DRAFT Agenda Planning Committee Meeting September 16, 2014 | 1:00-5:00 p.m. (PDT) September 17, 2014 | 8:00 a.m. to 12:00 p.m. (PDT) Hyatt Regency Vancouver Conference Room - Regency E-F 655 Burrard Street Vancouver, B.C. V6C 2R7 888-421-1442 Introductions and Chair’s Opening Remarks Trustee Chair Frederick Gorbet Opening Remarks NERC Antitrust Compliance Guidelines and Public Announcement Agenda Items

1. Administrative ― Secretary

a. Arrangements

b. Safety Briefing

c. Announcement of Quorum

d. Planning Committee (PC) Membership

i. Chair Appointment

ii. Vice Chair Nomination and Election

iii. Secretary Introductions

iv. Planning Committee Executive Committee Nominations and Election • Stacia Harper • Brian Evans-Mongeon • Phil Fedora • Ed Scott • Noman Williams • Mark Westendorf • Russ Schussler

v. Election Results

vi. New Member Welcome • Gary T. Brownfield • Arthur Iler • Andrew Wade Tudor • Russ Schussler • Carl Turner • Michael Goggin • Herb Schrayshuen • Mark Sims • David Mercado • Doug McLauhglin

e. Future Meetings

2. Consent Agenda ― Interim Chair, David Weaver

a. June 10-11, 2014 Draft PC Meeting Minutes**

b. September 16-17, 2014 Meeting Agenda

3. Update on the August 14, 2014 Board of Trustees (Board) Meeting – John Moura, NERC Staff

4. Regional Reports

a. Regional Challenges and Updates

5. Committee Business

a. Reliability Issues Steering Committee Update – John Moura, NERC Staff Objective: Provide an update on the 2014 Reliability Leadership Summit and solicit volunteers to review the draft ERO Risk Profiles. Presentation: Yes Duration: 15 minutes Background Item: A presentation on the Reliability Leadership

Summit will be provided. The Reliability Issues Steering Committee (RISC) is preparing a document on ERO Risk Profiles that will be presented to the Board. Volunteers are needed to review the document on behalf of the PC to determine if risks to the Bulk Power System are adequately captured.

Personal Notes:

b. Department of Energy Research and Development Program Status Report – Dr. Emmanuel Taylor, U.S. Department of Energy

Objective: Review and discuss the DOE’s goals and objectives of its Research and Development program regarding operating reliability. Presentation: Yes Duration: 20 minutes Background Item: None Personal Notes:

c. IVGTF Final Summary Report – John Moura, NERC Staff Objective:

• The objective of this report is to summarize the findings from the IVGTF multi-task effort. Findings and recommendations provide a reference of best practices for planners, operators, regulators, and developers dealing with the challenges and opportunities offered by variable generation.

• PC Endorsement and Approval Next Steps:

• The IVGTF recommendations should be considered in light of the dynamic changes facing the bulk power system (BPS). Therefore, NERC staff will continue monitor the progress of the IVGTF recommendations.

• Request PC guidance: NERC staff is seeking PC guidance in acknowledging the completion of the IVGTF work plan and activities. Therefore, the task force requests disbanding the IVGTF and delegating this effort to the NERC LTRA, special assessments, and to the Essential Reliability Services Task Force (ERSTF) that carries out work plan and activities on actions for enhancing system reliability due to changes facing the BPS.

Presentation: Yes Duration: 20 minutes Background Item: IVGTF Summary and Recommendations of 12 Tasks Report

Personal Notes:

d. Essential Reliability Services Task Force (ERSTF) – Brian Evans-Mongeon, Co-Chair of ERSTF Objective:

• Seeking members endorsement of the concept paper for the ERSTF which is posted online on NERC website.

Draft Agenda – Planning Committee Meeting September 16-17, 2014 2

• Update on Task Force Status: The ERSTF kicked off the official task force business in June following the OC/PC meetings. The task force work has been divided into four subgroups based on the areas of study as decided by the task force. These subgroups could include various characteristics and services that could fall under the umbrella of ERS.

o Load and Resource Balance o Voltage Support o Frequency Support o Policy and Advisory Group

• This presentation will provide a brief update on each subgroup and their status thus far. • Next deliverable will include as a whole, a framework for assessment and detailed technical analysis and

technical reference papers for each subgroup area. • Next meeting – Following the OC/PC meetings, September 17-18, 2014 in Vancouver, BC.

Presentation: Yes Duration: 15 Minutes Background Item: ERSTF Concept Paper Personal Notes:

e. Long-Term Reliability Assessment – Elliott Nethercutt, NERC Staff Objective: i. Overview of Report Conclusions and Key Findings ii. Review Remaining Milestones and Target Release Date iii. Report Development Improvements/Remaining Issues Presentation: Yes Duration: 20 minutes Background Item: 2014 Long Term Relialbility Report (will be

sent to committee members on September 10, 2014)** Personal Notes:

f. Winter Reliability Assessment – Elliott Nethercutt, NERC Staff Objective: i. High Level Overview with Preliminary Data Findings ii. Review Remaining Milestones and Target Release Date Presentation: Yes Duration: 10 minutes Background Item: None Personal Notes:

g. Reliability Assessment Subcommittee (RAS) Update – Layne Brown, Chair of RAS

Objective: i. Recent developments (Reliability Assessment process, glossary, and guidebook) ii. 2015 RAS Work Plan

Presentation: Yes Duration: 10 minutes Background Item: No Personal Notes:

h. Geomagnetic Task Force Update - Ken Donohoo, Chair of GMDTF Objective: Periodic update on the development of the GMD planning standard, TPL-007, and GMD Task Force supporting work. Presentation: Yes Duration: 5 minutes Background Item: No Personal Notes:

i. GHG – EPA Section 111(d) Regulations – John Moura, NERC Staff Objective: i. Inform the Planning Committee of NERC’s perspective and approach for assessing proposed EPA regulations. ii. Solicit industry input on the reliability challenges, EPA assumptions used for its reliability analysis

iii. Next steps and assessments schedule Presentation: Yes Duration: 20 minutes Background Item: EPA CO2 Draft Rule: NERC Plan* Personal Notes:

Draft Agenda – Planning Committee Meeting September 16-17, 2014 3

j. Performance Analysis Subcommittee - Melinda Montgomery, Chair of PAS Objective: Melinda Montgomery, Chair of the PAS, will provide an update on the subcommittee’s actions. Specifically, the PAS has developed a plan to review specific metrics through the close of 2014. They are also planning to develop a replacement metric for KCMI working with the CCC. The PAS also decided to include additional data analysis into the 2015 State of Reliability report, including GADS and DADS information.

Presentation: Yes Duration: 10 minutes Background Item: None Personal Notes:

k. Model Validation Update - Bob Cummings, NERC Staff Objective: i. 2014 Plan Status ii. Long Term Implementation Objectives Presentation: Yes Duration: 15 minutes Background Item: None Personal Notes:

l. 2014 Polar Vortex Weather Phenomenon Status Report – James Merlo, NERC Staff Objective: In early January 2014 a Polar Vortex impacted the ERCOT and Eastern Interconnections. NERC and the impacted Regional Entities are documenting this cold weather event in a report, Phase 1 of which is expected to be available in September 2014. Mr. Merlo will provide the PC with an overview of the report’s development. Presentation: Yes Duration: 15 minutes Background Item: None Personal Notes:

m. Power Plant and Transmission System Protection Coordination - Phil Winston, Chair of System Protection and Control Subcommittee (SPCS)

Objective: Provide a status report and overview of comments received during the 45-day public posting. SPCS is responding to comments and revising the report where deemed appropriate. A final report will be presented for approval at the December PC meeting. Presentation: Yes Duration: 10 minutes Background Item: None Personal Notes:

n. Order No. 754 – Study of Protection System Single Points of Failure - Phil Winston, Chair - SPCS Objective: Inform the Planning Committee of SPCS and SAMS observations and conclusions from the Section 1600 data request associated with FERC Order No. 754 and request assignment of members to review the draft report. The data request provides information on the potential reliability risk associated with protection system single points of failure. The observations and conclusions are based on review of data for buses operated at 200 kV and above. SPCS and SAMS will review data for buses operated between 100 kV and 200 kV in October and update its observations and conclusions, if necessary, and provide a final report for approval in December. Presentation: Yes Duration: 15 minutes Background Item: Draft Report will be provided for review by

September 24. Personal Notes:

o. Functional Model Demand Response Advisory Team (FMDRAT)* – Jerry Rust, Vice Chair of Functional Model Working Group

Objective: Review and discuss the FMDRAT’s findings and recommendations regarding the impacts of demand response programs on operations planning, which includes monitoring Demand Response (DR) development and identification of if and when DR technology and penetration levels creates a unique impact on BES reliability. Presentation: No Duration: 15 minutes Background Item:

1. Letter dated July 25, 2014 from Standards Committee to PC Chair Crisp*

2. A Report on Assessing the Need for Introducing Demand Response Functions and Entities to the NERC Reliability Functional Model*

Draft Agenda – Planning Committee Meeting September 16-17, 2014 4

Personal Notes:

p. AC Substation Equipment Task Force Status Update - John Moura, NERC Staff Objective: : The AC Substation Equipment Task Force (ACSETF) was formed to analyze one of NERC’s top priority reliability issues – AC Substation Equipment Failures. As reported in the NERC 2013 State of Reliability Report, AC substation equipment failures have been observed to be a significant contributor to disturbance events, and have a positive correlation to increased transmission severity for outages associated with them. The task force is developing a report for the industry which summarizes trends in disturbance events resulting from AC substation equipment failure, identification of root and contributing causes, and recommendations for actions to be presented at the December 2014 Planning Committee and Operating Committee meeting.

• The report is in progress and expected to be out for PC reviewers by September 25th.

• Report approval is due by OC/PC in December meeting.

• More details will be provided during presentation. Draft report will be available for PC reviewers by September 25th

Presentation: Yes Duration: 15 Minutes Background Item: None Personal Notes:

q. Spare Equipment Database Working Group Update – Nathan Mitchell, American Public Power Association

Objective: Revised scope approval request.

Presentation: No Duration: 20 minutes Background Item: SEWG Redline Scope* SEWG Clean Scope*

Personal Notes:

r. PRC Standards Under Development – Steve Crutchfield, NERC Staff Objective: Provide an overview of PRC Standards Development Projects. The presentation will address the following Protection and Control Standards / Projects under development:

• Project 2007-06, System Protection Coordination (PRC-027) - Project 2007-06 Background Information • Project 2007-11, DM (PRC-002) -Project 2007-11 Background Information • Project 2008-02, UFLS (PRC-006)- Project 2008-02 Background Information • Project 2010-05.2, Special Protection System and Remedial Action Scheme definitions - Project 2010-05.2

Background Information

• Project 2010-13.3, Stable Power Swings (PRC-026) - Project 2010-13.3 Background Information Presentation: Yes Duration: 30 minutes Background Item: Links provided above. Personal Notes:

s. Physical Security Guidelines CIP-014, Steve Crutchfield, NERC Staff Objective:

• Assemble a team of planning experts to evaluate / augment guidance related to: o Initial and subsequent risk assessment (per Requirement R1) o Unaffiliated third party verification of risk assessments

• In particular, we request guidance regarding the parameters for the transmission analysis necessary to perform the risk assessment and the mechanics of the verification process to streamline meeting the reliability objectives of Requirements R1 and R2.

• Provide final work product at conclusion of March 3-4, 2015 PC meeting. Presentation: Yes Duration: 20 Minutes Background Item: None Personal Notes:

Draft Agenda – Planning Committee Meeting September 16-17, 2014 5

6. Planning Committee and Subcommittees Project Queue Review

a. Planning Committee Work Plan

*Background materials included. ** Background materials will be provided prior to the meeting.

Draft Agenda – Planning Committee Meeting September 16-17, 2014 6

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

• Discussions involving pricing information, especially margin (profit) and internal cost information and participants’ expectations as to their future prices or internal costs.

• Discussions of a participant’s marketing strategies.

• Discussions regarding how customers and geographical areas are to be divided among competitors.

• Discussions concerning the exclusion of competitors from markets.

• Discussions concerning boycotting or group refusals to deal with competitors, vendors or suppliers.

NERC Antitrust Compliance Guidelines 2

• Any other matters that do not clearly fall within these guidelines should be reviewed with NERC’s General Counsel before being discussed.

III. Activities That Are Permitted From time to time decisions or actions of NERC (including those of its committees and subgroups) may have a negative impact on particular entities and thus in that sense adversely impact competition. Decisions and actions by NERC (including its committees and subgroups) should only be undertaken for the purpose of promoting and maintaining the reliability and adequacy of the bulk power system. If you do not have a legitimate purpose consistent with this objective for discussing a matter, please refrain from discussing the matter during NERC meetings and in other NERC-related communications. You should also ensure that NERC procedures, including those set forth in NERC’s Certificate of Incorporation, Bylaws, and Rules of Procedure are followed in conducting NERC business. In addition, all discussions in NERC meetings and other NERC-related communications should be within the scope of the mandate for or assignment to the particular NERC committee or subgroup, as well as within the scope of the published agenda for the meeting. No decisions should be made nor any actions taken in NERC activities for the purpose of giving an industry participant or group of participants a competitive advantage over other participants. In particular, decisions with respect to setting, revising, or assessing compliance with NERC reliability standards should not be influenced by anti-competitive motivations. Subject to the foregoing restrictions, participants in NERC activities may discuss:

• Reliability matters relating to the bulk power system, including operation and planning matters such as establishing or revising reliability standards, special operating procedures, operating transfer capabilities, and plans for new facilities.

• Matters relating to the impact of reliability standards for the bulk power system on electricity markets, and the impact of electricity market operations on the reliability of the bulk power system.

• Proposed filings or other communications with state or federal regulatory authorities or other governmental entities.

Matters relating to the internal governance, management and operation of NERC, such as nominations for vacant committee positions, budgeting and assessments, and employment matters; and procedural matters such as planning and scheduling meetings.

Announcement 2014 Planning Committee Election Results The Planning Committee (PC) opened nominations for 14 vacant positions from June 4 through June 25. One sector (Large end-use electricity customer sector) had more nominees than available open positions; therefore, balloting was required for that sector. The following twelve persons were nominated for, or elected to fill, the open positions on the Planning Committee to serve from 2014–2016, except as noted.

Sector Elected Member

1. Investor-owned utility Gary Thomas Brownfield, Ameren

2. State/Municipal Utility Aruther Iler, American Municipal Power (2 year) Andrew Wade Tudor, Municipal Energy Agency of Nebraska (1 year)

3. Cooperative utility Russ Schussler, Georgia Transmission Corporation

4. Federal or provincial utility/Federal Power Marketing Administration

Serge Fortin, Hydro-Québec TransEnergie David Jacobson, Manitoba Hydro

5. Transmission dependent utility Brian Evans-Mongeon, Utility Services, Inc. (2 year) Carl Turner, Florida Municipal Power Agency (1 year)

6. Merchant electricity generator Robert Ramaekers, Tenaska, Inc. (2 year) Michael Goggin, American Wind Energy Association (1 year)

7. Electricity marketer Steven Huber, PSEG Services Corporation

8. Large end-use electricity customer John Hughes, Electricity Consumers Resource Council

9. Small end-use electricity customer Herb Schrayshuen, Self-as Small End-User

10. ISO/RTO Mark Sims, PJM

In accordance with the Planning Committee charter, the newly elected members will serve on the PC committee pending approval by the NERC Board of Trustees.

Planning Committee 2014- 2015 Meeting Dates

Dates Time Meeting Location Hotel Information

2014

October 2, 2014 1:00-2:00 p.m. ET PC Conference Call 2014 LTRA

N/A N/A

November 4, 2014 1:00-2:00 p.m. ET PC Conference Call 2014/15 WRA

N/A N/A

December 9, 2014 10:00 – 11:00 a.m. ET PCEC Meeting Atlanta, GA Westin Buckhead Atlanta

December 9, 2014 1:00 – 5:00 p.m. ET PC Meeting Atlanta, GA Westin Buckhead Atlanta

December 10, 2014 8:00 a.m. – Noon ET PC Meeting Atlanta, GA Westin Buckhead Atlanta

2015

March 10, 2015 10:00 – 11:00 a.m. PCEC Meeting West Coast location TBD

March 10, 2015 1:00 – 5:00 p.m. PC Meeting West Coast location TBD

March 11, 2015 8:00 a.m. – Noon PC Meeting West Coast location TBD

May 2015 TBD PC Conference Call 2015 SRA

N/A

May 2015 TBD PC Confernce Call 2015 SOR

N/A

June 9, 2015 10:00 – 11:00 a.m. ET PCEC Meeting Atlanta, GA Westin Buckhead Atlanta

June 9, 2015 1:00 – 5:00 p.m. ET PC Meeting Atlanta, GA Westin Buckhead Atlanta

June 10, 2015 8:00 a.m. – Noon ET PC Meeting Atlanta, GA Westin Buckhead Atlanta

Dates Time Meeting Location Hotel Information

September 15, 2015 10:00 – 11:00 a.m. ET PCEC Meeting East Coast Canadian location

TBD

September 15, 2015 1:00 – 5:00 p.m. ET PC Meeting East Coast Canadian location

TBD

September 16, 2015 8:00 a.m. – Noon ET PC Meeting East Coast Canadian location

TBD

December 15, 2015 10:00 – 11:00 a.m. ET PCEC Meeting Atlanta, GA Westin Buckhead Atlanta

December 15, 2015 1:00 – 5:00 p.m. ET PC Meeting Atlanta, GA Westin Buckhead Atlanta

December 16, 2015 8:00 a.m. – Noon ET PC Meeting Atlanta, GA Westin Buckhead Atlanta

Planning Committee – 2014-2015 Meeting Dates 2

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 i  

 

         

                 

Essential Reliability Services Task Force A Concept Paper on Essential Reliability Services that Characterize Bulk Power System Reliability

September 2014

DRAFT 

Table of Contents

Preface ....................................................................................................................................................................... iii

Executive Summary ................................................................................................................................................... iv

Introduction ................................................................................................................................................................ v

Background ............................................................................................................................................................. v

Objectives .............................................................................................................................................................. vi

Essential Reliability Services .......................................................................................................................................1

Reliability Building Blocks .......................................................................................................................................1

Ancillary Services Compared to Essential Reliability Services ................................................................................3

Load and Resource Balance ....................................................................................................................................3

Operating Reserves .................................................................................................................................................3

Voltage Support ......................................................................................................................................................9

Voltage Control .......................................................................................................................................................9

Voltage Disturbance Performance ....................................................................................................................... 10

Frequency Support............................................................................................................................................... 10

Frequency Disturbance Performance .................................................................................................................. 11

Resource Mix Impacts to ERS .................................................................................................................................. 13

Emerging Resources – Distributed Resources ..................................................................................................... 14

Emerging Resources – Demand Response ........................................................................................................... 14

Emerging Trends and ERS Observations .............................................................................................................. 15

Conclusions and Way Ahead ................................................................................................................................... 17

Abbreviations .......................................................................................................................................................... 19

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 ii

Preface The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose mission is to ensure the reliability of the bulk power system (BPS) in North America. NERC develops and enforces Reliability Standards; annually assesses seasonal and long-term reliability; monitors the BPS through system awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico. NERC is the electric reliability organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the BPS, which serves more than 334 million people. The North American BPS is divided into several assessment areas within the eight Regional Entity (RE) boundaries, as shown in the map and corresponding table below.

FRCC Florida Reliability Coordinating Council

MRO Midwest Reliability Organization

NPCC Northeast Power Coordinating Council

RF ReliabilityFirst

SERC SERC Reliability Corporation

SPP-RE Southwest Power Pool Regional Entity

TRE Texas Reliability Entity

WECC Western Electricity Coordinating Council

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 iii

Executive Summary The North American Bulk Power System (BPS) is experiencing a transformation that could result in significant changes to the way the power grid is planned and operated. These changes include retirements of base load generating units, increases in natural gas powered plants, rapid expansion of wind, solar and commercial solar photovoltaic (PV) integration, and more prominent use of demand response and distributed generation. Conventional generation (steam, hydro, and combustion turbine technologies) inherently provide necessary operating characteristics, defined here as Essential Reliability Services (ERS), needed to reliably operate the North American grid. ERS represents a necessary and critical part of the fundamental reliability functions that are vital to ensuring BPS reliability; therefore, these services must be identified, measured and monitored so that operators and planners of the BPS are aware of the changing charateristics of the grid and continue reliable operation. Some variable energy resources (VERs) and newer storage technologies also have the capability to offer some components of these ERS to some extent. ERS are an integral part of reliable BPS operations. They are the elemental “reliability building blocks” provided by generation, and in some cases by demand response, storage and other elements necessary to maintain BPS reliability. Gaps in ERS can lead to adverse impacts on reliability. This paper identifies the reliability building blocks in three groups as listed below, and each of these groups may have one or more characteristics and attributes. As the overall resource mix changes, all the aspects of the ERS still need to be provided to support reliable BPS operation. Importantly, ERS are technology neutral and must be provided regardless of the resource mix composition. Defining the Essential Reliability Services Building Blocks

• Load and Resource Balance: required to maintain continuous load and resource balance. The BPS must have the capability and ability to raise and lower generation or load automatically or manually under normal and post contingency conditions.

• Voltage Support: required to maintain system level voltages on the BPS within established limits, under pre and post contingency situations, thus preventing voltage collapse or system instability.

• Frequency Support: required to maintain stable frequency on the synchronized BPS, by employing automatic response functions of a resource in response to deviations from normal operating frequency.

Conventional generators historically have provided most of the grid's ERS. As non-conventional generators are introduced to the power system, it is becoming necessary to examine each of the ERS requirements to ensure that the BPS remains reliable. Historically, the BPS has reliably operated without explicitly quantifying each ERS element, as most conventional resources provided these services as a result of being part of the grid. Recent trends and developments in industry are introducing alternative methods of achieving ERS. Research has shown that VERs can be capable of providing come components of these ERS; however, due to the variability of weather dependent resources, the ERS are not available continuously, thus making it difficult to rely on them consistently. The changing dynamics of BPS planning and operations warrants further study of these characteristics at both the micro and macro levels. NERC has commissioned the Essential Reliability Services Task Force (ERSTF) to study, identify and analyze the planning and operational changes that may impact BPS reliability as the resource mix continues to change. This report provides an initial overview of the primary elements comprising the ERS, and describes anticipated conditions based on known forecasts of resource changes.

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 iv

Introduction Background NERC’s annual Long-Term Reliability Assessment (LTRA) 1 informs industry, policy makers, and regulators and aids NERC in achieving its mission—to ensure the reliability of the North American BPS by assessing and identifying significant emerging trends in planning and operations that could negatively impact reliability. The 2013 assessment raised reliability concerns regarding the changing resource mix and included recommendations that NERC expand the methodology for assessing reliability. More specifically, the recommendations stated that NERC “develop a new approach and framework for the long-term assessment of ERS to supplement existing resource adequacy assessments.”1 This report discusses the change in dynamics of the modern BPS, how new technologies are improving and/or affecting existing ERS, and what combination of approaches will be required to ensure BPS reliability in the future. Figure 1 summarizes the changing resource mix taking place over the near future horizon. Some of these changes are due to increase in wind, solar, and natural gas-fired generation and how those increases are replacing retired coal and nuclear generation. Each category, peak & variable, midrange, and baseload may have resources that have identical characteristics and can be grouped based on their capabilities and normal operating characteristics. The operating characteristics of VERs (wind and solar) differ from those of large synchronous generators and those of midrange and peaking resources. As the industry continues on this trend, it is increasingly important to understand how a resource mix change affects the composition of the ERS, as well as the impacts on planning and operation of the BPS and what considerations need to be made to ensure reliability. A recent joint NERC-CAISO study has pointed out the significant resource mix changes have led to straining of certain generation and transmission system characteristics in California that are essential for maintaining the reliability of the BPS. This issue may not be unique to California. Today, ERS are largely provided by baseload and midrange conventional generation plants with significant rotating mass capability, with some VERs providing some ERS capabilities to an extent possible. The electric industry has established reliability expectations with these generating resources through knowledge accumulated over many years of experience. These conventional generation resources have predictable operating performance with well-understood reliability characteristics. New technologies and adaptation of existing technologies are possible by means of addressing reliability performance requirements, and technology – neutral guidelines or rules. The convergence of large quantities of VER (predominantly wind and PV), the increase in gas-fired generation, and the retirement of conventional coal and nuclear generation resources means a greater proportion of the total resource mix will have different ERS characteristics and thereby change operators’ control philosophy and/or requirements. ERS available to operate the BPS change as VERs are added to the system, sometimes replacing conventional electric generation provided by large rotating machines. Consequently, these services must be obtained from other sources besides conventional generation resources.

1 2013 Long-Term Reliability Assessment

Figure 1: Representation of changing resource mix in present and future

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 v

Figure 2 provides some context on the magnitude of the aforementioned resource mix changes over the next 10 years, where (a) shows wind and solar installations and (b) shows conventional generation retirements.

Figure 2: (a) Addition of Wind and Solar in 2023 and (b) Retirement of Conventional Generating Plants in 2023.

Objectives The objectives of this concept paper is to:

• Provide a reference for regulators and policy makers and to inform, educate, and build awareness on the ERS elements essential for the reliability of the BPS,

• provide background information on the changes to the electric grids in North America and other countries that indicate the need to identify, measure and trend ERS,

• Identify, define, and formulate an initial standardized set of Essential Reliability Services (ERS) to be considered by the task force.

The task force recognizes that ERS are technology neutral and must be provided regardless of the resource mix composition for a given operating area or Balancing Area (BA). ERS must be assessed based on the functional needs of the BPS and require a defined approach for verifying that a certain level of performance can be achieved in the long-term. Therefore, by specifying a technology-neutral assessment framework for ERS, a larger pool of reliability resources could be considered as contributing to the overall system needs. This approach encourages the development and implementation of new technologies to further enable and contribute to the provision of these services.

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 vi

Essential Reliability Services Reliability Building Blocks The essential reliability building blocks that represent primary components of ERS necessary to maintain BPS reliability2 are provided by load, generation, and in some cases Demand Response (DR), and storage resources. Figure 3 graphically represents these three building blocks are:

• Load and Resource Balance

• Voltage Support

• Frequency Support

Figure 3: Reliability Building Blocks – Definition and Effects of Lack of availability

2 Synchronous condensers, statcoms, and SVCs are also resources that provide ERS.

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 1

Essential Reliability Services

ERS are key services and characteristics that are needed to plan and operate the BPS. Many of these services and characteristics are widely provided under current industry resource mix with mainly base loaded conventional generating plants and load. This industry resource mix changes as the composition of VERs, DRs, and storage devices interconnect to the BPS in larger amounts. The reliability building blocks are listed below with underlying ERS characteristics:

• Load and Resource Balance

Operating Reserves: Operating Reserves (OR) is defined by the systems’ ability to maintain specified (in some BA’s) and/or adequate reserves beyond the firm system demand. Major attributes to OR consist of regulation, load following, and contingency reserves (spinning, non-spinning and supplemental). Load following in a particular area is provided over a longer time horizon and a wide range of output as opposed to resources that provide regulation within time frame of minutes and over smaller output levels. Contingency reserve resources provide resources during a contingency event and also ensure resources are available to replenish amount of output used during the contingency, thus returning the system to same level of balance pre contingency.

Active Power Control: APC is the ability of a system to control real power in order to maintain load and generation balance. Active Power Control attributes can include:

o Frequency Control: Frequency Control (FC) is a resources; ability to automatically intervene with real power output as a response to frequency deviation on the system. This is achieved by a generating plants’ autonomous governor response that adjusts its output to match interconnection scheduled frequency. FC usually is referred to normal operating conditions, i.e. pre-contingency, stable system conditions. FC is mostly incentivized in all interconnections, except for Eastern Interconnection, resulting in varied frequency control performance across all interconnections.

o Ramping Capability: Ramping is defined by the amount of upward or downward real power control by resources over a period of time needed to maintain load-generation balance. Ramping capability of a system is most needed at times of major load shifts, such as morning ramp up, afternoon ramp down and evening ramp up. In California, Ramping needs have emerged as an ongoing issue with integration of large amounts of solar PV. California’s challenges with ERS such as these are addressed in later part of this paper. As the typical load curve changes due to integration of off peak electrical loads, for e.g. electric vehicles and smart appliances, ramping needs may also change from morning and evening ramps to off peak ramps.

• Voltage Support

Reactive Power/Power Factor Control: The ability to control leading and lagging reactive power on the system to maintain appropriate voltage levels and acceptable voltage bandwidths, to maximize efficient transfer of real power to the load across the BES under normal and contingency conditions, and provide for operational flexibility under normal and abnormal conditions. Control of reactive resources can be performed by many reactive devices such as SVC’s, statcoms, capacitors, and reactors in addition to conventional generating plants and adequately designed VER and storage plants.

Voltage Control: The ability of the system to maintain adequate level of voltage in local, and across regional areas to support system loads, maintain transfers and devices connected to the system.

Voltage Disturbance Performance: The ability of the system to maintain voltage support during and after a disturbance in order to avoid voltage collapse.

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 2

Essential Reliability Services

• Frequency Support

Inertia: The ability of a machine with rotating mass inertia to arrest frequency decline and stabilize the system.

Frequency Disturbance Performance: The ability of a system to ride through disturbances and restore frequency levels to pre disturbance levels.

Ancillary Services Compared to Essential Reliability Services ERS are necessary to ensure reliability. The required amounts of each service and the resources providing them will vary by Balancing Authority (BA), Regions, and their associated BPS characteristics. Some ERS are already well-defined ancillary services, while others may become new ancillary services provided by market mechanisms of a BA or RTO. Special case ancillary services could be addressed through alternative means such as region or state specific interconnection agreements. Ancillary services, according to the NERC Glossary of Terms, are those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Service Provider's transmission system in accordance with good utility practice. 3 FERC defines ancillary services as:

“Those services necessary to support the transmission of electric power from seller to purchaser, given the obligations of control areas and transmitting utilities within those control areas, to maintain reliable operations of the interconnected transmission system. Ancillary services supplied with generation include load following, reactive power-voltage regulation, system protective services, loss compensation service, system control, load dispatch services, and energy imbalance services.” 4

Because of the critical role ancillary services play in maintaining reliability, they are considered a subset of ERS. NERC recognizes ancillary services in organized and bilateral North American regions as those reliability attributes necessary to support a reliable BPS. Ancillary services were established as requirements of FERC’s pro forma Open Access Transmission Tariff (OATT). These existing ancillary services were defined for a traditional system with conventional generating plants; however, with changing BPS characteristics they could be addressed by means of a technology neutral framework of performance metrics. Load and Resource Balance Operating Reserves Load and resource balance can be affected by range of variations in system load and generation, for e.g. evening load ramp, or unintended loss of a generating plant. ORs ensure sufficient amount of resources are available to address load and generation imbalance. ORs for example, can be included in Regulation, Load Following, and Contingency Reserves. These categories can be distinguished into two modes of the system: pre-contingency/normal and contingency. Regions differ in their OR definitions and requirements, but they all share some fundamental characteristics. Regulation is automatic mode of dispatch (by plants equipped with Automatic Generation Control (AGC)) to correct current Area Control Error (ACE), while load following is a mode of dispatch to correct anticipated ACE (intra– and inter-hour dispatch). Contingency reserves include spinning reserve that assist in stabilizing the system following a disturbance, and non-spinning reserves that return the frequency to nominal and ACE to zero. Supplemental reserves are used to restore the spinning and non-spinning reserves expended after the disturbance. Figure 4 represents that regulation and load following are services utilized during normal system operations; and contingency reserves are utilized after a contingency event.

3 Glossary of Terms Used in NERC Reliability Standards: http://www.nerc.com/files/glossary_of_terms.pdf 4 FERC Glossary of Terms: http://www.ferc.gov/market-ov ersight/guide/glossary.asp

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 3

Essential Reliability Services

Figure 4: Operating Reserves for Normal and Contingency Conditions on a system

Table 1 describes Operating Reserve categories generally known by the industry.

Table 1: Operating Reserves Categories

Description and Operation

Regulation • Used to manage the minute-to-minute differences between load and resources and

to correct for unintended fluctuations in generator output to comply with NERC’s Real Power Balancing Control Performance Standards (BAL-001-1, BAL-001-2)

Load Following • Follow load and resource imbalance to track the intra- and inter-hour load fluctuations within a scheduled period.

Spinning Reserve

• Online resources, synchronized to the grid that can increase output in response to a generator or transmission outage and can reach full output within 10 minutes to comply with NERC’s Real Power Balancing Control Performance Standards (BAL-001-1, BAL-001-2)

• Usually utilized after a contingency • Generally provides faster and more reliable response • VERs may not be spinning, but can be utilized as Spinning Reserves

Non-Spinning Reserve

• Similar in purpose as spinning reserve; however, these resources can be off-line and capable of reaching the necessary output within specified 15 minutes

• Usually utilized after a contingency

Supplemental Reserve

• Resources used to restore spinning and non-spinning reserves to their pre-contingency status

• Deployed following a contingency event • Response not need to begin immediately

Reliability Considerations for Operating Reserve Historically, demand changes over the course of a day have been predictable in terms of directional trends (i.e., consistent load duration profile). With the addition of variable generation, the net load (demand minus energy production from non-dispatchable resources) can shift the period of intraday peak demand. For example, a large PV penetration can shift the daily load peak downward due to available sun during the day. However, large amounts of VERs that are aggregated in output, such as concentrated areas of wind production, can introduce greater variability within the course of an hour or several hours. Greater variability (and uncertainty) in these time frames requires dispatch in both directions, up and down, and makes optimization of the unit commitment more

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Essential Reliability Services

challenging. Services such as regulation and contingency reserves need to be analyzed more frequently with significant penetration of VERs. As a result of the increased variability and uncertainty, OR requirements may change based on the available portfolio of resources for any given region. Active Power Control Traditionally Active Power Control (APC) is defined as the ability of the system to control real power in order to maintain load and generation balance. While there are many combinations of ERS that fall under APC, two additional ERS may apply here, namely Frequency Control and Ramping Capability. Variable generation is typically managed to maximize the production of electric energy from a zero-cost source of fuel. However, variable generation sources can be implemented with capability of operating under economic dispatch and are increasingly doing so in some areas of North America. Production of real power from most VERs is predominantly a function of meteorology and is subject to the nuances of complicated atmospheric dynamics. Predictions of future output—minutes, hours, or days ahead—are also subject to these complications, and therefore can only be made with some degree of uncertainty. In bulk system operations and control, accommodation must be made for the additional variability and uncertainty attendant with these resources.

Frequency Control

The essential workings of frequency as it relates to the balance of load and generation, which are fundamental characteristics of a stable BPS, are illustrated in Figure 5. Stable system frequency is one of the primary measures of health for a large, interconnected electric power system. One of the System Operator’s primary objectives is to maintain system frequency (in North America, operating frequency is 60 Hz).

Frequency represents an indication of the real-time balance between supply and demand; declining frequency indicates more demand than supply, while rising frequency results from more supply than demand. Further, frequency balance must be maintained within tens of mHz of the target 60 Hz.

Frequency

Figure 5: Frequency explained in terms of real power control.

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Essential Reliability Services

Frequency Control is required to maintain a stable system level frequency. It is available at two stages of response on the system; primary and secondary frequency controls. Table 2 explains in details the two stages of response.

Table 2: Frequency Control

ERS Element Definition Type of Service Response Time

Primary FC

Automatic and autonomous response to frequency variations through a generator’s droop parameter and governor response.

• Local frequency sensing

• Provided through generator governor control

• Can be provided through deliberate control of electronically coupled wind, solar, storage, and DR resources.

• Less communication infrastructure • May include automatic load shedding.

t ~ seconds

Secondary FC

Returns frequency to nominal value and minimizes unscheduled transient power flows due to power imbalance between neighboring control areas.

• Centralized within control centers through Automated Generation Control (AGC)

• Significant communication infrastructure

• Typically provided by generation but some DR can provide this service.

Slower than Primary

Primary < t > 15 minutes

Reliability Considerations for Frequency Control Sudden disruptions to the supply and demand balance increase the potential for adverse BPS reliability impacts. Loss of one to several generating units or loss of significant transmission system elements can negatively impact system frequency, requiring recovery response to restore frequency. There is also a concern that governor response may decline as the share of VERs in the system and retirement of base load generation plants increases. It is common for conventional generators to not operate at their maximum rated output allowing some governor modulation. This allows the generators to have some flexibility in the upward direction and help support the interconnection response to frequency perturbations in a timely manner. VERs, on the other hand, are generally operating at full production and are only able to provide governor-like response in the downward direction. Overall, an operating area requires complete capability to manage frequency control for stable system operation. Simulations of modern wind power plants have demonstrated improved frequency control by implementing fast response to an event at the cost of reducing a portion of its real power production. Specific levels of frequency response reserves need to be modeled, analyzed and incorporated in future planning and operating criteria. Specific levels of such support for varying resource mixes will need to be established based on the dynamics of their respective interconnected systems. Ramping Capability Ramping Capability is the ability of a resource to ramp active power upwards or downwards in a certain amount of time. It is typically measured on a MW/min basis. The BPS is planned and operated to accommodate ramping requirements imposed by the daily load profile. System ramping capabilities are based not just on the type of fuel source available, but also the type of prime mover used in each generating unit, for e.g. gas combustion turbine, steam turbine, etc. The addition of variable generation, net-load variability and uncertainty on the system require more flexibility in terms of providing ramping capability. Figure 6 shows forecasted ramping requirements for

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Essential Reliability Services

2020 load and net load scenarios conducted for CAISO.5 Refer to the joint NERC and CAISO report for more information on the study assumptions used for this scenario.

Figure 6: Wind, and Solar Base Load Scenario for Ramping in 2020

Some modern utility-scale VERs have greater ramp control capability for control than coal-fired conventional generators (up or down). Downward ramps are accomplished by curtailing production,6 which is a normal feature for wind and utility scale solar power plants, however, for Distributed Generation (DG) applications these capabilities are not typical and there is limited control linked to the system operators. Consequently, determining the required levels of ramp control needed for a Balancing Authority containing significant amounts of VERs is dependent on the level of resources, resource mix, and net load ramp behavior essential to bulk system reliability. Figure 7 explains in details ramping provisions provided by VERs. Both ramp rate, direction, and ramp range are important because ramping capability requirements change hourly based on both the system load (hour of day, day of week) and the availability of VER (both wind and solar). Consequently, system ramping capabilities and requirements are heavily intertwined with the dispatch control of the power system, which balances system needs with system economics.

5 A joint NERC and CAISO special reliability assessment report, 2013 Maintaining Bulk Power System Reliability While Integrating Variable Energy Resources – CAISO Approach, http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC-CAISO_VG_Assessment_Final.pdf. 6 Modern utility-scale wind and solar plants can typically control their output from zero to whatever the full currently available power level is. Conventional generators typically have minimum load levels that they cannot reduce power below. Minimum loads can be 40 percent or higher for coal plants, and nuclear plants may offer no control capability to the power system operator. Some combustion turbines must be block loaded for emissions reasons and also offer no control capability. Ramping control is typically faster and more accurate for the new wind and solar plants than for fossil fired or nuclear plants.

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Essential Reliability Services

Reliability Considerations for Ramping Capability System operators must accurately follow net load and minimize inadvertent energy flows. To meet this operational task, system operators need enough flexible resources with sufficient ramping capability to balance the system in real time. It is important to evaluate the overall composition of resources within a control area to ascertain both the capabilities and requirements for ramping and system balance. An aspect of this involves distinguishing between the ramping limitations of a conventional as well as VER resource response operational conditions that result from the unexpected loss of a VER or other plant. Further, it is key to determine whether or not these resources are connected to the distribution system. Large, utility-scale wind and solar plants are already required to have the capability to limit production and control ramp rates to support system BPS reliability. For distributed resources, the system operator may have little to no visibility and control. A comprehensive study of ramping capabilities of generating plants currently interconnected to the BPS is needed to establish quantitative measures needed to support reliable balanced operation linked to the underlying resource mix. These measures may be used to establish an acceptable level of ramping needs for various regions depending on their resource mix and VER penetration and guide requirements for new interconnecting VERs in regards to ERS. The capability of the composite resource mix to ramp down and/or disconnect from the BPS is crucial in maintaining reliability as it also translates to Disturbance Performance, which is a characteristic of ERS, explored in latter half of the paper.

There are four types of controlled changes in variable generation real power production:

Ramp – The change in VER production over a defined period of time, e.g., MW/min. The duration of the change may also be important and is sometimes used as a qualifier: “sustained” ramp. A ramp can either be natural (driven by the meteorology) or controlled by operators.

Ramp Rate Limit – A change in VER production over time that is controlled by technology within the VER plant; e.g., coordinated pitching of individual wind turbine blades or a limitation imposed by the inverters in a PV plant on the change of production over time.

Economic Dispatch – The purposeful following of system operator economic dispatch commands, within the current physical capability of the plant (Note: AGC is not the same as economic dispatch.

Curtailment – The purposeful limiting of real power production from a VER plant to an instructed level, which may be zero.

Ramping Capabilities of VERs

Figure 7: Ramping Capabilities pertaining to VERs

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Essential Reliability Services

Voltage Support Reactive Power/Power Factor Control Unlike Active Power Control and other ERS, reactive power control is supporting service for the real power that enables transmission of voltage through the BPS. The process of controlling reactive power on interconnected transmission systems is well understood from a system operations perspective. Similarly, maintaining an acceptable power factor is a technically understood planning and operational service, and in some cases enforced by BA, TOP regulations. Figure 8 describes voltage and reactive power support conceptually, where BPS loads absorb reactive power (measured in var, volt amps reactive, or in Mvar, millions of volt amps reactive) that causes voltage to deviate from acceptable limits. Three objectives dominate reactive power management:

1. Provide reactive power source to loads, transmission lines and transformers on the system.

2. Maintain unity power factor (provide exact amount of reactive power as consumed) at load aggregation spot, like a substation.

3. Minimize real power losses caused by overheating of equipment due to increased reactive power absorption.

While reactive support must be provided locally throughout the power system, these resources are controlled centrally because they require a comprehensive view of the power system to be accurate. Various devices, such as shunt capacitor banks, synchronous condensers, and static var compensators (SVCs), can provide reactive support. Generally, suppliers of the resources are not able to independently determine the system’s reactive needs. Only a planning and operating entity has sufficient information to know the system requirements, both during normal and contingency conditions, to deploy those resources effectively. Voltage Control Voltage control can be defined as the ability of a system to manage reactive power. Traditionally, in synchronous generators, the excitation system that provides direct current to the field winding of a machine, maintains reactive power input and output to maintain a voltage schedule at the delivery point. But the generating machine also provides reactive power through other parts such as stator and rotor. Therefore, it must be noted that Voltage Control is not an independent service or characteristic from Reactive Power Control, and is dependent on physically moving parts of a generating machine. Capacitors, reactors, SVC’s and similar devices also provide reactive power and voltage control. Generators and various types of transmission equipment are used to maintain voltages throughout the transmission system. In general, injecting reactive power into the system raises voltages, and absorbing reactive power lowers voltages. Voltage control requirements can differ substantially from location to location and can change rapidly. At very low levels of system load, voltages may increase based on transmission line characteristics. At high levels of load, however, transmission lines absorb reactive power and voltage is reduced.

Most types of loads;

induction motors

Absorb Reactive Power

Voltage balance within acceptable range using reactive power control

Bulk

Pow

er S

yste

m L

oads

Reactive Control Devices

Capacitor Banks, Static Var

Compen-sators In

ject

Rea

ctiv

e

Figure 8: Graphical Representation of Reactive Power Control

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Essential Reliability Services

Voltage Disturbance Performance An inherent characteristic of BPS is to maintain acceptable levels of voltage during normal operations and after a disturbance. These phenomena could be termed as voltage stability or voltage profile control. Unavailability of sufficient reactive power can lead to voltage instability and ultimately can cause partial or complete voltage collapse. The BPS is designed and built to withstand disturbances up to certain levels of instability in voltage. The industry needs to continue to review and analyze voltage performance under normal and post disturbance conditions. Reliability Considerations for Reactive Power/Power Factor Control, Voltage Control, and Voltage Disturbance Performance Reactive power requirements can change rapidly, especially under contingency conditions. Resources with dynamic reactive power control capability (all generators, SVCs, and synchronous condensers) are necessary to maintain system reliability. System operators must monitor and manage reactive power reserves just as they must monitor and manage real power reserves. Changes in the resource mix of the generation fleet will impact reactive power management and controlling voltage. Reactive power cannot be transmitted as far as real power, so generator reactive capability and location is particularly important in managing voltage. Synchronous generators are excellent resources for reactive support and voltage control. Power system reactive power and voltage control requirements must be considered when the generators are designed and built, with additional costs incurred to obtain the needed capabilities. Utility-grade inverters that couple modern wind generators and PV plants with the BPS can incorporate dynamic reactive power and voltage control capabilities as well.7 Naturally, obtaining greater capability comes with greater cost, as is the case with conventional generators. Frequency Support Inertia Total interconnected inertia is an important reliability characteristic. Maintaining a sufficient level of inertial response is crucial to arresting the initial frequency decline and slows the frequency fall that occurs from the unexpected loss of a generation resource in the interconnection. The aggregate effect of inertia within an interconnection to arrest the initial frequency decline allows time for the generator governors and other responsive resources to restore the frequency to 60 Hz. Inertia is an inherent attribute of synchronous machines (generators and motors) and is not directly under a generator operator’s ability to control. Increased penetration of VERs, in addition to the retirement of conventional large coal-fired generation plants with massive prime movers, has increased the need to ensure that adequate sources of inertia are present within the interconnection and to maintain a sufficient level of inherent frequency support. Table 3 describes inertia in detail.

7 Inverters can be designed to provide dynamic reactive support to the BPS even when the wind or solar generator is not producing real power, a capability that very few large synchronous generators can match. The added cost must be considered when deciding on this capability.

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Essential Reliability Services

New technologies offer new opportunities to provide ERS. For example, wind power plants, some energy storage devices, and dc interties can be controlled to provide “synthetic” inertia. Synthetic inertia is a solution requiring wind generating units and energy storage plants with dc converters, which are normally insensitive to frequency changes to be able to inject power into the BPS. This injection of power would be required following the loss of another generating unit, similar to conventional synchronous generating units in order to arrest the initial decline in frequency. This function is achieved via sophisticated control actions. Some DR resources, if equipped with dc inverters, can also provide fast response that is required in the inertia and governor response time frames (discussed further in the Demand Response section below). All of these factors point to the need for an inertia ERS component with individual generating unit and Balancing Authority level system requirements. While the concept of inertia is not new, the concept of synthetic inertia is new and will need to be addressed in a coordinated fashion by the industry and device manufacturers.8 Frequency Disturbance Performance Disturbance ride-through capability of an interconnected plant is an important generating unit requirement for normal and contingency conditions. A sudden disconnect, or trip offline, of a plant because of a disturbance on the system can cause power quality issues on the system while also degrading BPS equipment. Frequency ride through can be defined as ability of a plant to stay operational during a disturbance and restore frequency to nominal after a disturbance. While it is accepted that the reliability of the grid depends on the adequacy of generation and transmission systems to meet load demand at all times, it is also heavily dependent on performance of the BPS system during and immediately after system disturbances. System disturbances are most often are initiated from an unexpected transmission or generation event, but can also be initiated from distribution level system events. During such disturbances, performance of all the remaining interconnected BPS system elements should enable the transition to an acceptable steady state. Generation resources and their associated control and protection systems play a key role in providing system dynamic performance. Reliability Considerations for Inertia and Frequency Disturbance Performance System reliability can be severely impacted during system disturbances, if generation resources are inadvertently lost (or their output significantly altered) causing voltage and frequency transients. Therefore, all generation resources not directly involved in the disturbance should continue supplying real and reactive power immediately after a disturbance. All generators with available capacity and options at the time of the disturbance should respond to support reliability.9 Grid disturbance performance requirements are often used to ensure minimum capabilities of all resources to contribute to grid security around system disturbances. A properly defined requirement must unambiguously

8 Grid Code Review Panel Paper, Future Frequency Response Services, https://www.nationalgrid.com/NR/rdonlyres/59119DD3-1A8D-4130-9FED-0A2E4B68C2D2/43089/pp_10_21FutureFrequencyResponseServices.pdf 9 Nuclear plants may not be allowed to provide governor response by license.

Table 3: Inertia

ERS Element Definition Type of Service Response

Time

Inertia

Stored rotating energy on the BPS. It is the accumulation of the inherent response of synchronous generators that arrests system frequency decline.

Provided inherently by synchronous machines

• May be provided through deliberate control of VERs

• Local frequency sensing – applicable to synthetic inertia only

cycles

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Essential Reliability Services

define the grid conditions for which the generator must provide the performance, as well the specifics of the performance that must be provided. Disturbance performance requirements that are unclear often result in different interpretations and different implementation by individual regulatory authorities (i.e., states and provinces), possibly compromising the reliability of the BPS. There are also concerns with fast reconnection after a fault, particularly for distributed resources. In general, wind and solar plants are often able to return to service faster than thermal plants because of their electronically coupled minimum available disturbance ride through capability. Supply from these resources may be interrupted more often because of minimal ride-through capability, but the reason they can return more quickly is because they are not dependent on complicated thermal and mechanical systems such as boilers. On the BPS, system operators may elect to control these resources and use their quick-start function to support reliability. However, distributed resources often lack system operator control and visibility and may reconnect without considering the reliability of the BPS. Efforts are underway to require disturbance ride-through from distributed resources in the future, through the IEEE Standard 1547 revision process. This effort supports future BPS reliability and will prevent further degradation of the overall resources with this capability.

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 12

Resource Mix Impacts to ERS There is an inherent need for changes to the existing planning and operations model, due to the convergence of various changes to the North American BPS. These changes include retirements of base load generating units, addition of natural gas powered plants, increasing levels of wind, solar and Commercial PV integration, and prominent use of DR. These changes alter the resource mix, and focus the need on determining the required elements of ERS needed to support a reliable BPS. Power system planners must consider the impacts of all these changes in power system planning and design and develop the practices and methods necessary to maintain long-term BPS reliability. Operators will require new tools and practices, which may include potential enhancements to NERC Reliability Standards or guidelines to maintain BPS reliability. Figure 9 shows the planned gas-fired generation and renewable resources, as well as conventional plant retirements expected in the near future. In relation to ERS, as the resource mix changes, the requirements for maintaining ERS may change. For example, as solar penetration continues to increase in California, the morning up-ramp and evening down-ramp profiles will change based on reliability requirements. Gaps in ERS can lead to adverse impacts on reliability. As previously described, resource adequacy addresses the question of whether a given system has enough resources to meet expected demand. However, being resource-adequate does not necessarily equate to having the right type of resources with the right functional capabilities to maintain reliability. For example, a system with all coal-fired generation may not have the ramping capability to support hourly changes in load. On the other hand, a system that has significant penetration of wind and solar may not be able to provide the right level of operating reserves or frequency response needed to support other contingencies on the system. In Figure 10, a graphical display of the resource stack is presented along with the ERS “building blocks.” The "Potential Future" resource stack represents a system with high levels of variable generation and less conventional generation. While both hypothetical systems may be above the reserve margin target, several gaps (represented by white blocks) are present. It is important to note that with supporting policies, incentives, and standards gaps in ERS can be severely diminished. That is, ERS are technology neutral and must be provided regardless of the resource mix composition.

-40-30-20-10

0102030405060

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Gig

awat

ts (G

W)

Gas Renewable Resources

Figure 9: LTRA Projected change in resource mix and base load retirements

Figure 10: Potential Future Gaps in ERS

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 13

Resource Mix Impacts to ERS

Emerging Resources – Distributed Energy Resources An important element of BPS reliability is the ability to support grid reliability during a disturbance, which requires both Voltage Ride-Through (VRT) and frequency ride-through (FRT) capability. Under high penetration scenarios, it is possible for a large amount of Distributed Energy Resources (DERs) to trip on voltage or frequency due to transmission contingency, which could potentially affect BPS stability. Because frequency is a wide area phenomena, resources with little tolerance for frequency deviations (i.e., current solar PV units connected at the distribution level) can significantly impact BPS reliability, particularly when they share the same trip points. As an example, Germany has an installed capacity of over 10,000 MW of distributed PV, has recognized the need to integrate DERs into the dynamic support of the network and has; proposed the following:

1. Prevent DERs from disconnecting from the system due to faults on the system;

2. Require DERs to support the network voltage during faults by providing reactive power into the system; and

3. Require DERs to consume the same or less reactive power after the fault clearance as prior to the fault. Distributing generation resources throughout the power system can also have a beneficial effect if the generation has the ability to supply reactive power and this ability is coordinated by the system operator. Without this ability to control reactive power output, performance of the transmission and distribution system can be degraded. Given the growing penetration of distribution-connected variable generation, there is an increasing need to understand its characteristics and overall contribution to ERS. NERC assessments have concluded that DERs, in aggregate, can impact the operation of the BPS. Emerging Resources – Demand Response Demand Response (DR) is a growing component of the BPS resource mix. Industrial, commercial, and residential DR has been effectively used for decades for peak reduction. NERC long-term reliability assessments have noted the benefits that DR provides, along with careful considerations of issues needed to be studied with the increasing portfolio of DR. Advances in communications and controls technologies are responsible for expanding the ability of all types of consumers to respond directly and quickly to frequency deviations including disconnecting their behind-the-meter resources and also to respond to system operator instructions. DR is not a single technology; rather DR is any technology that controls the rate of electricity consumption rather than the rate of generation. DR, with suitable added technology components, can also provide regulation, governor response, spinning reserve, non-spinning reserve, and supplemental Operating Reserve (Kirby, et al. 2003, 2008, and 2009). For example, ERCOT obtains half of its spinning reserves from DR and is considering a DR-based Fast Frequency Response Service (FFRS) that is positioned between inertia and governor response (ERCOT 2013). DR can enhance power system reliability by increasing the reserve resource pool available to the system operator, provided that there is adequate control, visibility, and availability. This is especially important as conventional generators retire and as VERs increase reserve requirements. DR technologies that can meet prevailing performance criteria should be considered as part of the fleet of resources available for all power system balancing needs. Different technologies can be successful for different applications in different locations, depending on the specific characteristics of the local loads. Significant levels of DR have enabled peak shaving and reliable operation of the BPS, thus this emerging trend is an important future service to be monitored by NERC’s long term and seasonal assessments.

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Resource Mix Impacts to ERS

Emerging Trends and ERS Observations A changing generation mix has the potential to impact the reliability of the power system, especially in areas with large percentage changes. The following sections provide several regional examples. California The NERC-CAISO 2013 special assessment provides insight into CAISO’s approach on renewables integration. Figure 11 depicts current and projected variable generation penetration in California. The report concludes that improved operating practices, procedures, and tools are critical for accommodating large amounts of VERs (i.e., 20–30 percent) into any power system and for improving the control performance and reliability characteristics of the power system as a whole. System resources supporting reliability, such as flexible generation and responsive load, are finite. Operating practices, procedures, and tools that maximize the effective use of limited responsive resources improve reliability and facilitate variable generation integration. Operational tools can also help support and maintain the system’s ERS. Additional system flexibility and essential reliability service requirements will also increase. This flexibility manifests itself in terms of the need for dispatchable resources to meet increased ramping, load-following, and regulation capability—this applies to both expected and unexpected net load changes. This flexibility will need to be accounted for in system planning studies to ensure system reliability. System planning and VER integration studies focus both on the reliability and economic optimization of the power system—here the emphasis is on reliability. Hawaii Hawaii is rapidly integrating renewable resources into its power grid, as shown in Figure 12. The current capacity makes up 13 percent of the total resources with a goal to reach 40 percent by 2030. In extreme events, Hawaii uses a load-shedding scheme as an operating procedure. Part of the Hawaiian network experiences operational reliability issues due to the loss of inertia and the loss of generating units used to control transient instability driven by the significant non-controllable generations and lack of sufficient attention to ERS. A combined GE and Hawaii report on renewable integration recommended mitigation actions on frequency response and active power control with increased dependability on fast-starting generation to provide ramping capabilities.

Figure 11: Current and Projected Wind and Solar Penetration in California. (Source: Ventyx)

Figure 12: Resource Mix in Hawaii

7.5% 17.8%

17.6% 24.7%

Current Percentage Installed MW Wind and Solar Name Plate

2023 Percentage Planned MW Wind and Solar Name Plate

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 15

Resource Mix Impacts to ERS

Germany In some areas of North America, it is possible that very high penetrations of variable generation could be achieved in the future, as has occurred in some regions of Germany (VTT and Dena 10 ). As mentioned earlier, under these circumstances, bulk ERS are required to maintain grid reliability. In recent years, electricity production from DG in Germany increased significantly due to the German Renewable Energy Sources Act. Photovoltaic power plants have shown the highest growth rates. About two thirds of photovoltaic power plants in Continental Europe are connected to low voltage networks. Related grid codes allow for DG only to operate within frequency ranges that are in many cases extremely close to nominal frequency. During abnormal system conditions, the frequency of a region may increase above those ranges and DG would disconnect immediately— posing a significant challenge for BPS performance during and after a disturbance. In 2011, Germany was the largest European producer of variable generation including wind, biofuel, and solar. In North Germany, wind serves 33 percent of peak load energy. Occasionally, with high winds and congestion in the transmission system, the North German system faces supply and demand challenges. The VTT and Dena studies recommend ride-through capabilities to improve balancing requirements. Voltage and frequency ride-through requirements have since been implemented in the German grid codes for both utility scale and DG projects; though, after-the-fact measures to preserve BPS reliability has resulted in significant costs. Texas ERCOT has significant experience maintaining operational reliability with substantial and increasing levels of interconnected variable generation. Using a combination of state-of-the-art wind generation forecasts and flexible levels of ancillary services, ERCOT manages available wind and solar generation to support system reliability utilizing current procedures. Texas continues to develop wind farms along the coastline of Texas. These installations have a slightly higher capacity factor compared to the plants sited in inland Texas and the panhandle areas. This development should increase the overall benefit from wind generation.

Given the transition of generation occurring across Texas, ERCOT has explored improvements and changes to the current ancillary services approach. These improvements capture key BPS operational needs and are in line with the ERS discussed in this paper.

10 VTT Technical Research Center of Finland, “Design and Operation of Power Systems with Large Amounts of Wind Power - first results of IEA collaboration,” http://www.ieawind.org/annex_XXV/Meetings/Oklahoma/IEA%20SysOp%20GWPC2006%20paper_final.pdf

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 16

Conclusions and Way Forward The North American electric system is and will continue to experience an increased penetration of variable resources, retirements of conventional coal and nuclear units, and an increase in gas generation. This change substantiates the need for an industry level review of the impact to ERS evolving from the emerging conditions. The results of this review may come in many forms, but some of them could be:

• Detailed analysis of each service with new system parameters and criteria, linked to the underlying resource mix composition

• A framework for a longer-term assessment of technical parameters for each service

• Other solution sets for maintaining reliability can be derived from:

Exploring and incorporating new technology integration, and

Enhancements to reliability standards or requirements Next Steps Newly integrated technologies can be a challenge in some areas of the North American system. Extensive research is being conducted to evaluate what ERS functions that they might provide and other opportunities. This research is independently conducted by subject matter experts, academia and manufacturers. For example, certain types of wind turbine generators are equipped to provide inertia and ramping capability faster than conventional generators. However, these units are rarely installed on the BPS due to limited availability and high cost, may not be available at all times, nor may be able to sustain an output. Based on the current research, newly revamped NERC standards, and available electronics technology; following are examples of possible ways to address the need for ERS:

• Reactive Power and Voltage Control – Develop an interconnection and sub-regional voltage stability metric.

• Synthetic Inertia – Utilize synthetic inertia where available through wind farms to arrest frequency decline.

• Active Power Control, and Frequency Support – Leverage work done via NERC’s Integration of Variable Generation Task Force (IVGTF) and Frequency Working Group (FWG) in developing new and updating NERC standards.

• Ramping Capability – Establish a baseline for ramping needs and availability. Then, identify how the changing resource mix is impacting ramp availability. The difference of the ramp rate from current conditions to projected system conditions will identify a ramping capability margin that can be utilized to ensure sufficient resources are available to provide that service. North American regions like California are exploring the possibility of flex ramping capability to accommodate massive influx of solar and wind power on their system.

Other services can be quantified or analyzed by developing an assessment that will identify metrics, procedures, and methodologies to determine the need for, provide for, and maintain ERS in an electric system. The assessment will focus on following:

• Engineering and technical details for each service, linked to the composition of the resource mix.

• Framework for assessment of data required to measure and formulate a metric for each service.

• Data collection and analysis to quantify these services.

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 17

Conclusions and Way Forward

NERC through the ERSTF will work with entities in different NERC Regions, to develop appropriate guidelines, practices, and requirements to assure the BPS benefits from the advanced capabilities of all new technologies while also assuring that reliability is maintained.

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 18

Abbreviations Abbreviation Term

AGC Automatic Generation Control

APC Active Power Control

AS Ancillary Service

BA Balancing Authority

BPS Bulk Power System

CAISO California Independent System Operator

DER Distributed Energy Resource

DR Demand Response

ERS Essential Reliability Services

ERSTF Essential Reliability Services Task Force

FRT Frequency Ride-Through

FR Frequency Response

LTRA Long-Term Reliability Assessment

NG Natural Gas

NERC North American Electric Reliability Corporation

OR Operating Reserve

PV Photovoltaic

SVC Static Var Compensator

VER Variable Energy Resource

VRT Voltage Ride-Through

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 19

References

Alberta Electric System Operator, “Wind Power Facility Technical Requirements,” November 2004, http://www.aeso.ca/files/Wind_Power_Facility_Technical_Requirements_Revision0_signatures_JRF.pdf

T. Denger, ET. al., “Utility-Scale PV systems: Grid Connection Requirements, Test procedures and European harmonization,” http://www.der-lab.net/downloads/pvi4-08_3.pdf

A. Ellis, “Interconnection Standards for PV Systems,” UWIG Fall Meeting, Cedar Rapids, IA, 2009, http://www.uwig.org/pvwork/4-Ellis-InterconnectionStandards.pdf

European Wind Energy Association, “Generic Grid Code Format for Wind Power Plants,” November 2009, http://www.ewea.org/fileadmin/ewea_documents/documents/publications/091127_GGCF_Final_Draft.pdf

ERCOT, “Future Ancillary Services in ERCOT,” ERCOT Concept Paper, Draft Version 1.1, November 2013, http://www.ercot.com/content/news/presentations/2014/ERCOT%20AS%20Concept%20Paper%20Version%201_0%20as%20of%209-27-13%201745.pdf

FERC Glossary, accessed April 2014, http://www.ferc.gov/market-oversight/guide/glossary.asp

FERC Order 888-A, Promoting Wholesale Competition through Open Access Non-discriminatory Transmission Services by Public Utilities, March, 1997, http://www.ferc.gov/legal/maj-ord-reg/land-docs/order888.asp

FERC Large Generator Interconnection Agreement, http://www.ferc.gov/industries/electric/indus-act/gi/stnd-gen/2003-C-LGIA.doc

FERC Large Generator Interconnection procedures, http://www.ferc.gov/industries/electric/indus-act/gi/wind/appendix-G-lgia.doc

ISO New England, “New England Wind Integration Study Report,” http://www.iso-ne.com/committees/ comm_wkgrps/prtcpnts_comm/pac/reports-/2010/newis_report.pdf

J. Ingleson and E. Allen, 2010, “Tracking the Eastern Interconnection Frequency Governing Characteristic,” IEEE Power and Energy Society General Meeting, Minneapolis MN, July

B. Kirby, M. Starke, S. Adhikari, 2009, NYISO Industrial Load Response Opportunities: Resource and Market Assessment, New York State Energy Research and Development Authority, Oak Ridge National Laboratory, http://www.consultkirby.com/files/NYISO_Industrial_Load_Response_Opportunities.pdf

B. Kirby, J. Kueck, T. Laughner, K. Morris, 2008, Spinning Reserve from Hotel Load Response: Initial Progress, ORNL/TM 2008/217, Oak Ridge National Laboratory, October, http://www.consultkirby.com/files/TM2008-217_Spin_From_Hotel.pdf

B. Kirby, J. Kueck, 2003, Spinning Reserve from Pump Load: A Technical Findings Report to the California Department of Water Resources, ORNL/TM 2003/99, Oak Ridge National Laboratory, November, http://www.consultkirby.com/files/TM2003-99_CDWR.pdf

LBNL/FERC Report, Use of Frequency Response Metrics to Assess the Planning and Operating Requirements for Reliable Integration of Variable Renewable Generation, LBNL-4142E, December 2010, http://certs.lbl.gov/pdf/lbnl-4142e.pdf

NERC “2013 Long-Term reliability Assessment,” December 2013, http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2013_LTRA_FINAL.pdf

NERC IVGTF Task 1-1, “Standard Models for Variable Generation,” May 2010, http://www.nerc.com/files/Standards%20Models%20for%20Variable%20Generation.pdf

NERC IVGTF Task 1-2, “Methods to Model and Calculate Capacity Contributions of Variable Generation for Resource Adequacy Planning,” March 2011, http://www.nerc.com/files/ivgtf1-2.pdf

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 20

References

NERC IVGTF Task 1-3, “Interconnection Requirements for Variable Generation,” September 2012, http://www.nerc.com/files/2012_IVGTF_Task_1-3.pdf

NERC IVGTF Task 1-4, “Flexibility Requirements and Metrics for Variable Generation: Implications for Planning Studies,” August 2010, http://www.nerc.com/files/IVGTF_Task_1_4_Final.pdf

NERC Reliability Principles, http://www.nerc.com/files/Reliability_Principles.pdf

NERC Definition: Adequate Level of Reliability for the Bulk Power System

NERC IVGTF Task 1-5, “Special Report: Potential Reliability Impacts of Emerging Flexible Resources,” November 2010, http://www.nerc.com/files/IVGTF_Task_1_5_Final.pdf

NERC IVGTF Task 1-6, “Probabilistic Methods”

NERC IVGTF Task 1-7, “Low Voltage Ride-Through Requirements”

NERC IVGTF Task 1-8, “Potential Bulk System Reliability Impacts of Distributed Resources,” August 2011, http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/IVGTF_TF-1-8_Reliability-Impact-Distributed-Resources_Final-Draft_2011%20(2).pdf

NERC IVGTF Task 2-1, “Variable Generation Power Forecasting for Operations,” May 2010, http://www.nerc.com/docs/pc/ivgtf/Task2-1(5.20).pdf

NERC IVGTF Task 2-2, “BA Communications”

NERC IVGTF Task 2-3, “Ancillary Services and Balancing Authority Area Solutions to Integrating Variable Generation,” March 2011

NERC IVGTF Task 2-4, “Operating Practices Procedures and Tools,” March 2011, http://www.nerc.com/files/ivgtf2-4.pdf

NERC Reliability Standards, accessed April 2014, http://www.nerc.com/pa/stand/Pages/default.aspx

D. Woodfin and J. Dumas, ERCOT, August 2009

NERC | Concept Paper On ERS that Characterize Bulk Power System Reliability | September 2014 21

EPA CO2 Draft Rule: NERC Plan August 2014

Background The Environmental Protection Agency (EPA) proposed a draft rule under Clean Air Act Section 111 (d) on June 2 to cut carbon dioxide emission from power plants by 30 percent of 2005 levels by 2030. Substantial CO2 reductions are required under state implementation plans. As the Electric Reliability Organization, NERC is charged with ensuring the reliable operation of the North American bulk power system and assessing long term reliability impacts. Key Points

• NERC’s mission is ensuring the reliability of the North American bulk power system. In order to do that, NERC performs reliability-centered assessments that focus on potential impacts to the bulk power system.

• This focus has resulted in a wide-ranging series of technical reliability reports, which inform decision makers and help better position industry.

• As the expert in electric reliability, NERC reports and assessments of potential impacts are based on solid technical and engineering data and bulk power system analysis.

Activities

• The NERC Board of Trustees endorsed a plan for the review and assessment of the reliability impacts of the EPA proposal at its August 2014 Board meeting. This plan includes a preliminary review of the assumptions and potential major reliability impacts resulting from implementation of EPA’s notice of proposed rulemaking under Section 111(d). NERC will incorporate these observations and findings in the 2014 Long-Term Reliability Assessment, expected to be released in October.

• With EPA scheduled to finalize its rule by June 2015, NERC has planned a second and more comprehensive reliability assessment report that will focus on evaluating generation and transmission adequacy, as well as the major reliability impacts.

• After the EPA rule is finalized, the states, either individually or in regional groups, are required to develop state implementation plans by 2016 and 2018 respectively. NERC plans to provide a more specific and comprehensive reliability assessment in advance of state implementation plans due to EPA.

Overview of EPA Proposed Rule – Clean Air Act Section 111(d)

• The proposed CO2 rule for existing units is nearly 1,000 pages and reflects a complex regulatory landscape, including CO2 emissions caps for each state. States may work together or individually to reach emissions targets

• CO2 reductions under the EPA proposal are scheduled to begin in 2021.

• According to the EPA’s reliability assessment included in the proposed rule, these existing generation rules would result in approximately 121 GW of fossil generation retirements by 2020.

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FMDRAT Report

February 26, 2014  

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A Report on  

Assessing the Need for Introducing Demand Response Functions and Entities to the NERC

Reliability Functional Model  

Prepared by: Functional Model Demand Response Advisory Team    

Executive Summary  

The Functional Model Working Group Demand Response Advisory Team (FMDRAT) has completed an assessment of the need to include Demand Response (DR) functions and associated  functional entities either in the NERC Functional Model (FM) or as an Applicable Entity for NERC Reliability Standards. 

 

The FMDRAT assessed a number of key issues related to the role and reliability  impacts of DR in the planning and operation horizons. This assessment  leads to the following key conclusions and recommendations: 

 

1)   DR is generally considered  in BES planning and operations  from the perspective of resource adequacy assessment and operating reserve determination.  Long‐term planners, operational planners and operators do take into account the amount of DR under contractual agreement or participated  in operating reserve market to adjust resource needs to meet forecast system demand and reserve requirements. Since DR itself is not an active facility or component  like a generator,  its “dispatch” action is initiated upon receiving  instructions  from the operating authorities under pre‐ determined system conditions. Compared to sudden  load increase and generator tripping, DR’s spontaneous performance or failure to perform as instructed does not pose adverse reliability  impacts on the BES for which there is no recourse. Providing DR offered by any entities is not materially different than other dispatchable resources and would not impact BES planning and operations. Hence, there is not a need at this time to include DR in the Functional Model to describe  its role in contributing  to BES reliability. 

 

2)   Reliability standards are not required to enforce DR compliance with commercial agreements or obligations.  Imposing reliability standards to force compliance with commercial agreements would be inappropriate, may not achieve the desired outcome, and in fact may discourage entities from participating in DR programs. 

 

3)    The NERC technical committees, including the Operating, Planning, and Critical Infrastructure Committee, continue to monitor DR development and identify if and when DR technology and penetration levels create a unique impact on BES reliability.

FMDRAT Report

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1.0 Introduction  

The Functional Model Working Group Demand Response Advisory Team (FMDRAT) has completed an assessment of the need to include Demand Response  (DR) functions and associated  functional entities either  in the NERC Functional Model (FM) or as an Applicable Entity for NERC Standards. The issues considered by the FMDRAT and the key findings after discussing  these  issues are summarized  in this report for consideration by the Functional Model Working Group (FMWG). 

 

The FMDRAT  is made up of 14 members appointed by the NERC Standards Committee. The FMDRAT’s  roster  is included as Attachment 1. 

 2.0 Background

 

 In 2008, the FMWG set up a small advisory team to assess the need to create a DR function and a DR entity.  That advisory team concluded  that such a function and related functional entity were not justified at that time. The Advisory Team also suggested  that the FMWG reconsider  the issue when developing Functional Model Version 5 (FM V5).  The advisory team recommended  consideration  of assigning such functions and responsibilities  to functions and entities already defined  in the FM. 

 

The FMWG reconsidered  the issue in its development of FM V5, and again concluded  that there was no justification  for defining a DR function and entity  in the FM V5 Model. The NERC Planning Committee at its December 8‐9, 2009, meeting, when approving  the FM V5, requested  the FMWG reassess the need to include a DR Functional Entity  in FM V6. Below  is the excerpt from the Planning Committee’s meeting minutes: 

 

Functional Model Version 5: FMWG Chair Jim Cyrulewski presented an overview of the 

Functional Model, version 5.  On a motion by John Simpson,  the PC approved V5, without 

modification,  the technical content of two documents: Reliability Functional Model, Function 

Definitions and Functional Entities and Reliability Functional Model Technical Document.  

The primary discussion  focused on what was not in version 5: a functional entity (or entities) 

responsible  for demand resources.  Mr. Cyrulewski noted that when the FMWG presents 

version 5 to the Standards Committee  (SC) in January 2010 for approval,  it will be 

recommending  a new subgroup be formed to address the demand resources  function so that it 

can be incorporated  in version 6.  John Simpson suggested  that the PC’s Resource  Issues 

Subcommittee  be involved  in that effort.   

The Standards Committee  in response  to the FMWG’s request approved  the formation of the FMDRAT to address the Planning Committee’s  request.  The FMDRAT was formed  in May 2010, and from September 2010 to February 2011 completed  its assignment  to assess the need for a DR function and entity.  This report presents the FMDRAT’s assessment and recommendations. 

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February 26, 2014  

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3.0 Key Issues Addressed by the FMDRAT   

The FMDRAT began  its tasks by identifying and compiling a list of potential reliability impacts associated with the participation of DR.  The issues were important because the Functional Model  is a general description of the primary reliability  tasks that need to be performed  to ensure reliability of the Bulk Electric System  (BES). 

 Presented below  is a summary of the FMDRAT’s assessment of each of the identified key issues. 

 3.1   Reliability Impact of DR ‐ Does the change in energy use from a DR 

asset or from an aggregation of DR assets create any unique reliability impact? 

 

 Demand Response  (DR)  is a temporary change  in electricity usage by a Demand Resource  in response  to market or reliability conditions.1  Demand Response  is regarded as a “dispatchable”  resource  (as opposed  to energy efficiency, which  is always “on”) whose deployment  is driven by pre‐determined  system conditions or reliability event criteria by an operating entity.  The system operator  typically provides instruction  to the DR provider  for deployment of DR assets.  Additionally, DR providers may self‐schedule DR asset deployment,  as in the case for economic dispatch  in some regions. 

 A DR asset or aggregator  that functions according  to operating conditions as defined by prior agreements poses no impact to reliability because  its impacts are analyzed and assessed  in the Operating Plans of the respective Transmission Operator  (TOP) and Balancing Authority (BA). 

 The TOP and BA plan in advance to meet system  load, including  load that is represented or controlled by DR entities.  TOPs and BAs have knowledge of all relevant conditions and agreements,  and plan operations accordingly  for the load to be served with or without contribution  from DR. 

 To the BA, load  is a composite value (i.e., not locational) and a forecast can be developed  for how much capacity  is required to meet that load.  Contractual arrangements with DR providers are accounted  for in the BA’s operating plans. 

 To  the  TOP,  load  is  locational  and  it  is  based  on  historic  load  bus  values.  The  DR control of  load does not  change  the  location  of  the basic  load;  rather,  the availability of  DR  provides  the  TOP  with  another  option  to  control  congestion  and  to  maintain reliability. 

 From a MW change perspective, DR mis‐performance does have some reliability impact on the BES but such impact is not expected to be at a level that will create an Adverse Reliability Impact for which there is no remedy.  There are mechanisms  in some areas (e.g. in some organized markets) to levy a 

                                                            1 North American Energy Standards Board, Wholesale Electric Quadrant definition, 2010 

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penalty on the Generator Operator  for not meeting  its commitment or requested output, but this is a commercial arrangement which falls outside of the scope of the NERC Functional Model or reliability  standards.  BAs and TOPs are similarly  free to prescribe penalties  for comparable failures of DR.  Such penalty structures are not currently described  in the Functional Model, nor are there reliability  standards developed  to enforce compliance  to such penalties. 

  

Observation 1: DR may be considered a dispatchable resource as compared to energy 

efficiency, which is always “on”. It is generally regarded as a load whose contractual 

arrangement is to be reduced in response to operating instructions or as triggered by 

market mechanism, thus providing the intended reliability benefit to system planners 

and operators. At present, there does not appear to be any adverse reliability impact 

on the BES unique to DR resources where there is no recourse either for the DR’s 

reduction of load as planned or requested, or the DR's failure to reduce load as 

planned or requested. There does not appear to be any DR impact on BES reliability 

that is materially different than that of other dispatchable resources. 

 3.2   Reliance on DR to provide Operating Reserves 

 

 In some organized markets, DR may participate  in the reserve market.   In non‐organized markets, DR may enter  into contractual arrangements with the host utility to provide reserve capability.  The FMDRAT assessed  that the BA was responsible  for ensuring adequate reserves  in the operations  time frame, and the BA was required  to understand  the characteristics of the DR resources  regardless of the market setup, and the BA was required to develop the necessary  recourses  to guard against DR’s failure to perform.  Again, this situation  is no different  than generators not providing operating  reserves.  At present, there are no reliability  standards  that mandate a Generator Operator  to provide the needed reserves as procured or requested by the Balancing Authority. 

 To manage  the potential risk that DR fails to provide the dispatched or self‐scheduled reserve quantity agreed upon, some organized markets apply a discount  factor to the amount of reserves offered by a DR resource, while some organized markets  limit DR participation  to 30‐minute  reserve services.  Still others do not count on the DR to begin with, but as load drops off, the responsible entity backs down the generation loaded  in response  to the activation  in order to maintain adequate operating  reserves. 

 Similar measures were determined by the FMDRAT  to be adopted  in non‐organized markets through contractual arrangements. 

 Observation 2: TOPs or BAs are responsible  for managing  the load and supply 

balance  in their control areas.  Dispatchable DR resources are generally considered 

in resource adequacy and operating  reserve assessments  in the operational planning 

time frame. However,  it does not appear that DR presents any new or unique  risks to 

the BES compared  to any other dispatchable  resource available to the TOP or BA.  All 

responsible entities have measures  in place to guard against the possibility  that any 

dispatchable resource does not fulfill its obligations  to provide the agreed amount of 

reserves.   There are no adverse reliability  impacts on the BES for which there is no 

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February 26, 2014  

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recourse when DR resources do not perform as planned or requested  to provide the 

needed reserve.  3.3   DR resources’ obligations to support resource planning 

  

Many planning entities consider DR in their mid‐term and long‐term  resource planning processes.  Some Planning entities consider DR as a resource to help meet the reserve margin requirement  that  is determined by either the traditional  loss‐of‐load expectation (LOLE) process or by other commonly used methodologies. 

 Projected available DR may be applied as an available  resource to help meet a reserve margin requirement, or applied as an offset to the long‐term  load forecast.  Some planning entities apply a forced outage rate to the DR, similar to dispatchable generators, and simulate DR performance  in LOLE calculations.   In each case, some uncertainty exists around long‐term DR resource availability due to the short term contractual nature of DR assets as compared  to the expected  life of a generation asset.  Some entities conduct more frequent resource adequacy assessments  as the planning horizon approaches  the near‐term.  An additional DR functional entity will not change the current role or responsibility of the planning coordinator or the resource planner. 

 Observation 3: Some entities consider DR in long‐term planning and its treatment 

varies from one entity to another.  However, owing to the long lead time in the 

planning process, there is uncertainty as to whether or not the status of the DR will 

remain unchanged as it approaches  real time.  An additional DR functional entity 

will not change the current role or responsibility of the planning coordinator or the 

resource planner. 

 3.4 Need for reliability standards to enforce compliance with

contractual agreements/obligations  

At present, DR is usually arranged via contractual agreements or market mechanisms such as pricing thresholds,  reserve offerings, or forward capacity auctions.   In these arrangements, penalties are levied  if commercial or contractual obligations are not met.  These mechanisms are similar to generators bidding  into and being dispatched  in an energy market and getting paid the market price or another pre‐determined  price based on the amount of generation provided.   In such cases generators would not be paid (and in some cases assessed with additional penalties)  if they failed to generate at the agreed upon or committed  level.  Given these contractual or commercial payment/penalty mechanisms,  there do not appear to be gaps that would require the development  and enforcement of reliability standards  to achieve the desired DR performance.   Imposing reliability standards  to force compliance  to commercial agreements  is inappropriate, may not actually achieve the desired outcome, and may in fact discourage  load from participating  in DR programs. 

 The FMDRAT  further assessed whether DR is a fundamental  component or product of 

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the BES.   DR can provide some flexibility  in both the long‐term and operational planning  time frames, to the extent that the responsible entities can choose which loads continue  to be supplied.  As such, DR may be considered a derivative product that should continue  to be handled by commercial arrangements,  not reliability standards. 

 Observation  4: Reliability  standards are not required  to enforce DR to comply with 

commercial agreements or obligations.   There are little or no material reliability 

impacts  if DR fails to perform as agreed to or as requested  for which there is no 

recourse  (from Observations  1 and 2, above).      

3.5 DR Ownership and Operations – roles and relationships with others

 

In consideration of the possibility of introducing DR functions and entities to the Functional Model, the FMDRAT developed a draft set of tasks describing a Demand Response Ownership  function and the relationship between  the DR Owner and others.  The FMDRAT also developed a draft set of tasks for a Demand Response Operations function and the relationship between  the DR Operator and others.  The objective of this exercise was to compare  the primary  functions between  the two types of resource providers. 

 The FMDRAT concluded  that a parallel to the tasks and relationships developed  for the Generator Ownership and Generator Operations and their respective  functional entities could be drawn for DR.  The draft  list of tasks and relationships  for the DR Ownership and Operation  functions and for the DR Owner and DR Operator  is provided  in Appendix A for information only.  The FMDRAT did not finalize or accept the list provided  in Appendix A in light of the FMDRAT’s assessment  that introducing DR functions and associated entities to the Functional  is not required at this time.  The list is provided herein only as a matter of record for future reference and is not part of the FMDRAT’s  recommendation  at this time. 

 3.6 Conclusion of Majority Position

 

 A near‐unanimous  consensus of the FMDRAT agreed with the analysis made for each of the key issues and the corresponding  assessments detailed  in this section of this report.  The same majority agreed that that there  is not a demonstrated  need to introduce DR functions and entities to the Functional Model at this time. 

  

4.0 Minority Position   

The key counter‐arguments center on the comparable obligations between DR Owner/Operator  and Generator Owner/Operator  (GO/GOP).  At present, there are a number of reliability  standards  that apply to GOs and GOPs.  DR providers may offer their product into energy or ancillary services markets and receive compensation  for successful performance.  They should bear the same obligations as their generation counterparts  and hence should have a comparable  set of reliability  standards  imposed on the DR Owners and Operators.  However,  if DR is not introduced  to the Functional 

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Model and if DR were required to meet the same reliability  standards,  then a number of standards currently applied to GO and GOP, as listed  in Appendix B, should be removed  from the NERC reliability standards. 

 The FMDRAT assessed these minority views and arrived at the following assessments: 

 Apart from the fact that both generation and DR provide resources  to the BES, there are some fundamental differences between  them.  Generators are a fundamental part of the integrated power system; they provide primary products  for BES reliability – energy and ancillary services. Generators do change output  in reaction to system changes and their changes are largely governed by their inherent physical characteristics  and auxiliary device settings.  These characteristics  and settings need to be verified and modeled, and the simulated generator performance needs to be assessed against specific standards criteria to ensure that any adverse effects are self‐contained  or isolated without propagating  to other parts of the BES which could result  in uncontrolled or cascade tripping.   It is largely on this basis, to ensure acceptable generator performance,  that reliability  standards are developed and imposed on GOs and GOPs. 2 

 DR changes  in load are inherently  independent of system changes.  Therefore, reliability standards are not needed to ensure acceptable performance  as in the case of their generator counterpart. Commercial arrangements  and compensation/penalty mechanisms are in place to govern DR contractual obligations and are sufficient  to drive the desired behavior when DR is called upon to act. Imposing reliability  standards to enforce such behavior  is inappropriate  and unnecessary  and may not actually achieve the desired outcome.  Observation 5: DR is a derivative or supplementary  part or product of the power 

system, with specific rules for participation  in BES operations. DR must be verified 

and assessed in planning models, similar to a generator. DR augments the capabilities 

of the BES, thus increasing the effective utilization of the BES, but does not increase 

the total installed capacity of the system, unlike its generator counterpart.  

As to the request to remove the listed reliability  standards  for the GOs and GOPs, the FMDRAT did not agree to a position since such a determination was not part of its charter. 

 5.0 Observations and Recommendations

  

The FMDRAT assessed a number of key issues related to the role and reliability impacts of DR in the planning and operation horizons. The assessment  leads to the following observations:  1. DR is generally considered  in BES planning and operations  from the perspective of 

                                                            2 Reliability Standard MOD‐025 requires the verification of the real and reactive power capability of generators to “ensure that 

accurate information is available for planning models used to assess Bulk Electric System (BES) reliability”.   

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resource adequacy assessment and operating  reserve determination.  Long‐term planners, operational planners and operators do take into account the amount of DR under contractual agreement or participated  in operating  reserve market to adjust resource needs to meet forecast system demand and reserve requirements. At present, there does not appear to be any evidence suggesting a potential adverse reliability impact on the BES unique to DR. Providing DR offered by any entities is not materially different than other dispatchable resources and would not impact BES planning and operations.  

2. TOPs or BAs are responsible for managing the load and supply balance in their areas.  Dispatchable DR resources are generally considered in resource adequacy and operating reserve assessments in the operational planning time frame. However, it does not appear that DR presents any new or different risks to the BES compared to the longstanding load management programs administered by existing Registered Entities and any other dispatchable resource available to the TOP or BA. 

 3. For long‐term planning, most entities  include contributions  from DR to some 

extent. Uncertainties  associated with DR’s long‐term commitment  to remain “dispatchable”  are typically addressed by applying a discount  factor or probability analysis to DR’s availability  in resource adequacy assessments. 

 4. Reliability  standards are not required to enforce DR compliance with commercial 

agreements or obligations.   Imposing  reliability standards  to force compliance with commercial agreements would be inappropriate, may not achieve the desired outcome, and in fact may discourage entities  from participating  in DR programs. 

 5. DR is a component and a derivative product of the power system DR augments the 

capabilities of the BES, thus increasing the effective utilization of the BES, but does not increase the total installed capacity of the system. DR does not move spontaneously  or in response  to system changes  for which reliability  standards might be needed to ensure acceptable performance.    

 Observations  (1) through (3) suggest that there  is no need at this time to include a  DR entity in the Functional Model to describe  its role in contributing  to BES reliability. While DR and DR entities participate in electricity markets and are dispatched by system operators—hence, contributing to the reliable operation of the BES—observations (4) and (5) suggest that there is no urgency or need to develop reliability  standards  to ensure compliance with commercial agreements or obligations  in place to drive the desired outcome.  It is on the above basis that the FMDRAT  recommends: 

 1. DR functions and their associated  functional entities not be defined and 

introduced  to the Functional Model at this time.  

 2.   The NERC technical committees, including the Operating, Planning, and Critical 

Infrastructure Committee, continue to monitor DR development and identify if 

and when DR technology and penetration levels create a unique impact on BES 

reliability. 

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Attachment 1  

The Functional Model Demand Response Advisory Team       

Name  Company   Ben Li (Chair/Facilitator)  Ben Li Associates 

 1  Albert DiCaprio  PJM 

 2  Phil Davis  Schneider Electric 

 3  Stephen C. Knapp  Constellation  Energy Commodities Group,  Inc. 

 4  John D. Varnell  Tenaska Power Services Co 

 5  Donna Pratt  NYISO 

 6  Ken Clark (did not participate) Consert,  Inc. 

 7  Aaron Breidenbaugh  EnerNOC 

 8  Wayne Van Liere  EON US 

 9  Ulric Kwan  Pacific Gas & Electric Company 

 10  Eric Winkler, Ph.D.  ISO New England 

 11  Paul Wattles  Electric Reliability Council of Texas (ERCOT  ISO) 

 12  John Simpson  RRI Energy 

 13  Andy Satchwell  Lawrence Berkeley National Lab 

 14  Tony Jankowski  We Energy 

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Appendix A  

DRAFT List of Perceived Tasks and Relationships for  

Demand Response Functions and Entities  

(The list is provided for information and for future reference only; it is not part of the FMDRAT’s recommendation at this time.)

   

Generation  Demand Response  

Generator Ownership Function    Tasks 

Demand Response Ownership Function  

Tasks    

1.  Establish generating  facilities ratings,  limits, and operating  requirements. 

 

2.  Design and authorize maintenance  of generation plant protective  relaying systems, protective  relaying systems on the transmission  lines connecting  the generation plant to the transmission  system, and Special Protection Systems. 

 

3.  Maintains owned generating  facilities.  

4.  Provide verified generating  facility performance  characteristics  / data. 

   Functional Entity – Generator Owner 

 The functional entity that owns and maintains generating units. 

 

Relationships with Others  

1.  Provides generator  information  to the Transmission  Operator, Reliability Coordinator,  Balancing Authority, Transmission  Planner, and Resource Planner. 

 

2.  Provides unit maintenance  schedules and unit retirement plans to the Transmission Operator, Balancing Authority, Transmission Planner, and Resource Planner. 

1.  Establish demand  response  facility ratings, limits, and operating  requirements. 

 

2.  Design and authorize maintenance  of demand  response  facilities and associated control devices. 

    

3.  Maintains owned demand  response  facilities.  

4.  Provide verified demand response  facility performance  characteristics  / data. 

   Functional Entity – Demand Response Owner  The functional entity that owns and maintains demand  response  facilities.  

Relationships with Others  

1.  Provides demand  response  information  to the Transmission Operator, Reliability Coordinator, Balancing Authority, Transmission  Planner, and Resource Planner. 

 

2.  Provides demand  response  facility maintenance  schedules  to the Transmission Operator, Balancing Authority, Transmission Planner, and Resource Planner. 

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 3.  Develops an interconnection  agreement with 

Transmission  Owner on a facility basis.  

4.  Receives approval or denial of transmission service request  from Transmission  Service Provider. 

 

5.   Provides  reliability  related  services  to Purchasing‐Selling   Entity  pursuant  to agreement. 

 

6.  Reports the annual maintenance  plan to the Reliability Coordinator, Balancing Authority and Transmission Operator. 

 

7.  Revises the generation maintenance  plans as requested by the Reliability Coordinator. 

   Function – Generator Operation 

   Tasks 

 1.  Formulate daily generation plan. 

  

2.  Report operating and availability  status of units and related equipment,  such as automatic  voltage regulators. 

  

3.  Operate generators  to provide  real and reactive power or reliability‐related  services per contracts or arrangements. 

       

4.  Monitor  the status of generating  facilities.   

5.  Support  Interconnection  frequency.      Functional Entity – Generator Operator 

 The functional entity that operates generating 

  

3.  Reports the annual maintenance  plan to the Reliability Coordinator, Balancing Authority and Transmission Operator. 

 

4.  Revises the demand  resource  facility maintenance  plans as requested by the Reliability Coordinator. 

             Function – Demand Response Operation    Tasks  

1.  Formulate daily demand response  resource plan. 

  

2.   Report operating  and availability  status of demand  response  related  equipment  and control devices. 

  

3.  Operate demand  response  facility control devices or otherwise  implement demand reduction or demand  increase  in response  to instructions  or according  to contract arrangements. 

  

4.  Monitor  the status of demand  response facilities. 

     Functional Entity – Demand Resource Operator  The functional entity that operates demand 

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 unit(s) and performs  the functions of supplying energy and reliability  related services. 

      Relationship with Others 

 

Ahead of Time    

1.   Operate generators  to provide  real and reactive power or reliability‐related  services per contracts or arrangements. 

  

2.   Provides operating and availability  status of generating units to Balancing Authority and Transmission  Operators  for reliability analysis. 

     

3.   Reports status of automatic voltage or frequency  regulating equipment  to Transmission  Operators. 

  

4.   Provides operational data to Reliability Coordinator. 

  

5.   Receives  reliability analyses  from Reliability Coordinator. 

  

6.   Receives notice from Purchasing‐Selling Entity  if Arranged  Interchange  approved or denied. 

  

7.   Receives  reliability alerts from Reliability Coordinator. 

  

8.   Receives notification of transmission  system problems  from Transmission Operators. 

response  facilities and performs  the functions of curtailing or increasing demand  in response  to instructions or in accordance with contractual arrangement.    Relationship with Others  

Ahead of Time    

1.   Implement demand  reduction or consumption  increase  in response  to instructions  or according  to contract arrangements. 

  

2.  Provides operating and availability  status of demand  response  to Balancing Authority, Transmission  Operator and Reliability Coordinator  for reliability analysis. 

  

3.  Provides operational data to Reliability Coordinator. 

  

4.  Receives  reliability analyses  from Reliability Coordinator. 

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 Real Time 

    

9.   Provides Real‐time operating  information  to the Transmission Operators and the required Balancing Authority. 

  

10.   Adjusts real and reactive power as directed by the Balancing Authority and Transmission Operators. 

Real Time     

5.   Provides Real‐time operating  information to the Transmission Operators and the required Balancing Authority. 

  

6.   Adjusts demand  in response  to instructions or according  to contract agreements. 

  Post Real Time    

7.   Provide operating  information  required Balancing Authority  for settlement purposes 

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 Appendix B

Minority Views

List of NERC Reliability Standards that should be removed if DR is not Assigned the Same Obligations as GO/GOP

    

On the basis of comparable  treatment of “supply”  resources used to balance  load and supply  in both the planning horizon and the real time operating horizon, a BA may choose between DR and traditional generation  resources  to meet the load obligations on the grid.  As increased use is made of DR to meet certain  load requirements,  lower commitments  are made of traditional generation supply.  This is fine as long as the DR “supply” shows up when the BA calls on it. 

 

Penalizing a DR that doesn’t perform as agreed to or requested by penalize  it via market mechanism is not acceptable  from a reliability perspective.   If sufficient DR doesn’t show up and traditional generation  resources have not been committed and cannot get on‐line  in time to meet the aggregate demand,  then some  load will have to be curtailed against  its desires  in order to maintain BES reliability. 

 

If it is indeed our position that whether or not DR responds when called upon that it does not impact reliability,  then the following changes ought to be made to the existing reliability standards: 

 a)   CIP Standards:  remove Generator Operators  from these standards.   If it is not 

important  for supply to respond when called on then we don’t need these standards applied to any supply resources. 

 

b)   COM‐002:  remove Generator Operators  from the Applicability.   If DR that is used as a supply  resource  doesn’t  need  to  respond,  then  GOPs  do  not  need  to  have communications with the RCs for them to respond either. 

 

c)   IRO‐001,‐004,‐005,‐010: remove Generator Owners and Generator Operators  from these standards.   If it is not important  that DR used as a supply resource responds  to the directives of the RC, then it should not be important  that GO/GOPs respond either.  They also should not have to provide  information on their capabilities  in Day Ahead or Current Day time frames. There also shouldn’t be a need to coordinate any maintenance outages with the RC.  After all, if a DR owner or operator can just sit out for a day, then a generator should be able to do the same thing. 

 

d)   MOD‐024,‐025:  delete  these standards.   If  it  is not  important  to know or qualify  the capacity  of  a  DR  resource,  then  we  should  not  have  to  qualify  the  capacity  of  a traditional generation resource either. 

 

e)   PRC‐001,‐005:  remove  Generator  Operator  and  Generator  Owner  from  these standards.   If it is not  important  to reliability  that DR operate properly when called on, then  we  should  not  have  to  coordinate  protective  relays  or  do  protection  system maintenance  for traditional generation  resources either. 

 

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f)   TOP‐001,‐002,‐003,‐006: remove Generator Operators  from these standards.   If it is not important  that DR which  is being counted on by the BA to respond to directives from the RC, then we shouldn’t need to have GOPs respond either.  There shouldn’t be a need to coordinate normal operations planning with the RC, or coordinate outage schedules with the RC, or provide notice to the RC of any resources  that are available, or not available  for dispatch. 

  

As more and more DR is included  in the dispatch stack and the planning and operating horizon, fewer real generation  resources are included  to meet the aggregate  load obligations on the grid.  It is certainly  important  to the BA and the RC that the real generation  resources can be counted on to perform when called.  As DR replaces those real generation  resources,  it should be important  that they respond as well.  Comparable reliability  standard requirements  should be in place for DR resources as are in place for Generator Owners and Operators. 

July 25, 2014 Mr. Ben Crisp Chair, NERC Planning Committee SERC Reliability Corporation 2815 Coliseum Centre Drive, Suite 500 Charlotte, NC 28217 Dear Mr. Crisp: On April 9, 2014, the Standards Committee approved the attached report prepared by the Functional Model Working Group Demand Response Advisory Team (FMDRAT). The report assessed the need to include Demand Response (DR) functions and associated functional entities either in the NERC Functional Model or as an Applicable Entity in certain NERC Standards. Specifically, the report set forth the following key conclusions and recommendations:

1. DR is generally considered in Bulk Electric System (BES) planning and operations from the perspective of resource adequacy assessment and operating reserve determination. Long‐term planners, operational planners, and operators do take into account the amount of DR under contractual agreement or participate in the operating reserve market to adjust resource needs to meet forecast system demand and reserve requirements. Since DR itself is not an active facility or component like a generator, its “dispatch” action is initiated upon receiving instructions from the operating authorities under predetermined system conditions. Compared to sudden load increase and generator tripping, DR’s spontaneous performance or failure to perform as instructed does not pose adverse reliability impacts on the BES for which there is no recourse. Providing DR offered by any entities is not materially different than other dispatchable resources and would not impact BES planning and operations. Hence, there is not a need at this time to include DR in the Functional Model to describe its role in contributing to BES reliability.

2. Reliability Standards are not required to enforce DR compliance with commercial agreements or obligations. Imposing reliability standards to force compliance with commercial agreements would be inappropriate, may not achieve the desired outcome, and in fact may discourage entities from participating in DR programs.

3. The NERC technical committees, including the Operating, Planning, and Critical Infrastructure Committee, continue to monitor DR development and identify if and when DR technology and penetration levels create a unique impact on BES reliability.

3353 Peachtree Road NE Suite 600, North Tower

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Page 2 of 2 SC Letter to PC Chair

It is my understanding that the FMDRAT worked with NERC standing committees (Operating and Planning Committees) to assure concurrence with the above conclusions. Given that one of the key recommendations of the report includes a monitoring role, I transit this report and encourage your Committees to continue to monitor DR functions. If there comes a time you believe the Standards Committee or the FMDRAT should reconsider or re‐assess any of the recommendations and findings in the report, please let me know. Sincerely, Brian J. Murphy Chair, NERC Standards Committee cc: Ms. Valerie Agnew, NERC Director of Standards Mr. Scott Miller, Vice Chair, NERC Standards Committee Mr. Jim Cyrulewski, Chair, NERC Functional Model Working Group Mr. Jerry Rust, Vice Chair, NERC Functional Model Working group Mrs. Soo Jin Kim, Secretary, NERC Standards Committee Mr. John Moura, Secretary, NERC Planning Committee

SCOPE Spare Equipment Working Group (SEWG) Purpose The purpose of the Spare Equipment Working Group (SEDWG) is to review the industry’s posture on long-lead time electric transmission system equipment, manage the NERC Spare Equipment Database (SED), and act as conduit for information exchange in this area to ensure reliability and resiliency of the Bulk Electric System (BES).

Activities To accomplish its purpose, the SEDWG will perform the following activities:

1. Define the long-lead time spares of generation and transmission equipment deemed critical by the NERC Planning Committee (PC) to the operation of the Bulk Electric System (BES);

2. Provide industry assessment of spare equipment programs and the risk to BES reliability; 3. Provide input on industry practices and programs to minimize impact from high-impact low

frequency event that could affect the availability of long lead-time transmission equipment; 4. Participate in NERC exercises such as GridEx and industry exercises, as needed; 5. Manage NERC SED and the SED Data Reporting Instructions; 6. Develop periodic summaries and analyses of the industries participation and use of SED; and 7. Coordinate with the NERC Critical Infrastructure Protection Committee (CIPC), Standards

Committee (SC), Compliance and Certification Committee (CCC), and Operating Committee (OC), and the Reliability Issues Steering Committee (RISC).

Annual Deliverables The SEWG will deliver the following reports:

1. Periodic summaries and analyses of the industry’s posture on spare equipment programs; and

2. Manage NERC’s SED and offer reports to the NERC PC.

Deleted: Database

Deleted: D

Deleted: Database

Deleted: participation and use of the SED and determine if other

Deleted:

Deleted: should be included. SED is a voluntary program open for participation by organizations registered with NERC as Transmission Owners or Generation Owners functional entities. All participants will be signatories to the disclosure requirements as outlined in the SED Mutual Confidentiality Agreement.

Deleted: Performance Analysis Subcommittee (PAS) and

Commented [PK1]: Originally, the NERC Spare Equipment Database Task Force reported directly to the PC. This was changed when the SEDWG was created because the group was expected to provide data/analysis to the NERC PAS. Since the suggested scope is far wider than just the database, it is recommended that the SEWG report directly to the PC again. Also, with the heightened awareness of spare equipment in the industry, this seems like the appropriate change.

Deleted: Power

Deleted: P

Deleted: oversight and

Deleted: the management of a single on-line process for collecting SED defined data and information;

Deleted: the logistical use of the SED during a

Deleted: Conduct quality control processes, data reviews and analysis (including exercises) to ensure accuracy and effectiveness of SED;

Deleted: Review additions and changes to the information collected by

Deleted: SED

Deleted: for review by PAS (reporting periods to be determined by PAS)

Deleted: task forces and working groups supporting the NERC Electricity Sub-Sector Coordinating Council (ESCC) Critical Infrastructure Strategic Roadmap.

Deleted: D

Deleted: participation and use of SED for review by PAS and the PC; and

Deleted: Provide an SED summary report for the PAS’s annual Performance Analysis Report.

Deleted: Database

Membership The structure of the SEWG voting membership shall include the following:

• Chair and Vice Chair

• Four representatives from organizations registered with NERC as TO functional entities (One each from the membership1 of the American Public Power Association, Canadian Electricity Association, Edison Electric Institute, and National Rural Electric Cooperative Association.)

• Four representatives from organizations registered with NERC as GO functional entities (One each from the membership2 of the American Public Power Association, Canadian Electricity Association, Edison Electric Institute, and National Rural Electric Cooperative Association.)

• Three member-at-large3 functional entities. The working group members and the chair are appointed by the chair of the NERC Planning Committee for a single, two-year term. The NERC Planning Committee will also appoint a vice chair from the membership and the appointee should be available to succeed to the chair.

The SEWG non-voting liaisons/observers participants may include the following:

• Government or regulatory entities

• Equipment manufacturers, repairers, and suppliers

• Industry equipment experts

• Interested TO and GO representatives

• Interested public

• NERC staff coordinator(s)

Order of Business In general, the desired, normal tone of SEWG business is to strive for constructive technically sound recommendations and solutions. On occasions where that desired outcome cannot be achieved, the SEWG will defer to a vote by the Planning Committee to resolve the gaps. Minority opinions of the SEWG should be documented as desired by the minority and forwarded to the Planning Committee for consideration.

1 Employees and contractors of any Association may participate in SEWG as non-voting liaisons/observers. Should there not be a registered functional entity assigned as the SEWG member representing that Association in a particular segment, on a temporary basis the liaison/observer may be designated by the SEWG Chair, or Vice Chair, to fill that vacant segment. The Association representative shall be permitted to vote as an SEWG member while temporarily assigned as an SEWG member. Should the vacant Association position then be filled by a registered functional entity representative, the Association representatives’ temporary assignment shall immediately revert back to non-voting liaison/observer status.

2 See Footnote 1 3 One each from the membership of the North American Transmission Forum, North American Generation Forum, and the

Performance Analysis Subcommittee.

Deleted: D

Deleted: All voting members of SEDWG shall be from functional entities who have signed the SED Mutual Confidentiality Agreement.

Deleted: D

Deleted: The SEDWG non-voting liaisons/observers participants will not be required to sign the SED Mutual Confidentiality Agreement. ¶

Deleted: D

Deleted: the

Deleted: D

Deleted: D

Deleted: D

Deleted: D

Deleted: D

Deleted: D

Deleted: D

Spare Equipment Working Group Scope 2

Deleted: Database

Reporting The SEWG reports to the Planning Committee (PC). Reports and recommendations developed by the SEWG will require approval by the PC. Meetings One face-to-face meeting per year and one conference call per quarter are anticipated. Meetings will be held in public, but there may be times when attendance at the meetings will be limited to the SEWG voting members to allow discussion of confidential information. The SEWG voting members may also invite guests to provide input on specific areas.

Approved by the NERC Planning Committee:

Deleted: DS

Deleted: Performance Analysis Subcommittee (PAS)

Deleted: D

Deleted: PAS and

Deleted: Planning Committee

Deleted: month

Deleted: However, during the initial year of operation of SED (2012), SED may meet or hold conference calls as necessary.

Deleted: D

Deleted: SED

Deleted: D

Deleted: June 19, 2012

Spare Equipment Working Group Scope 3

Draft Scope Spare Equipment Working Group (SEWG) Purpose The purpose of the Spare Equipment Working Group (SEWG) is to review the industry’s posture on long-lead time electric transmission system equipment, manage the NERC Spare Equipment Database (SED), and act as conduit for information exchange in this area to ensure reliability and resiliency of the Bulk Electric System (BES). Activities To accomplish its purpose, the SEDWG will perform the following activities:

1. Define the long-lead time spares of generation and transmission equipment deemed critical by the NERC Planning Committee (PC) to the operation of the Bulk Electric System (BES);

2. Provide industry assessment of spare equipment programs and the risk to BES reliability;

3. Provide input on industry practices and programs to minimize impact from high-impact low frequency event that could affect the availability of long lead-time transmission equipment;

4. Participate in NERC exercises such as GridEx and industry exercises, as needed;

5. Manage NERC SED and the SED Data Reporting Instructions;

6. Develop periodic summaries and analyses of the industries participation and use of SED;

7. Coordinate with the NERC Critical Infrastructure Protection Committee (CIPC), Standards Committee (SC), Compliance and Certification Committee (CCC), and Operating Committee (OC), and the Reliability Issues Steering Committee (RISC).

Annual Deliverables The SEWG will deliver the following reports:

1. Periodic summaries and analyses of the industry’s posture on spare equipment programs; and

2. Manage NERC’s SED and offer reports to the NERC PC.

Membership The structure of the SEWG voting membership shall include the following:

• Chair and Vice Chair

• Four representatives from organizations registered with NERC as TO functional entities (One each from the membership1 of the American Public Power Association, Canadian Electricity Association, Edison Electric Institute, and National Rural Electric Cooperative Association.)

• Four representatives from organizations registered with NERC as GO functional entities (One each from the membership2 of the American Public Power Association, Canadian Electricity Association, Edison Electric Institute, and National Rural Electric Cooperative Association.)

• Three member-at-large3 functional entities.

The working group members and the chair are appointed by the chair of the NERC Planning Committee for a single, two-year term. The NERC Planning Committee will also appoint a vice chair from the membership and the appointee should be available to succeed to the chair. The SEWG non-voting liaisons/observers participants may include the following:

• Government or regulatory entities

• Equipment manufacturers, repairers, and suppliers

• Industry equipment experts

• Interested TO and GO representatives

• Interested public

• NERC staff coordinator(s)

Order of Business In general, the desired, normal tone of SEWG business is to strive for constructive technically sound recommendations and solutions. On occasions where that desired outcome cannot be achieved, the SEWG will defer to a vote by the Planning Committee to resolve the gaps. Minority opinions of the SEWG should be documented as desired by the minority and forwarded to the Planning Committee for consideration.

1 Employees and contractors of any Association may participate in SEWG as non-voting liaisons/observers. Should there not be a registered functional entity assigned as the SEWG member representing that Association in a particular segment, on a temporary basis the liaison/observer may be designated by the SEWG Chair, or Vice Chair, to fill that vacant segment. The Association representative shall be permitted to vote as an SEWG member while temporarily assigned as an SEWG member. Should the vacant Association position then be filled by a registered functional entity representative, the Association representatives’ temporary assignment shall immediately revert back to non-voting liaison/observer status.

2 See Footnote 1 3 One each from the membership of the North American Transmission Forum, North American Generation Forum, and the Performance

Analysis Subcommittee.

Reporting The SEWG reports to the Planning Committee (PC). Reports and recommendations developed by the SEWG will require approval by the PC. Meetings One face-to-face meeting per year and one conference call per quarter are anticipated. Meetings will be held in public, but there may be times when attendance at the meetings will be limited to the SEWG voting members to allow discussion of confidential information. The SEWG voting members may also invite guests to provide input on specific areas.

Approved by the NERC Planning Committee:

Document Title 3

DRAFT - NERC Planning Committee Work Plan Last Updated: September 3, 2014

1. Tasks Requiring Review, Assignment, and Prioritization (PC ExCom)

Task Formal Request Status PC Approval/

Endorsement RISC Triage

2. Action Items from Previous Meetings

Task ID Task Name Lead Person/Group

Meeting Date Status Due

Date

3. Planning Committee Executive Committee (John Moura)

Task Frequency Status PC Approval/ Endorsement

PC Subcommittee Prioritization Monthly Review at May 2014 PC ExCom N/A

4. Subcommittee Project Queues

4.1 Reliability Assessment Subcommittee (John Moura) Task Frequency PC Approval/

Endorsement 2014 Long-Term Reliability Assessment Annually October 2014 –

Conference Call 2014/2015 Winter Reliability Assessment Annually November 2014 –

Conference Call

4.2 Performance Analysis Subcommittee (Howard Gugel) Task Frequency PC Approval/

Endorsement Adequate Level of Reliability Metric Development / Review Annually December 2014

4.3 System Analysis and Modeling Subcommittee (Bob Cummings/Neil Burbure/Eric Allen) Task Frequency PC Approval/

Endorsement

Node-Breaker Representations in Off-line and Real-time Study Models (MWG) Ongoing

Approved by PC December 10, 2013 MWG to complete

Implementation Plan by December 2020

Standardized Component Models (MWG) Ongoing

Approved by PC September 17, 2013 MWG to complete

Implementation Plan by June 2015

SW Outage Recommendation 16: Consistency in model parameters (Eliminate Discrepancies Between RTCA and Planning Models)

Ongoing

Approved by PC September 17, 2013 MWG to complete

Implementation Plan by December 2015

WECC Rec NERC3: Parameters for Simulations (SAMS/MWG) Ongoing

Approved by PC September 17, 2013

SAMS/MWG to monitor Standards

efforts underway to satisfy

recommendation

WECC Rec NERC10 & SW Outage Recommendation 21: Review Generator Control Issues and Acceleration Control Function (MWG with SPCS support)

Once Q4 2015

SW Outage Recommendation 10: Benchmarking Dynamic models (MWG) Ongoing Ongoing

SW Outage Rec 27: Angular Separation (coordination with SMS) Once TBD

NERC Planning Committee Work Plan 2

Model Validation Field Trial Ongoing Ongoing

Load Dynamics (FIDVR Project) Ongoing

Workshop – Q2 2015

Ongoing

Composite Model use in Eastern and Texas Interconnections Multi-year 2016 Target Eastern Interconnection FR capable powerflow and dynamics models Annual Q3 2014

IFRO Dynamics Testing - BAL-003-1 Effort Annual November 2014

Distributed Resources (IEEE 1547 Revisions) – Technical Support Ongoing Ongoing

SPS Standard Development Technical Support (Project 2010-05.2) Ongoing Ongoing

Technical Support of modeling issues monitored by NERC Reliability Issues Steering Committee (RISC) Ongoing Ongoing

4.4 System Protection and Control Subcommittee (Phil Tatro) Task Frequency PC Approval/

Endorsement

SC RfR: Project 2009-07 Reliability of Protection System-Order 754 Once

December 2014 Approval,

Present report in September 2014

SW Outage Rec 21: Acceleration Control Function (possible support to SAMS) Once Q4 2015

Implement IEEE recommendations to change the Power Plant and Transmission System Protection Coordination document Once Approval in

December 2014 Develop a report on generating plant unit auxiliary transformer (UAT) protection to assess whether a reliability risk exists if UAT low-voltage side protection is not included in PRC-025.

Once TBD

4.5 Synchronized Measurement Subcommittee (Bob Cummings)

Task Frequency PC Approval/ Endorsement

SW Outage Rec 27: Angular Separation (coordination with SAMS and JSIS) Once TBD

5. Task Force / Working Group Project Queues

5.1 Integrating Variable Generation Task Force (John Moura) Task PC Approval/

Endorsement Task 3.1: IVGTF Final Report and September 2014

5.2 Geomagnetic Disturbance Task Force (Noha Abdel-Karim) Task PC Approval/

Endorsement Equipment Model

• Initial models December 2014

• Improved Models December 2015 Q4 2014

Final Report on GMD Planning and Planning Studies Q4 2014

NERC Planning Committee Work Plan 3

5.3 Smart Grid Task Force – (John Moura) (All SGTF activity is being held until 2015) Task PC Approval/

Endorsement Task 1: Integration of smart grid devices and systems onto the bulk power system requires development of new planning and operating tools, models, and analysis techniques

2015 Restart of Work

Task 2: Integration of smart grid devices/systems will change the character of the distribution system 2015 Restart of Work

Task 3: Engage Standard Development Organizations in the U.S. and Canada to increase coordination and harmonization in standard development 2015 Restart of Work

Task 4: Develop risk metrics that measure current and future system physical and cyber vulnerabilities from smart grid integration 2015 Restart of Work

5.4 AC Substation Equipment Task Force (Naved Khan)

Task PC Approval/ Endorsement

Root Cause Analysis of AC Substation Equipment Failures – Final Report June 2014 Status

Report, December 2014

5.5 Essential Reliability Services Task Force (Pooja Shah) Task PC Approval/

Endorsement

Technical Reference/Whitepaper

March 2014 – Draft Version Submitted to

the TF August 2014 – To be Completed by end of

August Special Reliability Assessment December 2014

5.6 GADSTF – (Elsa Prince) Task PC Approval/

Endorsement GADS Wind White Paper December 2014

NERC Planning Committee Work Plan 4

6. Completed Tasks – 2014 Task Date PC Approval

Finalized PC input for SC/FMWG/FMDRAT report on Demand Response Once Completed February 14, 2014

PRC-005 drafting team guidance on the basis for the 10 mile exclusion for determining which reclosing relays must be added to the standard. (tentative)

Once Completed February 12, 2014

IVGTF Task 1.6: Probabilistic Methods for Variable Generation March 2014 Approved - Completed 2014 Summer Reliability Assessment Annually Completed May 2014 State of Reliability Report Annually Completed May 2014

Seasonal Assessments and Modeling of Sub-100 kV Elements (Southwest Outage Recommendations 5, 6, 7 and NERC2) (MWG) Once

Approved – Completed June 11, 2014

SW Outage Recommendation 9: Procedures for near- and long-term planning studies (SAMS) Once

Approved – Completed June 11, 2014

FAC-001 & FAC-002 5-year review Technical Support (SAMS) Ongoing Completed upon BOT

approval of Standards – August 2014

Monitoring MOD B effort – MOD-032 and MOD-033 Standard Drafting Team (Project 2010-03) (SAMS) Ongoing

Completed upon FERC approval of Standards –

May 2014