Operating Committee Conference Call and Webinar Meeting Minutes

Transcription

1 Operating Committee Conference Call and Webinar Meeting Minutes October 10, :00 p.m. 3:00 p.m. (EDT) The Operating Committee (OC) met by conference call and webinar on October 10, 2012 at 1:00 p.m. EDT. The meeting agenda and the attendance list are affixed as Exhibits A and B, respectively; and individual statements and minority opinions as Exhibits C and D, respectively. Chair Tom Bowe presided and Larry Kezele announced that a quorum was not present; therefore, the OC would conduct ballots of all actions. Notice of Public Meeting and Antitrust Compliance Statement Larry Kezele read the applicable Notice of Public Meeting and summarized the NERC Antitrust Compliance Guidelines. Conference Call Summary The OC discussed the following: Frequency Response Initiative Report Bob Cummings provided an overview of the Frequency Response Initiative report (Presentation 1). Mr. Cummings reported that the report was a work product of ERCOT, NERC staff, the Frequency Response standard drafting team, contractors, and the Resources Subcommittee. Jim Case moved to accept the Frequency Response Initiative report, as amended, by comments received during the OC s discussion. Some OC members questioned the validity of Recommendation 10 contained with the report. Others asked what version of the report the OC was actually being asked to accept. Keith Carman called for a roll call vote of the motion, during which time it was determined that a quorum of the OC was not available. By ballot, the OC approved the motion (Exhibit E). Several no votes, with comments, were received. Those comments are recorded in Exhibit.D. Definition of Adequate Level of Reliability Chair Bowe noted that at the October 3, 2012 Standing Committee Coordinating Group meeting, Allen Mosher, chair of the Adequate Level of Reliability Task Force, sought approval of a revised definition of ALR. Keith Carman, a member of the ALRTF, stated that the task force posted the proposed definition for public comment and addressed many of the comments received. The ALR definition is intended to be a foundational document for the development of NERC reliability standards going forward. The new ALR definition will likely be filed at FERC for informational purposes, as was the original ALR definition.

2 Jerry Mosier moved to approve the revised definition of Adequate Level of Reliability. By ballot, the OC approved the motion (Exhibit F). Project Cold Weather Preparedness Standard Authorization Request Jim Case reviewed draft OC comments developed by JT Thompson and himself in response to a request by Allen Mosher, chair of the Standards Committee, that the OC review the SAR and provide formal comments. Paul Johnson moved to approve the OC comments on the Cold Weather Preparedness SAR, as amended, (Exhibit G). By ballot, the OC approved the motion (Exhibit H). Adjournment The conference call meeting was adjourned at 2:36 p.m. EDT on October 10, Larry Kezele Larry J. Kezele Secretary Operating Committee Conference Call and Webinar Minutes October 10, 2012

3 Exhibit A Agenda Operating Committee October 10, :00 p.m. 3:00 p.m. (EDT) Conference Dial In: Pass Code: Security Code: Webinar Link: Ready Talk Link Welcome and Introductions Chair Bowe NERC Antitrust Guidelines and Notice of Public Meeting Larry Kezele Agenda 1. Review Agenda Chair Bowe Committee Matters 2. Accept Frequency Response Initiative Report* Bob Cummings Direct Link to CLEAN Version: Frequency Response Initiative Report 3. Approve Definition of Adequate Level of Reliability* Chair Bowe 4. Discuss OC Comments on Cold Weather Preparedness SAR* Jim Case a. Standards Committee Letter to Chair Bowe b. Cold Weather Preparedness Comment Form c. Cold Weather Preparedness SAR 5. Adjourn * Background material provided

4 EXHIBIT B ATTENDEES Operating Committee Conference Call and Webinar Meeting October 10, 2012 OFFICERS Chair Vice Chair Secretary and Staff Coordinator Tom Bowe Jim Castle Larry Kezele MEMBERS VOTING MEMBERS VOTING MEMBERS (cont d) Cooperative Chris Bolick Keith Carman Small End-use Customer Kevin Conway Michael Goggin Electricity Marketer TRE Alan Bern Federal/Provincial Tom Irvine Martin Huang FRCC MRO Ron Donahey Lloyd Linke Investor-Owned Utility ISO/RTO Paul Johnson Jim Case Bruce Rew David Zwergel NPCC RFC SERC Jerry Mosier Jacquie Smith Gerry Beckerle Large End-use Customer WECC Don Badley proxy for Jerry Rust State/Municipal Doug Peterchuck SPP Jim Useldinger Transmission Dependent Utility Merchant Generator State Government Richard Kinas NON-VOTING MEMBER U.S. Federal Eddy Lim

5 ATTENDEES Operating Committee Meeting (cont d) October 10, 2012 Regional Entity FRCC MRO Hassan Hamdar Dan Schoenecker NERC STAFF Matthew Varghese Mike Moon Thomas Dunn Roman Carter Svetlana Ekisheva Bob Cummings GUESTS Brad Gordon Kelly Casteel Carlos Martinez Don McInnis Macarena Toro Troy Blalock Enakpodia Agbedia Gil Tam Mike Potishnak Cindy Martin Robert Blohm Tom Pruitt Howard Illian Song Xue Randy Hubbert Syed Ahmad Paul Roehr Terry Bilke Matthew Adeleke Sydney Niemeyer Kent Saathoff PJM TVA Electric Power Group FPL FPL SCANA FERC Electric Power Group ISO-NE Southern Consultant Duke Energy Energy Mark Electric Power Group Southern FERC American Transmission MISO FERC NRG Energy ERCOT 2

6 Exhibit C Individual Statements Operating Committee Conference Call and Webinar Meeting October 10, 2012 There were none.

7 Exhibit D Minority Opinions Operating Committee Conference Call and Webinar Meeting October 10, Jerry Rust WECC The WECC still believes the Frequency Response Initiative Report has two significant problems: a. Recommendation 10 on Page 6 states "NERC and the Western Interconnection should analyze the FRO allocation implications of the Pacific Northwest RAS generation tripping of 3,200 MW." We believe that since this RAS was developed in the Western Interconnection (WI) and has had total WECC scrutiny there is no need for NERC and the WI to waste time restudying or re-reviewing the RAS. This RAS is a secondary action that is only armed when certain conditions occur: it is intended to prevent unreliable operating conditions. Furthermore, our experience with this particular RAS has verified the veracity of the studies used to develop the scheme. Also, we find it quite unusual to single out one Remedial Action Scheme when we are aware that many Remedial Action Schemes exist throughout NERC. b. On Page 52, the study begins to lay out discrete protection criteria that could be used to establish the Interconnection Frequency Obligation (IFO). One of these criteria is based upon "Largest loss of resource event in the interconnection in the last 10 years." We feel this is impractical and will mislead a lay person into thinking that protecting the system to this level will bolster reliability and reduce outages when just the opposite is likely to be the outcome. Also, this connotes a single event when, in reality, it was a series of events. This criterion will produce unintended consequences. We could live with Recommendation 10 but it will mean a lot of unnecessary work and many more reports that will be subject to submission and even further review as we move into the future. However, by not being totally clear on the wording within the report, it will cause the potential of unintended consequences and since we have already experienced such problems, we believe the report should be modify to assure the a lay person truly understands the meaning. When you present information that leads to more questions, and interpretations, you spend more time explaining you position. This takes away from reliability and may cause more harm than good. As you are asked when testifying "tell the truth, the whole truth, and nothing but the truth", and by doing so, you leave the reader with true meaning. 2. Gerry Beckerle SERC a. Without seeing the amended wording, I am changing my vote and abstaining.

8 Exhibit D 3. Keith Carman Cooperative Utility In regards to the FRI item, I must vote No, for the reasons communicated during the webinar. Specifically, the recommendation to study RAS schemes is misleading. This scheme along with all other schemes have already been studied, this recommendation as worded leads one to conclude that this scheme has not been studied, that is simply not true. Additionally, the largest resource loss discussion in the report is incorrect. The report is to identify the largest resource loss in the last 10 years but what has been identified is an event where multiple losses have been added together. It is misleading and impractical to plan the system for this unreasonable contingency. 4. Michael Goggin Small End-Use Electricity Customer I vote no on approving the FRI report, and yes on the other two items. My reasons for voting no on the frequency report are as follows, and I hope that these can be addressed: a. Page 1, Intro: The first paragraph is confusing, implying that renewables are a major source of FR concerns. As NERC has made clear in previous filings ( _Tech_Conf.pdf), the observed decline in frequency response has not been caused by the introduction of renewable resources, but has in fact been overwhelmingly caused by changes in the operation of conventional generators. I suggest removing the first two sentences and the last sentence of the first paragraph. b. Page 3, Ex Sum: It is unclear whether the recommendations for Existing generator fleet are envisioned applying to existing wind and solar resources, or if wind and solar resources are only included in the recommendations for Other frequency-responsive resources. If wind generators are envisioned being included in the Existing generator fleet category, the recommendations for that category would be a source of concern. Recommendations not featured prominently in report, but should be: a. Discussions at the NERC FR technical conferences focused heavily on the point that a solution to FR needs should be market-based, to take advantage of the fact that different resources have widely different costs for providing frequency response. This should be discussed in the report. b. Discussions at the NERC FR technical conferences also focused on the concern that Energy Imbalance penalties are needlessly discouraging sustained frequency response by imposing penalties on resources that exceed scheduled set-points by providing frequency response, thus encouraging generator owners to set their generator controls so that they

9 Exhibit D do not provide sustained frequency response. This should be discussed in the report. 5. Martin Huang BC Hydro No (same reasons as provided by WECC)

10 Frequency Response Initiative Report The Reliability Role of Frequency Response Operating Committee October 10, Background 1

11 3 Background Frequency Response Initiative launched in 2010 To coordinate analysis and support for FR activities IFRO section of report in September 2011 was: Presented to PC and approved Presented to OC and discussed, along with RS paper on FR FRI Report requested by NERC management when request for extension on BAL 003 in May Report History and Action Plan FRI Report was reviewed by: SAMS in August rough draft presented at meeting, IFRO methods highlighted g (originally assigned to TIS by PC in 2011) FRRSDT Several times in August and September Work reported out to RS over last year FRI Report was presented to PC at Sept meeting Approved by PC on yes, 1 no, 1 abstention Response will be published for comments made during vote Report is on MRC/BOT agenda for approval/acceptance 2

12 5 Relation to BAL Standard IFROcalculation methodology has been adopted by FRRSDT for use in BAL FRRSDT did NOT adopt recommendation to use linear regression to measure BA performance under BAL Referenced in background materials to BAL Recommendations 3

13 7 Recommendations 1. Develop Frequency Response Resource Guidelines to define the performance characteristics expected Existing Conventional Generator Fleet o o o o o ±16.67 mhz deadbands 3% to 5% droop depending on turbine type Continuous, proportional (non step) implementation Appropriate operating modes to provide primary frequency response Appropriate outer loop controls modifications to avoid withdrawal 8 Recommendations Other Frequency Responsive Resources to augment response with high speed energy injection from electronically coupled coupled loads and resources o o o o Contractual high speed demand side response Wind and photo voltaic particularly for over frequency response Storage automatic high speed energy retrieval and injection Variable speed drives non critical, short time load reduction 4

14 9 Governor Deadband Settings z) Deadband Setting (mhz <500 MW MW >1000 MW <500 MW MW >1000 MW <500 MW MW >1000 MW East West Texas Unit Size 10 ERCOT Frequency Profile January through September of each Year One Minute Occurances

15 11 ±0.036 Hz Vs ±0.016 Hz Deadband MW Minute Movement of a 600 MW 5% Droop MW Response of db 25.78% Decrease in MW movement with lower deadband MW Response of db MW MW Response of db 2010 MW Response RELIABILITY of ACCOUNTABILITY db Recommendations 2. Base calculation margins for Interconnection Frequency Response Obligations (IFROs) on statistical analysis of frequency and performance 3. Starting Frequency 5% quantile of frequency, assuring 95% of all frequency events should start above this point Based on 2 to 3 years of 1 second data (34 to 91 Million seconds sampled) Value Eastern Western ERCOT Québec Starting Frequency (F Start )

16 13 IFRO Tenets 1. Should not trigger first stage of regionally approved UFLS Systems 2. Unavoidable local tripping of first stage UFLS systems for locally severe frequency excursions Protracted faults Systems on edge of the interconnection 3. Some frequency sensitive loads may trip 4. Other frequency sensitivities may be impacted Inverters tested trip at 59.4 Hz instead of 59.2 Hz specified in IEEE Standard 1547 Electronically coupled loads with frequency sensitivities 14 Recommendations 4. Regionally approved UFLS should not trip for frequency events in the interconnection Recommended Starting Frequencies for IFRO calculations Interconnection Highest UFLS Trip Frequency Eastern 59.5 Western 59.5 ERCOT 59.3 Québec

17 15 Adjustment for Point C (CC Adj ) 5. Adjustment for differences between 1 second data and sub second measurements for Point C Statistically determined Interconnection Number of Samples Mean Standard Deviation CC ADJ (95% Quantile) Eastern Western ERCOT Québec 0 N/A N/A N/A 16 Adjustment for C to B Ratio 6. Adjustment for differences between 1 second data and sub second measurements for Point C (CB R ) Statistically determined Interconnection Number of Samples Mean Standard Deviation CB R (95% Quantile) Eastern (0.989) 1 Western ERCOT Québec 2 N/A

18 17 Recommendations 7. Adjustment to the maximum allowable delta frequency to compensate for predominant withdrawal ( Lazy L )of primary frequency response Value A HZ ΔF = Hz FR = 1,312 MW/0.1 Hz Value B Hz Point C 18 Recommendations 8. Recommended Determination of Maximum Delta Frequencies Eastern Western ERCOT Québec Units Starting Frequency Hz Minimum Frequency Limit Hz Base Delta Frequency Hz 1 CC ADJ N/A Hz Delta Frequency (DF CC ) Hz 2 CB R Hz Delta Frequency (DF CBR ) Hz 6 BC ADJ.018 N/A N/A N/A Hz Max. Delta Frequency Hz 9

19 19 Recommendations 9. Recommended IFRO Determination Eastern Western ERCOT Québec Units Starting Frequency Hz Max. Delta Frequency Hz Resource Contingency Protection Criteria 4,500 2,740 2,750 1,700 MW Credit for LR 300 1,400 MW IFRO 1 1, MW/0.1Hz Absolute Value of IFRO 1, MW/0.1Hz % of Current Interconnection 40.6% 71.2% 48.7% 23.9% Performance 2 % of Interconnection Load % 0.56% 0.45% 0.50% 20 Table 16 (now 15) Updates Largest Event Eastern Western ERCOT Québec Units Starting Frequency Hz Max. Delta Frequency Hz Resource Contingency Protection Criteria 4,500 5,000 3,400 1,700 MW Credit for LR 300 1,400 MW IFRO 1 1,002 1, MW/0.1Hz Absolute Value of IFRO 1,002 1, MW/0.1Hz % of Current Interconnection 40.6 % % 72.2 % 23.9 % Performance 2 % of Interconnection Load % 1.16 % 0.66 % 0.50 % 10

20 21 Table 19 (now 18) Updates IFRO Calc. Comparison Current Interconnection Frequency Response Performance Eastern Western ERCOT Québec Units 2,467 1, N/A MW/0.1Hz Largest N 2 Event Resource Loss Criteria 3,854 2,740 2,750 1,700 MW IFRO MW/0.1Hz IFRO as % of Current Performance 34.8% 71.2% 48.7% 23.9% IFRO as % of Load % 0.56% 0.45% 0.50% Largest Total Plant with Common Voltage Switchyard Resource Loss Criteria 3,524 3,575 2,750 1,700 MW IFRO 785 1, MW/0.1Hz IFRO as % of Current Performance 31.8% 95.6% 48.7% 23.9% IFRO as % of Load 0.13% 0.76% 0.45% 0.50% Largest Resource Event in Last 10 Years Resource Loss Criteria 4,500 5,000 3,400 1,700 MW IFRO 1,002 1, MW/0.1Hz IFRO as % of Current Performance 40.6% 146.0% 72.2% 23.9% IFRO as % of Load 0.17% 1.16% 0.66% 0.50% 22 Recommendations 10. NERC/WECC should analyze frequency response implications of 3,200 MW of generation tripped by remedial action scheme (RAS). 11. Frequency Response sustainability should be measured and tracked by observing frequency between T+45 seconds and T+180 seconds. 12. Frequency Response performance by Balancing Authorities should not be judged for compliance on a per event basis. 11

21 23 Recommendations 13. Linear Regression should be used for calculating Balancing Authority Frequency Response Measure (FRM). 14. NERC should annually review the process for detection of frequency events, interconnection methods for calculation of Values A, B, and C, and calculation of IFROs. Strive to continually improve process 24 Recommendations 15. NERC should improve understanding of the role of generator governors through seminars and webinars ongoing basis. 16. Eastern Interconnection IFRO should be analyzed with dynamic analysis when improved governor models become available. 17. Eastern Interconnection inter area oscillatory behavior should be further investigated by NERC, including during the testing of large resource loss analysis for IFRO validation. 12

22 25 Questions? 26 ERCOT Experience with Governor Settings 13

23 27 Deadbands in ERCOT Initially specified ±36 mhz deadbands (prior to 2010) Allowed stepped response at deadband Resulted in a flat frequency response for small disturbances Resulted in generators trying to respond by larger amounts when deadband was crossed Resulted in less stable operation when near boundary conditions of deadbands 28 ERCOT Frequency Profile January through September of each Year One Minute Occurances

24 29 ± 36 mhz Deadband Step Response Capability (MW) Frequency Response Deadband Setting Hz MW Change Step response at deadband Hz 30 ± 16.6 mhz Deadband No Step Response Capability (MW) Frequency Response Deadband Setting Hz MW Change No step response at deadband Hz 15

25 31 Deadbands in ERCOT Moving to ±16.67 mhz deadbands (1 rpm on a 3,600 rpm machine) Continuous proportional response (no step) atdeadband Results in a improved frequency response for small disturbances Results in generators responding more often in smaller increments Saves wear and tear on turbines Results in more stable operation when near boundary conditions of deadbands 32 ±0.036 Hz Vs ±0.016 Hz Deadband MW Minute Movement of a 600 MW 5% Droop MW Response of db 25.78% Decrease in MW movement with lower deadband MW Response of db MW MW Response of db 2010 MW Response RELIABILITY of ACCOUNTABILITY db

26 33 Frequency Response Performance 34 Concerns Raised 4,000 3,500 Source : J. Ingleson & E. Allen, "Tracking the Eastern Interconnection Frequency Governing Characteristic" presented at 2010 IEEE PES. Source : Daily Automated Reliability Reports * * 1999 Data Interpolated MW / 0.1 Hz 3,000 2,500 Initial projections based on historical data 2,000 1,500 1,000 Year 17

27 35 Updated EI Frequency Response 4,000 3,500 3,000 Eastern Interconnection Mean Frequency Response * Source : J. Ingleson & E. Allen, "Tracking the Eastern Interconnection Frequency Governing Characteristic" presented at 2010 IEEE PES. Source : Reliability Metrics Working Group * 1999 Data Interpolated MW / 0.1 Hz 2,500 Change in Value A & B Calculation Method 2,000 1,500 1,000 Year 36 Frequency Response Concerns Reductions to system inertia particularly at light load periods Change in resource mix electronically coupled resources Displacement of frequency responsive generation in light load dispatch Withdrawal of primary frequency response Worse in Eastern Interconnection Attempt to get ahead of situation BEFORE it becomes a problem! 18

28 37 1,711 MW Loss Sat 3:30 pm EDT Value A HZ ΔF = Hz FR = -2,369 MW/0.1 HZ Vl Value B Hz 38 1,049 MW Trip Sun 11:20 pm EDT Value A HZ ΔF = Hz FR = -1,312 MW/0.1 HZ Value B Hz 19

29 39 Eastern Interconnection Simulations 40 Generic Simulations 3,700 MW Resource Loss 1,400 MW/0.1 Hz Response 59.7 Hz Lower Squelch Higher Squelch 59.5 Hz 20

30 NERC Operating Committee Frequency Response Report Vote Date 10/10/2012 Name of Report FRI Report ` 1 = present, 0 = absent Sector PC Member Proxy Member Present Votes Present Vote Vote Total Chairman Tom Bowe 1 1 YES 1 Vice Chairman Jim Castle 1 1 YES 1 Investor Owned Utility Jim Case 1 1 YES 1 Investor Owned Utility Paul Johnson 1 1 YES 1 State/Municipal Doug Peterchuck 1 1 YES 1 State/Municipal Richard Kinas 1 1 YES 1 Cooperative Keith Carman 1 1 NO 0 Cooperative Chris Bolick 1 1 NO 0 Federal/Provincial Tom Irvine 1 1 YES 1 Federal/Provincial James Dalrymple 1 1 YES 1 Federal/Provincial Martin Huang 1 1 NO 0 Federal/Provincial Pierre Paquet 1 1 YES 1 Transmission Dependent Utility Dennis Florom 1 1 YES 1 Transmission Dependent Utility Ray Phillips 1 1 YES 1 Electricity Marketer Vacant Electricity Marketer Vacant Merchant Electricity Generator JT Thompson 1 1 NO 0 Merchant Electricity Generator Vacant Small End Use Electricity Customer Michael Goggin 1 1 NO 0 Small End Use Electricity Customer Kevin Conway 1 1 NO 0 Large End Use Electricity Customer John Anderson Large End Use Electricity Customer Vacant ISO/RTO Bruce Rew 1 1 YES 1 ISO/RTO David Zwergel 1 1 YES 1 RRO ERCOT Alan Bern YES 0.29 RRO FRCC Ron Donahey RRO MRO Lloyd Linke YES 0.29 RRO NPCC Jerry Mosier YES 0.29 RRO RFC Jacquie Smith YES 0.29 RRO SERC Gerry Beckerle ABSTAIN 0.00 RRO SPP Jim Useldinger YES 0.29 RRO WECC Jerry Rust NO 0.00 State Government Vacant State Government Jerry Murray Members Present Votes Present Vote Total Quorum Reached Yes Totals Quorum for meeting Quorum for vote Approved Yes Page 1 of 1

31 NERC Operating Committee ALR Definition Vote Date 10/10/2012 Name of Report ALR Definition ` 1 = present, 0 = absent Sector PC Member Proxy Member Present Votes Present Vote Vote Total Chairman Tom Bowe 1 1 YES 1 Vice Chairman Jim Castle 1 1 YES 1 Investor Owned Utility Jim Case 1 1 NO 0 Investor Owned Utility Paul Johnson 1 1 NO 0 State/Municipal Doug Peterchuck 1 1 YES 1 State/Municipal Richard Kinas 1 1 YES 1 Cooperative Keith Carman 1 1 YES 1 Cooperative Chris Bolick 1 1 YES 1 Federal/Provincial Tom Irvine 1 1 YES 1 Federal/Provincial James Dalrymple 1 1 YES 1 Federal/Provincial Martin Huang 1 1 YES 1 Federal/Provincial Pierre Paquet 1 1 YES 1 Transmission Dependent Utility Dennis Florom 1 1 YES 1 Transmission Dependent Utility Ray Phillips 1 1 YES 1 Electricity Marketer Vacant 0 0 Electricity Marketer Vacant Merchant Electricity Generator JT Thompson 1 1 YES 1 Merchant Electricity Generator Vacant Small End Use Electricity Customer Michael Goggin 1 1 YES 1 Small End Use Electricity Customer Kevin Conway 1 1 YES 1 Large End Use Electricity Customer John Anderson Large End Use Electricity Customer Vacant ISO/RTO Bruce Rew 1 1 YES 1 ISO/RTO David Zwergel 1 1 YES 1 RRO ERCOT Alan Bern YES 0.29 RRO FRCC Ron Donahey RRO MRO Lloyd Linke YES 0.29 RRO NPCC Jerry Mosier YES 0.29 RRO RFC Jacquie Smith YES 0.29 RRO SERC Gerry Beckerle YES 0.29 RRO SPP Jim Useldinger YES 0.29 RRO WECC Jerry Rust YES 0.29 State Government Vacant 0 0 State Government Jerry Murray Members Present Votes Present Vote Total Quorum Reached Yes Totals Quorum for meeting Quorum for vote Approved Yes Page 1 of 1

32 Exhibit G Project Cold Weather Preparedness Unofficial SAR Comment Form Please DO NOT use this form for submitting comments. Please use the electronic form to submit comments on the SAR. The electronic comment form must be completed by 8 p.m. ET October 24, If you have questions please contact Howard Gugel at howard.gugel@nerc.net or by telephone at Project Project Page Background Information Repeated occurrences of generation shortfall in winter weather conditions in the southern United States, indicate that institutionalization of extreme weather preparation and reporting of generation availability is needed. During the 2011 SW Cold Weather event, load shed was required to meet the demand due to loss of generation. During this weather event, cold weather conditions froze critical plant instrument sensors and equipment, causing generation to trip offline or not be able to come online to generate electricity when it was critically needed. Simultaneously, BAs and TOPs were basing their operations and operations planning on uncertain generation availabilities and capacities from the GO/GOPs, because the data available to them did not include availability based on severe winter weather. This uncertain information caused the BAs and TOPs to over-estimate the available generation, which resulted in the need to use load shedding to balance the actual available generation and load. Based on the FERC-NERC report of the Southwest Cold Weather Event of February 1-5, 2011, in many cases, generation plants did not effectively utilize their cold weather maintenance practices that were in place to reliably perform under severe winter weather conditions. During the critical load time, many plants were in the mode of having to unfreeze equipment and make weatherproofing modifications in real time to keep plant equipment from freezing or refreezing. This subsequently caused generation to not be available during critical peak times, causing the GO/GOPs, BAs and TOPs to be unaware of the state of the generation resources. The FERC-NERC report concluded there would be a reliability benefit from amending the EOP Reliability Standards to require Generator Owner/Operators to develop, maintain, and implement plans to winterize

33 plants and units prior to extreme cold weather, in order to maximize generator output and availability. The SAR is being posted for a 30-day comment period through October 24, 2012 to gather additional input from the industry. You do not have to answer all questions. Enter all comments in plain text format. Bullets, numbers, and special formatting will not be retained. Questions To require GO/GOPs to report generating unit capabilities based on anticipated winter weather using criteria developed by the standard drafting team using stakeholder input. GO/GOPs must ensure winter weather preparation plans are created, maintained, implemented and monitored as appropriate to help ensure generating units can operate to the criteria developed above. The plans shall include appropriate annual winterization measures. 1. Do you agree with this scope? If not, please explain. Yes No Comments: Cold weather events are one example of ambient conditions under which BES components (lines, relaying, breakers, transformers and generators) must perform. GO/GOPs should know and communicate the capabilities of the generating units under their authority. While load is intended to be served almost all the time, there are going to be points in time during which not all load can be served while maintaining real-time reliability. The grid and those generators that are connected to it and operating at the time of a power system disturbance must be protected without fail. NERC standards do not assign the responsibility to serve all firm load - all the time to any entity. Fundamentally, doing so would be in opposition to EPAct of 2005 s prohibition against FERC / ERO passing adequacy standards. Adequacy regulations remain under the authority of the States. In regulated states, the state utilities commission sets expectations for utilities in planning to serve firm load. In deregulated states, the market operator sets the compensation mechanism for generators, and market operators should address the cost of winterization into their market rules, based on the expectations the state utilities commission has of the market operator for serving firm load. In Unofficial SAR Comment Form: Project Cold Weather Preparedness 2

34 deregulated states, generators will weigh the benefit of any winterization project against the cost to implement. The benefit must be weighed with the likelihood of occurrence of an extreme weather event. In the event that initiated this NERC effort, the cold weather with high winds experienced then had last struck the Texas area about twenty years ago. It is illogical for a generator owner to invest money in a project today when the project becomes useful only once in twenty years. Reasonably, the market operator would develop a compensation mechanism for assuring that generators would be available under certain stressful climatic conditions. While there may be some mechanism of this kind developed as a compromise position, it is also illogical for a market operator to cause an investment of this kind by generator owners since it has such a poor return on investment for the ratepayers. Winterization of power plants is a complex undertaking. 1. The design basis for power plants is different in different climates. Power plants are designed to meet highly probable local climatic conditions. Plants in northern parts of North America are typically constructed with closed turbine buildings and extensive cold weather mitigation plans, procedures and apparatus. Plants in southern areas of North America have the opposite problem of prolonged high heat in summer. These plants are typically constructed with open turbine buildings. For example, if one owns an automobile in northern areas of North America, an engine block heater is required to be plugged in over-night if the driver expects to be able to crank the engine after a cold night. Yet, in the south, engine block heaters are almost unknown, due to the differing climate in the south. Just as there is no national standard for engine block heaters, there should not be a national standard for design or winterization of power plants. 2. Typically, a new plant is designed and constructed, but the actual capability of the new plant in cold weather is not known until it experiences a significant period of cold/windy weather. The actual performance of such a plant before the first such cold weather event is unknowable (many of the systems and much of the equipment is embedded deeply within structural components, making direct testing highly impractical.) The Texas event had several relatively new generators affected by this phenomenon. The first such event in the life of a power plant tends to expose weak points, which are then addressed based on cost-benefit analyses. In open turbine buildings across the south, various temporary measures are taken when extreme cold is forecasted, such as erecting temporary wind breaks and adding temporary portable heaters. Over time, best practices have emerged that are simple enough to be executed when a period of extreme cold weather is forecasted. These are typically shared among plants Unofficial SAR Comment Form: Project Cold Weather Preparedness 3

35 operated by a single entity. The Generator Forum may be the best entity to pursue development of continental winterization best practices. Notwithstanding the above, BAs with load obligations should understand the capabilities of generators that contribute to meeting their next-day and current day loads under the ambient conditions expected for those peak periods. GO/GOPs are currently responsible to (1) determine and (2) provide this information to the TOPs. The GO currently must comply with Determine : FAC R1. The Transmission Owner and Generator Owner shall each document its current methodology used for developing Facility Ratings (Facility Ratings Methodology) of its solely and jointly owned Facilities. The methodology shall include all of the following: R Design criteria (e.g., including applicable references to industry Rating practices such as manufacturer s warranty, IEEE, ANSI or other standards). R Ambient conditions. R Operating limitations.. And Provide Information : FAC R1. The Transmission Owner and Generator Owner shall each establish Facility Ratings for its solely and jointly owned Facilities that are consistent with the associated Facility Ratings Methodology. R2. The Transmission Owner and Generator Owner shall each provide Facility Ratings for its solely and jointly owned Facilities that are existing Facilities, new Facilities, modifications to existing Facilities and re-ratings of existing Facilities to its associated Reliability Coordinator(s), Planning Authority(ies), Transmission Planner(s), and Transmission Operator(s) as scheduled by such requesting entities. There appears to be a gap related to BAs, in that Generator Owners are not required by FAC R2 to convey this generation capability information to their host BA, although they are required to notify their TOP. We suggest that FAC R2 be revised to state: Unofficial SAR Comment Form: Project Cold Weather Preparedness 4

36 R2. The Transmission Owner and Generator Owner shall each provide Facility Ratings for its solely and jointly owned Facilities that are existing Facilities, new Facilities, modifications to existing Facilities and re-ratings of existing Facilities to its associated Reliability Coordinator(s), Planning Authority(ies), Transmission Planner(s), [Insert: Balancing Authority(ies)] and Transmission Operator(s) as scheduled by such requesting entities. 2. The SAR identifies a list of reliability functions that may be assigned responsibility for requirements in the set of standards addressed by this SAR. Do you agree with the list of proposed applicable functional entities? If no, please explain. Yes No Comments: We believe that the BA should be added to FAC R2. In addition, EOP b is applicable only to BAs and TOPs. Requirement R4 states: Each Transmission Operator and Balancing Authority shall include the applicable elements in Attachment 1-EOP-001 when developing an emergency plan. However, Attachment 1 EOP 001 includes elements that are only under the control of GOs and GOPs. These include: 1. Fuel supply and inventory An adequate fuel supply and inventory plan that recognizes reasonable delays or problems in the delivery or production of fuel. 2. Fuel switching Fuel switching plans for units for which fuel supply shortages may occur, e.g., gas and light oil. 10. Maximizing generator output and availability The operation of all generating sources to maximize output and availability. This should include plans to winterize units and plants during extreme cold weather. Even though R4 includes the word applicable, these elements only under control of GOs and GOPs are not aligned properly to TOPs and BAs. Rather, the GO and GOP should be added as applicable entities to EOP-001, as they are the entities in control of these elements of Attachment 1. We specifically do not endorse any significant expansion of this requirement beyond what is described above and we do not support any new proscriptive requirements for winterization due to the variety of approaches that are necessary across North America to address local weather extremes. Unofficial SAR Comment Form: Project Cold Weather Preparedness 5

37 3. Are you aware of any regional variances that will be needed as a result of this project? If yes, please identify the Regional Variance. Yes No Comments: This is not an area the fits well as a continental standard due to the differing climatic conditions faced by power plants in North America. We suggest no continental standard, as this is a localized issue regarding firm load, not an Interconnection issue. 4. Are you aware of any business practice that will be needed or that will need to be modified as a result of this project? If yes, please identify the business practice. Yes No Comments: As outlined in our comments above, Market Operators in deregulated states may need to review the qualification rules for generators to participate in the market. There may need to be a compensation mechanism developed for generators that are expected to operate without failure in an extreme cold weather event. 5. If you have any other comments on this SAR that you haven t already mentioned above, please provide them here. Comments: As stated above, this is a local load-serving issue, essentially a question of adequacy under extreme conditions, that properly belongs to the States, and should not be included in NERC standards. We support the collection and dissemination of generator winterization best practices by the appropriate groups. We firmly believe that no single continental standard is merited nor would it be useful in improving BES reliablity. Unofficial SAR Comment Form: Project Cold Weather Preparedness 6

38 NERC Operating Committee Cold Weather Preparedness Comments Vote Date 10/10/2012 Name of Report Cold Weather Preparedness Comments ` 1 = present, 0 = absent Sector PC Member Proxy Member Present Votes Present Vote Vote Total Chairman Tom Bowe 1 1 YES 1 Vice Chairman Jim Castle 1 1 YES 1 Investor Owned Utility Jim Case 1 1 YES 1 Investor Owned Utility Paul Johnson 1 1 YES 1 State/Municipal Doug Peterchuck 1 1 YES 1 State/Municipal Richard Kinas 1 1 YES 1 Cooperative Keith Carman 1 1 YES 1 Cooperative Chris Bolick 1 1 YES 1 Federal/Provincial Tom Irvine 1 1 YES 1 Federal/Provincial James Dalrymple 1 1 YES 1 Federal/Provincial Martin Huang 1 1 YES 1 Federal/Provincial Pierre Paquet 1 1 YES 1 Transmission Dependent Utility Dennis Florom 1 1 YES 1 Transmission Dependent Utility Ray Phillips 1 1 YES 1 Electricity Marketer Vacant 0 0 YES Electricity Marketer Vacant Merchant Electricity Generator JT Thompson 1 1 YES 1 Merchant Electricity Generator Vacant Small End Use Electricity Customer Michael Goggin 1 1 YES 1 Small End Use Electricity Customer Kevin Conway 1 1 YES 1 Large End Use Electricity Customer John Anderson Large End Use Electricity Customer Vacant ISO/RTO Bruce Rew 1 1 YES 1 ISO/RTO David Zwergel 1 1 YES 1 RRO ERCOT Alan Bern YES 0.29 RRO FRCC Ron Donahey RRO MRO Lloyd Linke YES 0.29 RRO NPCC Jerry Mosier YES 0.29 RRO RFC Jacquie Smith YES 0.29 RRO SERC Gerry Beckerle YES 0.29 RRO SPP Jim Useldinger YES 0.29 RRO WECC Jerry Rust YES 0.29 State Government Vacant 0 0 State Government Jerry Murray Members Present Votes Present Vote Total Quorum Reached Yes Totals Quorum for meeting Quorum for vote Approved Yes Page 1 of 1