Agenda Operating and Planning Committee Joint Session WebEx and Conference Call

Transcription

1 Agenda Operating and Planning Committee Joint Session WebEx and Conference Call July 20, a.m. noon EDT See Agenda Item 1.a for WebEx and conference call information 1. Administrative *a. WebEx and conference call information b. Welcome and introductions - Tom Burgess, PC Chair c. Conference call procedures conference call operator *d. NERC Antitrust Compliance Guidelines John Seelke *e. Operating Committee roster *f. Planning Committee roster roll-call (John Seelke) to determine quorum 2. Reliability Metrics Working Group Report (RMWG) Committee Action *a. The RMWG s Revised Metrics Herb Schrayshuen, RMWG chair *b Comments on the RMWG s May 28, 2009 report and the RMWG s responses Herb Schrayshuen, RMWG chair Presentations will be posted by 5:00 p.m. EDT on July 15, 2009 at: OC: Provide the PC with its recommendations on the RMWG s revised metrics, including the subset of metrics for the 2009 LTRA PC: Approve metrics, including a subset for the 2009 LTRA OC: Provide feedback PC: Provide feedback *Background material included Village Blvd. Princeton, NJ

2 Agenda Item 1.a Joint Operating and Planning Committee WebEx Meeting July 20, 2009 WebEx and Conference Call Information WebEx Information Topic: Operating Committee and Planning Committee Joint Session Meeting Number: Meeting Password: rmwg Conference Call Information Dial-in Pass Code

3 Agenda Item 1.d Joint Operating and Planning Committee WebEx Meeting July 20, 2009 NERC 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. 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 Approved by NERC Board of Trustees, June 14, 2002 Technical revisions, May 13,

4 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 and Bylaws are followed in conducting NERC business. Other NERC procedures that may be applicable to a particular NERC activity include the following: Reliability Standards Process Manual Organization and Procedures Manual for the NERC Standing Committees System Operator Certification Program 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. Any other matters that do not clearly fall within these guidelines should be reviewed with NERC s General Counsel before being discussed. Approved by Board of Trustees: June 14, 2002 Technical revisions: May 13, 2005 Approved by NERC Board of Trustees, June 14, 2002 Technical revisions, May 13,

5 Agenda Item 1.e Joint Operating and Planning Committee WebEx Meeting July 20, 2009 Operating Committee Chairman J.S. Holeman Director, System Operations Duke Energy 526 South Church Street EC02B Charlotte, North Carolina (704) (704) Fx duke-energy.com Vice Chairman Tom Bowe Executive Director Reliability Integration PJM Interconnection, L.L.C. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, Pennsylvania (610) (610) Fx Secretary Doug Newbauer Manager of Alerts North American Electric Reliability Corporation Village Boulevard Princeton, New Jersey (609) (609) Fx nerc.net Cooperative Chris Bolick Manager, System Operations Associated Electric Cooperative, Inc S. Golden Springfield, Missouri (417) (417) Fx Cooperative Shane Sanders Manager of System Operations Southwest Transmission Cooperative, Inc., (520) swtransco.coop Investor Owned Utility Paul B. Johnson, P.E. Managing Director - Transmission Operations American Electric Power 8400 Smith's Mill Road New Albany, Ohio (614) (614) Fx pbjohnson@ aep.com Federal/Provincial Darren Buck Regional Information Officer Western Area Power Administration 5555 East Crossroads Boulevard Loveland, Colorado (970) (916) Fx dbuck@wapa.gov Federal/Provincial Tom Irvine Manager, Grid Operations Hydro One Networks, Inc. 49 Sarjeant Drive Barrie, Ontario L4N-4V9 (705) (705) Fx tom.irvine@ hydroone.com Investor Owned Utility C. Martin Mennes Vice President, Transmission Operation and Planning Florida Power & Light Co West Flagler Street Room 6301 Miami, Florida (305) (305) Fx marty_mennes@ fpl.com State/Municipal Blaine R. Dinwiddie Division Manager, T&D Operations Omaha Public Power District 4325 Jones Plaza Omaha, Nebraska (402) (402) Fx bdinwiddie@ oppd.com State/Municipal To Be Named

6 Federal/Provincial Lorne Midford Manager, System Performance Dept. Manitoba Hydro P.O. Box 815 Winnipeg, Manitoba R3C 2P4 (204) (204) Fx hydro.mb.ca Federal/Provincial Louis-Omer Rioux Director System Control Hydro-Quebec 85, Ste-Catherine ouest 2 etage Montreal, Quebec H2X 3P4 (514) rioux.louis-omer@ hydro.qc.ca Transmission Dependent Utility Dennis Florom Manager, Energy and Environmental Operations Lincoln Electric System 1040 O St. P.O.Box Lincoln, Nebraska (402) (402) Fx dflorom@les.com Transmission Dependent Utility Raymond Phillips Manager Compliance and Special Projects Alabama Municipal Electric Authority 804 South Perry Street Montgomery, Alabama (334) (334) Fx ray@amea.com Merchant Electricity Generator Ralph Honeycutt, PE Director, Transmission Analysis and Operations SUEZ Energy Marketing NA, Inc Post Oak Boulevard Suite 1900 Houston, Texas (713) (713) Fx ralph.honeycutt@ suezenergyna.com Merchant Electricity Generator James T. Thompson Vice President Constellation Energy 500 Dallas St. Suite 3015 Houston, Texas (713) (443) Fx jt.thompson@ constellation.com Electricity Marketer Matt E. Greek Vice President - PJM/MISO Operations RRI Energy 1000 Main Street, #1662 Houston, Texas (713) (713) Fx mgreek@ rrienergy.com Electricity Marketer Stephen McCullough Director - Transmission and Operations Exelon Corporation 300 Exelon Way Kennett Square, Pennsylvania (610) (610) Fx exeloncorp.com Large End-use Electricity Customer John A. Anderson President & CEO Electricity Consumers Resource Council 1333 H Street, N.W. 8th Floor, West Tower Washington, D.C (202) (202) Fx janderson@ elcon.org Large End-use Electricity Customer Thomas Gianneschi Regulatory Affairs Alcoa, Inc. 900 South Gay Street 12th Floor Knoxville, Tennessee (865) (865) Fx tom.gianneschi@ alcoa.com Small End-use Electricity Customer To Be Named ISO/RTO Warren Frost Vice President Operations & Reliability Alberta Electric System Operator 2500, Avenue SW Calgary, Alberta T2P 0L4 (403) (403) Fx warren.frost@ aeso.ca ISO/RTO Jim G. McIntosh Director of Grid Operations California ISO 151 Blue Ravine Road Folsom, California (916) (916) Fx jmcintosh@ caiso.com

7 RRO-TRE Kent Saathoff Vice President of System Planning & Operations Electric Reliability Council of Texas, Inc West Lake Drive Taylor, Texas (512) (512) Fx ercot.com RRO-FRCC Ronald L. Donahey Managing Director, Grid Operations Tampa Electric Co. P.O. Box 111 Tampa, Florida (813) (813) Fx tecoenergy.com RRO-MRO Lawrence R. Larson Principal Engineer, Delivery Operations Otter Tail Power Company 215 South Cascade Street Fergus Falls, Minnesota (218) (218) Fx otpco.com RRO-NPCC John G. Mosier, Jr. Assistant Vice President - System Operations Northeast Power Coordinating Council, Inc Avenue of the Americas (6th Ave) 10th Floor New York, New York (212) (212) Fx jmosier@npcc.org RRO-RFC Jacquie Smith Senior Consultant, Reliability ReliabilityFirst Corporation 320 Springside Dr. Suite 300 Akron, Ohio (330) (330) Fx jacquie.smith@ rfirst.org RRO-SERC Jim Griffith Manager of System Operations Southern Company Services, Inc. P.O. Box 2625 Birmingham, Alabama (205) (205) Fx jsgriffi@ southernco.com RRO-SPP James Useldinger Manager, T&D System Operations Kansas City Power & Light Co. PO Box Kansas City, Missouri (816) (816) Fx jim.useldinger@ kcpl.com RRO-WECC Jerry D. Rust President Northwest Power Pool Corporation 7505 N.E. Ambassador Place Suite R Portland, Oregon (503) (503) Fx jerry.rust@ nwpp.org State Government To Be Named State Government To Be Named U.S. Federal (Non-voting) Thanh Luong Sr. Electrical Engineer Federal Energy Regulatory Commission 888 First Street, NE Washington, D.C (202) (301) Fx thanh.luong@ ferc.gov U.S. Federal (Non-voting) To Be Named Canadian Federal (Non-voting) To Be Named Provincial (Non-voting) Mark Lamothe Specialiste en Regulation Economique Quebec Energy Board 800 Place Victoria 2nd Floor, CP 001 Montreal, Quebec H4Z 1A2 (514) (514) Fx mark.lamothe@ regie-energie.qc.ca

8 Agenda Item 1.f Joint Operating and Planning Committee WebEx Meeting July 20, 2009 Planning Committee Chairman Thomas C. Burgess Director, FERC Compliance FirstEnergy Corp. 76 South Main Street Akron, Ohio (330) (330) Fx firstenergycorp.com Vice Chairman Jeffrey Mitchell Director - Engineering ReliabilityFirst Corporation 320 Springside Dr. Suite 300 Akron, Ohio (330) (330) Fx jeff.mitchell@ rfirst.org Secretary John L Seelke, Jr. Manager of Planning North American Electric Reliability Corporation Village Boulevard Princeton, New Jersey (609) (609) Fx john.seelke@ nerc.net Cooperative Jay Farrington Manager, T&D Planning and Reliability PowerSouth Energy Cooperative P.O. Box 550 Andalusia, Alabama (334) (334) Fx jay.farrington@ powersouth.com Cooperative Ronnie Frizzell Principal Planning Engineer Arkansas Electric Cooperative Corporation 1 Cooperative Way Little Rock, Arkansas (501) (501) Fx rfrizzell@ aecc.com Electricity Marketer Israel Melendez Vice President, Grid Optimization Constellation Energy Commodities Group 111 Market Place, Suite 500 Baltimore, Maryland (410) (410) Fx izzy.melendez@ constellation.com Electricity Marketer To Be Named Federal/Provincial Jean-Marie Gagnon Project Manager Interconnected Networks Assets Planning Hydro-Quebec TransEnergie Complexe Desjardins, Tour Est 10th Floor, CP Montreal, Quebec H5B 1H7 (514) Ext (514) Fx gagnon.jean-marie@ hydro.qc.ca Federal/Provincial R. W. Mazur Manager, System Planning Department Manitoba Hydro Waverly Street P.O. Box 815 Winnipeg, Manitoba R3C 2P4 (204) (204) Fx rwmazur@ hydro.mb.ca Federal/Provincial Naren Pattani Manager, Transmission System Development Hydro One, Inc. 483 Bay Street North Tower, 15th Floor Toronto, Ontario M5G 2P5 (416) (416) Fx naren.pattani@ hydroone.com Federal/Provincial Timothy E. Ponseti Vice President of System Planning Tennessee Valley Authority 1101 Market Street, MR-3K Chattanooga, Tennessee (423) (423) Fx teponseti@ tva.gov

9 Investor Owned Utility Richard J. Kafka Transmission Policy Manager Pepco Holdings, Inc. P. O. Box 1010 West Bethesda, Maryland (301) (301) Fx pepcoholdings.com Investor Owned Utility William P Stowe General Manager Southern Company Services, Inc. PO Box North 18th Street Birmingham, Alabama Fx wpstowe@ southernco.com Large End-Use Electricity Customer To Be Named Merchant Electricity Generator To Be Named Merchant Electricity Generator Kris Zadlo, P.E. Vice President Invenergy LLC (312) (312) Fx kzadlo@ invenergyllc.com State/Municipal Stuart Nelson Manager, Asset Development Lower Colorado River Authority P.O. Box 220 Austin, Texas (512) (512) Fx stuart.nelson@ lcra.org State/Municipal Ralph Rufrano Executive Director, Reliability Standards and Compliance New York Power Authority 1633 Broadway New York, New York (914) (914) Fx ralph.rufrano@ nypa.gov Transmission Dependent Utility To Be Named Large End-use Electricity Customer To Be Named Small End-use Electricity Customer Mary J. Healey Consumer Counsel Office Of Consumer Counsel, State of Connecticut 10 Franklin Square New Britain, Connecticut (860) (860) Fx mary.healey@ ct.gov Small End-Use Electricity Customer Glenn B. Ross President All Energy Queens Harbor Blvd. N. Jacksonville, Florida (904) glenn_ross@ comcast.net ISO/RTO Mark Westendorf Principal Engineer Midwest ISO, Inc. 701 City Center Drive P.O. Box 4202 Carmel, Indiana (317) (317) Fx mwestendorf@ midwestiso.org ISO/RTO Peter Wong Manager, Resource Adequacy ISO New England, Inc. One Sullivan Road Holyoke, Massachusetts (413) (413) Fx pwong@iso-ne.com RRO-ERCOT Dan M Woodfin Director, System Planning Electric Reliability Council of Texas, Inc West Lake Dr. Taylor, Texas (512) Fx dwoodfin@ ercot.com

10 RRO-FRCC Ben Crisp Director System Planning and Regulatory Performance Progress Energy Florida th Avenue North St. Petersburg, Florida (727) pgnmail.com RRO-MRO Dale Burmester Manager, Access/Transmission Planning American Transmission Company, LLC 2 Fen Oak Court Madison, Wisconsin (608) Fx dburmester@ atcllc.com RRO-NPCC Phil Fedora Assistant Vice President, Reliability Services Northeast Power Coordinating Council, Inc Avenue of the Americas (6th Ave) 10th Floor New York, New York (212) (212) Fx pfedora@npcc.org RRO-RFC Paul Kure Senior Consultant, Resources ReliabilityFirst Corporation 320 Springside Drive Suite 300 Akron, Ohio (330) (330) Fx paul.kure@ rfirst.org RRO-SERC Edward Pfeiffer 1901 Choutear Avenue St. Louis, Missouri (314) epfeiffer@ ameren.com RRO-SPP William Dowling Vice President of Energy Management & Supply Midwest Energy, Inc Canterbury Hays, Kansas Fx bdowling@ mwenergy.com RRO-WECC John Simpson Colfax Road Magnolia, Texas (281) jl2simpson@ sbcglobal.net State Government Philip Riley Advisory Engineer IV Public Service Commission of South Carolina 101 Executive Center Drive Columbia, South Carolina (803) (803) Fx philip.riley@ psc.sc.gov State Government Erik Saltmarsh 3720 Boise Avenue Suite 1250 Los Angeles, California (310) erik.saltmarsh@ gmail.com U.S. Federal (Non-voting) David Andrejcak Manager of Bulk Power System Analysis Federal Energy Regulatory Commission 888 First Street, NE Washington, D.C david.andrejcak@ ferc.gov U.S. Federal (Non-voting) To Be Named Canadian Federal (Non-voting) To Be Named Provincial (Non-voting) Peter Fraser Special Advisor Ontario Energy Board 2300 Yonge St., 26th Floor Toronto, Ontario M4P 1E4 (416) (416) Fx peter.fraser@ oeb.gov.on.ca

11 Agenda Item 2.a Joint Operating and Planning Committee WebEx Meeting July 20, 2009 The RMWG s Revised Metrics OC Action Required Provide the PC will its recommendations on the RMWG s revised metrics, including the subset of metrics for the 2009 LTRA. PC Action Required Approve metrics, including a subset of metrics for the 2009 LTRA. Background The RMWG issued a preliminary report 2009 Bulk Power System Performance Metrics Recommendation dated May 28, See the announcement in Attachment 1. At the June 8-9, 2009 Planning Committee, the PC acting on the following RMWG items: 1. It approved a revised RMWG scope. 2. It authorized the committee officers to request to the appropriate parties that the term dashboard be removed from the NERC Rules of Procedure and replaced with reliability indicators. 3. It approved the metrics development process as described in Chapter 2 of the May 28 report. 4. It approved deferring a decision on the 2009 LTRA metrics until this WebEx. Of the nine metrics proposed in the May 28 report and shown on Table 1 (next page), two metrics (ALR3-5 and ALR6-1) are not being proposed for the 2009 LTRA because of lack of data. Prior to the WebEx, the RMWG was to seek committee comments on the proposed metrics and provide the committee with a summary of those comments prior to the WebEx so that the committee can make an informed decision. On June 17, 2009, the RMWG requested comments from both the OC and PC on its May 28 report. See the request in Attachment 1. Attachment 2 has the comments that the RMWG received on the metrics in its May 28, 2009 report, along with responses to those comments. The revised metrics templates based upon the comments received begins on p The May 28 report may be downloaded at

12 Table 1 - Nine Recommended Metrics Metric Number Short Title ALR2-4 Disturbance Control Standard Failures ALR2-5 ALR1-4 ALR3-5 ALR4-1 Disturbance Control Events Greater than Most Severe Single Contingency Events Resulting in Unplanned Loss of Load Operating Limit Excursion (OL Excursion) Correct Protection System Operations ALR6-2 Energy Emergency Alert Level 3 ALR6-3 Energy Emergency Alert Level 2 ALR6-1 ALR1-3 Transmission Constraint Mitigation Reserve Margin

13 Page 1 of 2 Attachment 1 Agenda Item 2.a John Seelke From: Elizabeth Crouse [Elizabeth.Crouse@nerc.net] Sent: Wednesday, June 17, :14 PM To: Elizabeth Crouse Subject: REMINDER: RMWG Report Comments Deadline Attachments: RMWG Report Comment Matrix.doc; RMWG Report May 29 v2.doc; footer Reminder Comments on the RMWG report are due no later than close of business on June 30th, 2009 The report is both attached and available at: As a follow up to the recent committee meetings in Toronto, the Reliability Metrics Working Group (RMWG) respectfully requests comments on the RMWG report 2009 Bulk Power System Reliability Performance Metrics Recommendations. The attached Comment Matrix and a redlined copy of the report should be submitted to Herbert Schrayshuen, RMWG chair (hschrayshuen@serc1.org) and Jessica Bian, RMWG secretary (jessica.bian@nerc.net) by COB June 30th, /2/2009

14 Page 2 of 2 Liz Crouse Administrative Assistant North American Electric Reliability Corporation Village Blvd. Princeton, NJ elizabeth.crouse@nerc.net 7/2/2009

15 Comments on Proposed Metrics and the RMWG s Responses General Template Comments: Attachment 2 Agenda Item 2.a 1. Chapter 4 templates should more clearly indicate which entity (NERC Functional Model definition) is expected to submit the requested data. Agreed. RMWG will add one statement in a metric template to specify which entity is expected to collect and provide the data. Examples include NERC, regions, registered entities and stakeholder committees. 2. Since many readers of the report may not have taken quantum physics in school, the term Heisenburg Effect should be defined before reference in the Chapter 4 templates. Agreed. RMWG will delete this attribute from the metric template. 3. On the metric specification sheet, the SMART rating is provided with an explanation of how it will be suited to indicate performance. The explanation is not necessary AND SHOULD BE REMOVED. The SMART rating is only a ranking system used for determining which metric will be most beneficial and attainable at the time. Each metric should be placed in the proper context within each report that the metric is used. Further, under Chapter 4, it is indicated that an annual report will summarize and provide an assessment of the metric results. The explanation of how a metric will be suited to indicate performance and its ALR linkage should be kept in a template. It helps one to place the metric into proper context. This is also a record of RMWG decision making process. The SMART rating will be moved towards the end of template for record keeping purposes. 4. The reference to Can the metrics drill down to an individual entity? should be deleted. Care must be taken that the user of the trends cannot evaluate each entity on the mean or any statistical measure of the data. Trends should be an alarm that gets attention rather than a measure of some expected value. Agreed. Raw data that can be drilled down to an individual entity will not be made available. 1 of 31

16 Attachment 2 Agenda Item 2.a Comments for ALR1-3: 1. Mark Westendorf, MISO, reflection of comments across the ISO/RTO segment. Reserve Margin is a metric if presented in the proper context can provide adequacy information, especially for trending. Linking to the TPL and BAL standards is confusing AND SHOULD BE REMOVED. Requirements in the linked standards (TPL-001, TPL-002 and BAL-002) state neither what comprises an adequate reserve nor provide a methodology to determine adequacy based on Reserve Margin data. If a Reserve Margin metric is to provide an indication of health or adequacy of the BES, a meaningful linkage must be made. Agreed. Linkage to the TPL and BAL standards will be removed. This metric refers to Reserve Margin for planning purposes. 2. Lorne Midford, Manitoba Hydro This metric is overly simplistic and does not address deliverability of generation capacity. As reserve margin is already measured and acted upon, the occurrence of EEA, which identifies when systems are forecasting trouble to meet forecasted demand, is more meaningful information. ALR 6-2 and ALR 6-3 are sufficient measures. How is this metric linked to TPL-001 and TPL-002? The TPL standards do not address generation adequacy. If the intent of this metric is to report historical reserve margin, then the reporting is fact based. However, NERC has debated extensively on what generation should be included in such a metric (queued generation, generation with signed IOAs, capacity of wind, etc ) Outside the context of a document like the LTRA, the metric will require extensive qualification for proper interpretation. Agreed. Linkages to the TPL and BAL standards will be removed. The intent of the metric is to gauge the amount of generation capacity available to meet expected demand in the planning horizon. Deliverability is an on-going issue in the data reporting process for assessments. RMWG believes the best place to examine reserve margin is within seasonal and long term assessments, addressing various types of capacity incorporated into definitions. 3. Tom Gianneschi, Alcoa Delete ALR 1-3 Reserve Margin as a metric. The reserve margin metric fails the SMART analysis on a number of counts and should be eliminated from further consideration. Using the group s criteria from Table 2 SMART Method and Rating on page 7 of the report I have noted the following failures. 2 of 31

17 Attachment 2 Agenda Item 2.a Reserve Margin has a very low ability to identify factors that positively or negatively impact reliability because it measures only excess generation capacity. For the purpose of reliability, excess generation capacity by itself is neither good or bad on a standalone basis unless it is available exactly when needed and is the most economical alternative of all the choices an operator may have at his disposal. Reserve Margin fails to measure past and current reliability. For instance, I don t believe it is possible to point to low reserve margin values and positively correlate them in a causal manner to black outs. Furthermore, a change in reserve margins does not indicate a reliability gap or point to standards that need modification or a need for new standards. As an indicator only of capacity, Reserve Margins do not provide feedback for improving standards and as a result provide no meaningful information regarding the ALR. Looking forward, as the focus of policy turns to the development of non generation resources envisioned in the Smart Grid and Demand Response policies this metric seems obsolete as an indicator of much more than legacy overcapacity. The metric Reserve Margin is directly tied to ALR characteristic #6 Adequacy, which is in the RMWG charter. The trends for this metric will identify whether capacity additions are projected to keep up with load growth and provide adequate reserve. RMWG has proposed and discussed several metrics on usage of demand-side responses and storage devices. However through SMART criteria, they were not ranked high enough at this time as compared to the first set of nine metrics recommended in this report. RMWG expects to take up more details in the future rounds of metric development. There is a broad recognition of the shortcomings of pure margin calculations and definitions. RMWG will monitor diversifications of resources and develop reserve margin measuring usage of non generation resources in the future. 3. Terry Bilke, MISO How many years out will reserve margin be calculated? Is this by month? The metric will be used to look out up to next 10 years. It will be based on data reported in the LTRA (each year for 10 years out) and seasonal assessments (the next peak season). 4. Tom Burgess, FirstEnergy This is ready to include in LTRA. Agreed. 3 of 31

18 Attachment 2 Agenda Item 2.a Comments for ALR1-4: 1. Lorne Midford, Manitoba Hydro The meaning of "unplanned loss of load" isn't very clear. It appears that the metric is supposed to capture the number of transmission events that caused an "unplanned loss of load." Would the metric capture a loss of a transmission line with a tapped load? I would assume not as this would be a "planned loss of load". Suggest renaming the metric to "Transmission Related Events Resulting in Loss of Load." the proposed title implies that there is "planned loss of load." Agreed. The word unplanned will be removed from the title. 2. Tom Burgess, FirstEnergy This is ready to include in the LTRA, but it should be enhanced to measure significant losses, and exclude relatively minor instances of transmission events resulting in ANY unplanned loss of load. Metric Formula should specify "event" as being a load loss of a certain amount and/or other characteristic. Specify "event" as being a load loss of a certain amount and/or other characteristic. Event is an unplanned disturbance that produces an abnormal system condition due to equipment failures/system operational actions which result in the loss of firm system demands for more than 15 minutes, as described below (per Standard EOP-004): 1. Entities with a previous year recorded peak demand of more than 3,000 MW are required to report all such losses of firm demands totaling more than 300 MW. 2. All other entities are required to report all such losses of firm demands totaling more than 200 MW or 50% of the total customers being supplied immediately prior to the incident, whichever is less. 3. Firm load shedding of 100 MW or more to maintain the continuity of the BPS reliability. 4 of 31

19 Comments for ALR2-4: 1. Tom Gianneschi, Alcoa Delete ALR 2-4 Disturbance Control Standard Failures as a metric. As defined in the report this measure will indicate the percent of successful recoveries from DCS failures utilizing contingency reserves. I suggest putting operators in a position where they must call on these reserves is more an issue of adequate reliability than the success rate. For instance, if operators must access contingent reserves more frequently but manage to maintain a good success rate in doing so, the BPS does not demonstrate an increasing level of adequate reliability even though this metric could return a value of 100%. On the other hand, an increasing ability to avoid calling these reserves may indicate in increasingly robust level of reliability more than the success rate embedded in the proposed metric. For this reason I suggest replacing this with a metric that measures the trend of DCS events as a more direct indicator of the bulk power system s reliability. The currently proposed metric is skewed to indicate how well operators can access and juggle contingency reserves and may give a false impression of the level of adequate reliability if the underlying system performance deteriorates requiring them to more frequently access these reserves. The metric is designed to measure the Balancing Authority or Reserve Sharing Groups ability to utilize contingency reserve to balance resources and demand and return the Interconnection frequency within defined limits following a Reportable Disturbance. It is essential to track and monitor BA or RSG s recovery ability over time. 2. Terry Bilke, MISO This may not be a particularly useful metric. Being one minute late in recovering from DCS is probably not a reliability issue. Also, there are many different reporting thresholds. Some BAs count events as small as 100 MW as reportable. Some only report something on the order of 1000MW. Not all DCS events have the same impact on reliability. Since the metric tracks and monitors BA or RSG s ability over a period of time, any deteriorating performance can be identified, investigated and corrected quickly. It is true that not all DCS events have the same impact on reliability. However if poor performance of small DCS events are ignored, collectively the impact of the insufficient capability could make the system recovery performance worse following a sizable generation loss. We need to start somewhere and the standard definitions are as good as any to start with. Any DCS failure adds risk to the interconnection. If one ignored all the small events then the small event would grow into a large event. We need to treat everyone on the same base. 5 of 31

20 3. Mark Westendorf, MISO, reflection of comments across the ISO/RTO segment. Would focusing on DCS failures be more appropriate for a concern over warning signs of future reliability issues? In other words collect and calculate a percentage of DCS failures. Agreed. The metric will be revised to track a percentage of DCS failures, not percentage of DCS recoveries as it is defined in current template. 4. Tom Burgess, FirstEnergy This is ready to include in LTRA, but one conceivable issue should be examined. DCS reportable thresholds can be set differently across BA's, and thresholds can be reset from time to time, making regional comparisons misleading and potentially skewing trends over time. Thus, Metric Formula should be structured to become more sophisticated and address these aspects. There will not be any regional comparisons for any proposed metrics. The reportable thresholds are defined consistenly across BAs and RSGs within the same region in Standard BAL of 31

21 Comments for ALR2-5: 1. Tom Burgess, FirstEnergy This is potentially ready to include in the LTRA, but one issue should be examined. Will the fact that each BA has different types of MSSC, such as a tie line or a generating unit, produce misleading results. Consider doing a "field test" with this metric. Since the metric only tracks performance for each region and no regional comparisons are being made, it can be used to measure how much risk each region is exposed to for unusual contingencies. The results will help validate current contingency reserve requirements and document how often these contingences occur. In addition, one will be able to measure the risk for each Interconnection. 7 of 31

22 Comments for ALR3-5: 1. Terry Bilke, MISO The title is Operating Limit Excursion. Is this restricted to IROLs? If so, use this abbreviation. If not, there will be a big problem collecting this data. Local limits are set differently across North America and they are touched all the time. This is an expected outcome of open access. Also, the metric gives the impression that there should be a race in fixing exceedences of a postcontingent limit. While the operator needs to be aggressive in fixing these, they must evaluate the situation and take the appropriate action. Finally, the source of the data should be from NERC Compliance (reports of violations of IROL standards). RMWG recommends that IROLs be reported under this measure in the Eastern Interconnection, and SOLs in the Western and ERCOT Interconnections. 40 Designated Paths within the Western Interconnection are required to have System Operating Limits (SOL). SOLs are determined under N-2 conditions for all elements of a given Path, and the interconnected power system shall remain stable upon loss of any one single element without system cascading that could result in the successive loss of additional elements. NERC Compliance only receives violation reports if the OL limits have been exceeded more than 30 minutes. This metric is designed to measure not only the number of IROL violations but also frequency and duration of flows exceeding the defined limits less than 30 minutes. 2. Tom Burgess, FirstEnergy This is potentially ready to include in the LTRA. It appears that the use of IROLs in the eastern interconnection, which is appropriate, but use of SOLs in the ERCOT/WECC may frustrate regional comparisons. The summary overview could be understood to suggest that any limit at any time would need to be measured - this we're not ready to do. If limited to the reporting under IRO-009, then this is probably ready for LTRA. There will not be any regional comparisons for any proposed metrics. Since there are no IROL facilities in Western Interconnection, new WECC standard suggests using SOLs to represent its set of cirtical path limits. 40 Designated Paths within the Western Interconnection are required to have System Operating Limits (SOL). SOLs are determined under N-2 conditions for all elements of a given Path, and the interconnected power system shall remain stable upon loss of any one single element without system cascading that could result in the successive loss of additional elements. 8 of 31

23 Comments for ALR4-1: 1. TADSTF: The number of TADS Automatic Outages does not include all circuit trips. Two or more trips and reclosures which occur within one minute are counted as one Automatic Outage. The actual total number of circuit trips which challenge protective relay systems will be higher than the total number of TADS Automatic Outages. The TADS number of outages caused by Failed Protection System Equipment includes any relay and/or control misoperations except those misoperations which were caused by Human Error. TADS does not know how many relay and/or control misoperations where the result of Human Error. TADS just calculates the total count of Automatic Outages caused by Human Error. The following metric revision is proposed: Percent of Automatic Outages not caused by Failed Protection System Equipment = = 100 minus Percent of Automatic Outages caused by Failed Protection System Equipment Agreed. The template has been updated to reflect TADSTF s comments. 2. Mark Westendorf, MISO, reflection of comments across the ISO/RTO segment. Metric Description- Isn t the number of correct operations likely to increase and more time consuming to collect? Further it should be easier to keep track of misoperations and that is the focus of what should be tracked. For the Formula-The percent of misoperations should be the metric. Agreed. The template has been modified so that the metric will focus on automatic outages caused by Failed Protection System Equipment. 3. Tom Burgess, FirstEnergy This is not ready to be included in the LTRA, but instaed should be field tested. All the data is not clearly available, "total number of trips" in particular. A field test would allow for some prelimary results to further examine the implications of application of this metric. The metric data comes from TADS database, which lists the total number of automatic outages for each region. 9 of 31

24 Comments for ALR6-1: 1. Lorne Midford, Manitoba Hydro This metric assumes that the transmission system is not reliable when SPS/RAS in combination with operating procedures are used in the design of new transmission. This assumption is flawed. SPS/RAS are valid planning options, when designed to meet rigid requirements, that can ensure reliable operation of the BES, much like the use of generation redispatch or the application of some FACTS devices. A more meaningful metric would measure the robustness of the SPS/RAS design, not whether or not an SPS is installed, which seems to imply that an SPS/RAS degrades the robustness of the transmission system. Measuring the number of times that SPS/RAS's fail to operate as designed is much more useful. Trends in the number of mitigation plans required to meet reliability criteria will indicate whether the robustness of the transmission system is increasing, remaining static, or decreasing. A certain number of mitigation plans may be necessary to support reliable operation, however, changes in the number over time will provide an indication of whether additional transmission capacity is being added to meet reliability requirements or further reliance on mitigation plans is reducing the robustness of the grid. It is expected that the absence or existence of mitigation plans will, with time, communicate the efficacy of the engineering and operational reliability of the system. Mitigation plans are not expected to be either a deficit or benefit, but rather an indicator of how the system must be operated at a point in time. 2. Mark Westendorf, MISO, reflection of comments across the ISO/RTO segment. A number of mitigation plans or trend in that number may not be a good metric without some additional linkage to reliability since each mitigation plan may be unique to a specific condition (e.g. designed for remote parts of the BES ). Any reference to congestion with this metric should be removed and avoided. Congestion is not always an unwarranted condition. Congestion could be a sign that the market is fully utilizing the grid capability. Agreed. RMWG plans to conduct pilot data runs based on regional transmission assessment documents. 3. Tom Burgess, FirstEnergy This is not ready for the LTRA, but it should be field tested. The number and consistency of 'mitigation plans' is not likely readily at hand, and this potentially sets the stage for misinterpretations of results, in particular with the proposed TPL standard which obligates the TOs to provide Corrective Action Plans for all system conditions which do not satisfy the various planning tests. Further, this creates the impression that the mere presence of SPS, operating procedures, etc are somehow inferior, imposing adverse reliability consequences. Agreed. RMWG plans to conduct pilot data runs based on regional transmission assessment documents. At future time RMWG will consider a metric to measure failures of SPS/RAS operations. 10 of 31

25 Comments for ALR6-2: 1. Tom Burgess, FirstEnergy This is potentially ready to include in the LTRA, but the preference would be to conduct further field tests. The EEA metrics are not necessarily appropriate as a measure of reliability conditions, because they include various 'economic' actions taken in various parts of the grid. The objective of the field test would be to set a clear mechanism to differentiate the economic components from the reliability asepcts. The LTRA should only focus on the reliability component of EEAs. Clearly a part of these are reliability actions, and to the extent we are parsing the data to ONLY include those aspects, then I think that would be appropriate to include in the LTRA. Agreed that no economic factors should be included in the metric. The metric template will be updated to emphasize this point. An Energy Emergency Alert is an emergency procedure, not a daily operating practice. The Energy Emergency Alert trends are based on the data gathered from Reliability Coordinator Information System (RCIS). In EEA 3, firm load interruption is imminent or in progress. No economic factors are considered in the metric. As historical data is gathered, EEA 3 trends will provide an indication of either decreasing or increasing adequacy in the electric supply system. 11 of 31

26 Comments for ALR6-3: 1. John Seelke, NERC EEA-2, or a Level 2 Energy Emergency Alert, is defined in Reliability Standard EOP in Attachment EOP-002. As defined in that attachment, EEA-2 measures everything from the initiation of utility load conversation to public appeals for energy reduction. Embedded in that range of actions is demand-side management and interrupting non-firm load, with the proviso that non-firm load interruptions are only counted when they are for emergency, not economic reasons. Many non-firm tariffs have customer buy through provisions which allow customers to pay for purchased power rather than be interrupted, so this proviso is appropriate for non-firm load. The same proviso does not apply to demand response program such as direct control of residential air conditioners. Interruptible load and demand response are counted as resources from a planning and operating perspective, but Attachment EOP-002 would lead one to believe that their use to serve firm load constitutes an emergency. There use is not an emergency, and the standard itself warrants revision. By labeling the use of these resources as an emergency, the standard already negatively characterizes resources that many utilities and RTOs rely upon for serving firm load. The adoption of EEA-2 as a resource adequacy metric would memorialize this mistake; therefore, it should be rejected by the Planning Committee. If the RMWG wants a metric that is just shy of EEA-3, I suggest this metric: the number of times and MW shortfall when non-spinning operating reserve requirements cannot be met. Spinning reserves cannot be depleted firm load must be shed to maintain spinning reserve since they are needed in case of a disturbance. However, the failure of any BA to maintain its 10 or 30 minute non-spinning reserves seems like a good starting place. Agreed that no economic factors should be included in the metric. The metric template will be updated to emphasize this point. An Energy Emergency Alert is an emergency procedure, not a daily operating practice. The Energy Emergency Alert 2 trends are based on the data gathered from NERC s Reliability Coordinator Information System (RCIS). During an EEA 2 energy emergency event, which can only be called by the Reliability Coordinator, a Balancing Authority, Reserve Sharing Group, or Load Serving Entity are no longer able to provide its customers expected energy requirements, and are designated an Energy Deficient Entity. The Energy Deficient Entity foresees or has implemented procedures up to, but excluding, interruption of firm load commitments. All contractually interruptible retail loads have already been, or are in the process of being curtailed, and voluntary demand-side management activated within provisions of the agreements. As historical data is gathered, EEA 2 trends will provide an indication of either decreasing or increasing adequacy in the electric supply system. 12 of 31

27 The suggested metric, the number of times when non-spinning operating reserve requirements cannot be met, is in fact an EEA 1 event counts. EEA 2 events called solely for activation of DSM or interruption of non-firm load per applicable contracts will be excluded from the metric. The existing data reporting will be modified to add additional information on what actions are being taken in EEA-2 events to insure DSM and nonfirm load interruption are excluded from the metric. 2. Tom Burgess, FirstEnergy This is potentially ready to include in the LTRA, but the preference is to conduct field tests. These EEA metrics are not necessarily appropriate for reliability measurements because they include various 'economic' actions taken in various parts of the grid, rather than reliability actions. The LTRA should only focus on the reliability component of EEAs. Clearly a part of these are reliability actions, and to the extent we are parsing the data to ONLY include those aspects, then I think that would be eventually be okay to include in the LTRA. Agreed that no economic factors should be included in the metric. The metric template will be updated to emphasize this point. An Energy Emergency Alert is an emergency procedure, not a daily operating practice. The Energy Emergency Alert 2 trends are based on the data gathered from NERC s Reliability Coordinator Information System (RCIS). During an EEA 2 energy emergency event, which can only be called by the Reliability Coordinator, a Balancing Authority, Reserve Sharing Group, or Load Serving Entity are no longer able to provide its customers expected energy requirements, and are designated an Energy Deficient Entity. The Energy Deficient Entity foresees or has implemented procedures up to, but excluding, interruption of firm load commitments. All contractually interruptible retail loads have already been, or are in the process of being curtailed, and voluntary demand-side management activated within provisions of the agreements. As historical data is gathered, EEA 2 trends will provide an indication of either decreasing or increasing adequacy in the electric supply system. 13 of 31

28 Revised Metric Templates Based on the Comments Received: Metric Number Submittal Date February 27, 2009 Sponsor Group (OC, PC or subgroup name) Short Title Metric Description Reliability Metrics Specifications Sheet ALR 1-3 Reserve Margin ALR1-3 RMWG Reserve Margin Percentage of additional capacity over load To gauge the amount of generation capacity available to meet expected Purpose demand The percentage provides an indication of the additional capacity available to meet unforeseen increases in demand, unforeseen outages of existing How will it be capacity, and trends which will indentify whether capacity additions are suited to keeping up with load growth. Caution should be noted in all reports that this indicate is a capacity based metric and may not provide an accurate assessment of performance? performance in energy limited systems, e.g., hydro capacity with limited water resources. Formula Reserve Margin (%) = (Capacity Load)/Load X 100 Time Horizon Planning horizon Metric Start Time or Year 2002 Baseline Data Collection Data collection should be on an annual and seasonal basis with reporting for Interval and each quarter Roll Up Ease of Data is easily collected and reported on a regional basis now. Collection Aggregation Linkage to NERC Standard Linkage to Data Source Need for Validation or Pilot Data Submitting Entity SMART Rating Could be on an Interconnection, Regional Entity, or BA level. Data reported now in LTRA and seasonal assessments No Regional Entities Total Specific/ Measurable Attainable Relevant Tangible/ Score Simple Timely Reporting 14 of 31