of dispersed generation resources. This could be accomplished through the applicability section of the standard in most cases or, if required, through changes to the individual requirements. However, please note that any recommended changes to requirements are limited to changes in the applicability of the subject requirement and will not include technical changes to any requirement.



• White paper posted on April 4, 2014 Living evolving document Direction of the SDT Technical consideration of the unique characteristics of dispersed

generation Prioritization of standards to addresso High, Medium, and Low

Present options for potential modifications to the standardso Focus on applicabilityo Develop technical analyses related to possible recommendations

Elicit feedback from industry

White Paper


• The DGR SDT has identified three high-priority standards: PRC-004-2.1a* PRC-005* VAR-002*

*Relevant versions

White Paper


• Coordination with other SDTs• Risk-Based Registration• Regional BES definition compliance guidance• July 1, 2014 effective date with compliance by July 1, 2016

Concurrent Activities and Milestones

Risk-Based Registration

Terry Brinker, NERC Manager, Registration ServicesPlanning Committee MeetingJune 10, 2014


• Some Functions may have minimal impact on reliability• Must follow all standard requirements according to Function,

regardless of reliability impacts• Conservative criteria and thresholds used to register entities• Flexibility to use entity risk, but limited application to date• Entities registered in multiple regions are subject to inconsistent

criteria

Current Registration Challenges


• Understand and manage risk by ensuring entities registered based on risk to reliability

• 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

Risk-based Registration Vision


• Eliminate functional categories not contributing to reliability (PSE, IA and LSE)

• Reliability Standard requirements tailored to risk• Two options to use consistent risk-based methods: Modify thresholds (DP) Tiers within existing criteria (TOP)

• Systematic, repeatable and comprehensive process

RBR Approach


• The functional category of PSE has been identified for potential elimination The PSE function is a market/commercial function The BAL standards already require the BA to manage total interchange NERC standards applicable to the PSE can be transferred to NAESB

• The functional category of IA has been identified for potential elimination Changes to the INT standards remove the requirements applicable to the IA P81 efforts identified the INT standards as commercial in nature

• The functional category of LSE has been identified for potential elimination LSE serves mainly commercial purposes Many standards are applicable to both the DP and LSE Activities of an LSE can be better handled by other registered entities

Proposed Elimination


Distribution Provider• Increase the threshold to 75 MW for Distribution Providers pending studies of the aggregate impact of such change

• UFLS-Only Distribution Provider Entities 75 MW or below that have UFLS Protection Systems Only be responsible for complying with PRC-006-1 as Distribution Providers

Proposed Revisions


• Generation Owner and Operators Incorporation of the BES Definition, through the addition of the term

“Facility(ies)” units Project 2014-01 Standard Drafting Team

• Transmission Owner and Operators No change to the Registry Criteria Potential for tiering of Standard requirements based on risk to reliability

Proposed Revisions Continued


• Comprised of a NERC-led with Regional Entity participants• To provide a basis for NERC and regional consistency• To vet threshold applications, materiality, or Reliability Standard

requirement applicability issues• Decisions will be shared throughout the ERO Enterprise and

publicly posted on the NERC web site

Centralized Review Process


• Is the entity identified in the emergency operation plans and/or restoration plans of a Reliability Coordinator (RC), Balancing Authority (BA), GOP or TOP?

• Will intentional or inadvertent removal of a resource or Element owned or operated by the entity lead to loss of a BES resource or transmission Element of a GOP or TOP?

• Will intentional or inadvertent removal of a resource or Element owned or operated by the entity lead to a material loss of BES connected load of a BA or TOP?

• Can the normal operation, Misoperation or malicious use of the entity’s cyber assets cause a detrimental impact on the operational reliability of a BA, GOP or TOP?

• Can the normal operation, Misoperation or malicious use of the entity’s Protective Systems cause a detrimental adverse impact on the operational reliability of any BA, GOP or TOP, or the automatic load shedding programs of a PC or TP (UFLS, UVLS)?

Factors for Materiality


RBR Overview Flowchart


RBR Timeline

agenda item 4.a: update on regional challenges highlights and...• planning tasks task 1.1 –...

Documents