Operating Committee - nerc.com Highlights and Minutes DL... · Operating Committee Conference Call and Webinar Minutes October 10, 2012 Jerry Mosier moved to approve the revised definition

Operating Committee Conference Call and Webinar Meeting Minutes October 10, 2012 | 1:00 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 email 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 email 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.

Operating Committee Conference Call and Webinar Minutes October 10, 2012

Jerry Mosier moved to approve the revised definition of Adequate Level of Reliability. By email ballot, the OC approved the motion (Exhibit F).

Project 2013‐01 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 email ballot, the OC approved the motion (Exhibit H).

Adjournment The conference call meeting was adjourned at 2:36 p.m. EDT on October 10, 2012.

Larry Kezele Larry J. Kezele Secretary

Direct Link to CLEAN Version: Frequency Response Initiative Report

Agenda Operating Committee October 10, 2012 | 1:00 p.m.–3:00 p.m. (EDT) Conference Dial In: 1-866-740-1260 Pass Code: 5247004 Security Code: 823234 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

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

Exhibit A

http://www.nerc.com/docs/pc/FRI%20Report%209-30-12%20Clean.pdf�

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EXHIBIT B

ATTENDEES Operating Committee

Conference Call and Webinar Meeting October 10, 2012

OFFICERS

Chair Tom Bowe Vice Chair Jim Castle Secretary and Staff Coordinator Larry Kezele

MEMBERS

VOTING MEMBERS Cooperative Chris Bolick

Keith Carman Electricity Marketer Federal/Provincial Tom Irvine

Martin Huang

Investor-Owned Paul Johnson Utility Jim Case ISO/RTO Bruce Rew David Zwergel Large End-use Customer State/Municipal Doug Peterchuck Transmission Richard Kinas Dependent Utility Merchant Generator State Government

VOTING MEMBERS (cont’d) Small End-use Kevin Conway Customer Michael Goggin TRE Alan Bern FRCC Ron Donahey MRO Lloyd Linke NPCC Jerry Mosier RFC Jacquie Smith SERC Gerry Beckerle WECC Don Badley proxy for

Jerry Rust SPP Jim Useldinger NON-VOTING MEMBER U.S. Federal Eddy Lim

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ATTENDEES — Operating Committee Meeting (cont’d) October 10, 2012

2

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

Exhibit C

Individual Statements Operating Committee Conference Call and Webinar Meeting October 10, 2012

There were none.

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Exhibit D

Minority Opinions Operating Committee Conference Call and Webinar Meeting October 10, 2012

1. 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 re-studying 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.

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 (http://www.nerc.com/files/FinalFile_Comments_Resp_to_Sept_Freq_Resp_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

http://www.nerc.com/files/FinalFile_Comments_Resp_to_Sept_Freq_Resp_Tech_Conf.pdf�

http://www.nerc.com/files/FinalFile_Comments_Resp_to_Sept_Freq_Resp_Tech_Conf.pdf�

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)

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1

Frequency Response Initiative ReportThe Reliability Role of Frequency Response

Operating CommitteeOctober 10, 2012October 10, 2012

2

Background

RELIABILITY | ACCOUNTABILITY

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Presentation 1

10/31/2012

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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 2012


4

Report History and Action Plan

• FRI Report was reviewed by:

SAMS in August – rough draft presented at meeting, IFRO methods highlighted (originally assigned to TIS by PC in 2011)g g ( g y g y )

FRRSDT – Several times in August and September

Work reported out to RS over last year

• FRI Report was presented to PC at Sept. 2012 meeting

Approved by PC on 10‐4‐12 – 16 yes, 1 no, 1 abstention

Response will be published for comments made during vote


p p g

• Report is on MRC/BOT agenda for approval/acceptance

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5

Relation to BAL-003-1 Standard

• IFRO calculation methodology has been adopted byIFRO calculation methodology has been adopted by FRRSDT for use in BAL‐003‐1

• FRRSDT did NOT adopt recommendation to use linear regression to measure BA performance under BAL‐003‐1

• Referenced in background materials to BAL‐003‐1


6

Recommendations


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7

Recommendations

1. Develop Frequency Response Resource Guidelines to define the performance characteristics expected

Existing Conventional Generator Fleet

o ±16.67 mHz deadbands

o 3% to 5% droop – depending on turbine type

o Continuous, proportional (non‐step) implementation

o Appropriate operating modes to provide primary frequency response

o 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 loads and resourceselectronically‐coupled loads and resources

o Contractual high‐speed demand‐side response

o Wind and photo‐voltaic – particularly for over‐frequency response

o Storage – automatic high‐speed energy retrieval and injection

o Variable speed drives – non‐critical, short‐time load reduction


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9

Governor Deadband Settings5402000700

300

350

400

z)

700

100

150

200

250

Dea

dban

d Se

tting

(mH

z


0

50

<500 MW 500-1000MW

>1000 MW <500 MW 500-1000MW

>1000 MW <500 MW 500-1000MW

>1000 MW

East West Texas

Unit Size

10

ERCOT Frequency Profile

35000

40000January through September of each Year

10000

15000

20000

25000

30000

One

Min

ute

Occ

uran

ces

RELIABILITY | ACCOUNTABILITY10

0

5000

10000

59.9

59.9

159

.92

59.9

359

.94

59.9

559

.96

59.9

759

.9859

.99 60

60.0

160

.02

60.0

360

.0460

.05

60.0

660

.07

60.0

860

.09

60.1

O

2010 2008

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6

11

±0.036 Hz Vs ±0.016 Hz Deadband

120000

140000

545670.0

404989.0 2010 MW Response of 0.0166 db 25.78% Decrease in MW movement with lower deadband.

2008 MW Response of 0.036 db

MW Minute Movement of a 600 MW Unit @ 5% Droop

40000

60000

80000

100000

MW

p


0

20000

59.9

59.9

159

.9259

.9359

.9459

.9559

.9659

.9759

.9859

.99 60

60.0

160

.0260

.0360

.0460.0

560

.0660

.0760

.0860

.09

60.1

2008 MW Response of 0.036 db 2010 MW Response of 0.0166 db

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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 d l d)


seconds sampled)

Value Eastern Western ERCOT Québec

Starting Frequency (FStart) 59.974 59.976 59.963 59.972

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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 58.5

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15

Adjustment for Point C (CCAdj )

5. Adjustment for differences between 1‐second data and sub‐second measurements for Point C

Statistically determined

Interconnection Number

of Samples

Mean Standard Deviation

CCADJ (95% Quantile)

Eastern 30 0.0006 0.0038 0.0068


Western 17 0.0012 0.0019 0.0044

ERCOT 58 0.0021 0.0061 0.0121

Québec 0 N/A N/A N/A

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Adjustment for C to B Ratio

6. Adjustment for differences between 1‐second data and sub‐second measurements for Point C (CBR )

Statistically determined

Interconnection Number

of Samples

Mean Standard Deviation

CBR (95% Quantile)

Eastern 41 0.964 0.0149 1.0 (0.989)1

Western 30 1 570 0 0326 1 625


Western 30 1.570 0.0326 1.625

ERCOT 88 1.322 0.0333 1.377

Québec2 N/A 1 1.550

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Recommendations

7. Adjustment to the maximum allowable delta frequency to compensate for predominant withdrawal (“Lazy L”)of primary frequency response

Value A60.026 HZ


ΔF = 0.0799 HzFR = ‐1,312 MW/0.1 Hz

Value B59.946 Hz Point C’

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Recommendations

8. Recommended Determination of Maximum Delta Frequencies

Eastern Western ERCOT Québec Units

Starting Frequency 59.974 59.976 59.963 59.972 Hz

Minimum Frequency Limit

59.500 59.500 59.300 58.500 Hz

Base Delta Frequency 0.474 0.476 0.663 1.472 Hz

CCADJ1 0.007 0.004 0.012 N/A Hz

Delta Frequency (DFCC) 0.467 0.472 0.651 1.472 Hz

CBR2 1.0003 1.625 1.377 1.5504 Hz


Delta Frequency (DFCBR)

5 0.467 0.291 0.473 0.949 Hz

BC’ADJ6 .018 N/A N/A N/A Hz

Max. Delta Frequency 0.449 0.291 0.473 0.949 Hz

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19

Recommendations

9. Recommended IFRO Determination


Starting Frequency 59 974 59 976 59 963 59 972 HzStarting Frequency 59.974 59.976 59.963 59.972 Hz


Resource Contingency Protection Criteria

4,500 2,740 2,750 1,700 MW

Credit for LR – 300 1,400 – MW

IFRO1 ‐1,002 ‐840 ‐286 ‐179 MW/0.1Hz

Absolute Value of IFRO

1,002 840 286 179 MW/0.1Hz

% f C


% of Current Interconnection Performance2

40.6% 71.2% 48.7% 23.9%

% of Interconnection Load3

0.17% 0.56% 0.45% 0.50%

20

Table 16 (now 15) Updates


Starting Frequency 59.974 59.976 59.963 59.972 Hz

M D lt F 0 449 0 291 0 473 0 949 H

Largest Event


Resource Contingency Protection Criteria

4,500 5,000 3,400 1,700 MW

Credit for LR 300 1,400 MW

IFRO1 ‐1,002 ‐1,721 ‐423 ‐179 MW/0.1Hz

Absolute Value of IFRO

1,002 1,721 423 179 MW/0.1Hz


% of Current Interconnection Performance2

40.6 % 146.0 % 72.2 % 23.9 %

% of Interconnection Load3

0.17 % 1.16 % 0.66 % 0.50 %

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Table 19 (now 18) Updates Eastern Western ERCOT Québec Units

Current Interconnection Frequency Response Performance

‐2,467 ‐1,179 ‐586 N/A MW/0.1Hz

Largest N‐2 Event

IFRO Calc. Comparison

Resource Loss Criteria 3,854 2,740 2,750 1,700 MW

IFRO ‐858 ‐840 ‐286 ‐179 MW/0.1Hz

IFRO as % of Current Performance 34.8% 71.2% 48.7% 23.9%

IFRO as % of Load1 0.14% 0.56% 0.45% 0.50%

Largest Total Plant with Common Voltage Switchyard


IFRO ‐785 ‐1,127 ‐286 ‐179 MW/0.1Hz



IFRO as % of Load 0.13% 0.76% 0.45% 0.50%

Largest Resource Event in Last 10 Years


IFRO ‐1,002 ‐1,716 ‐423 ‐179 MW/0.1Hz


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.

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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.

10/31/2012

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25

Questions?


26

ERCOT Experience with Governor Settings


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14

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


amounts when deadband was crossed

• Resulted in less stable operation when near boundary conditions of deadbands

28

ERCOT Frequency Profile

35000

40000January through September of each Year

10000

15000

20000

25000

30000

One

Min

ute

Occ

uran

ces


0

5000

10000

59.9

59.9

159

.92

59.9

359

.94

59.9

559

.96

59.9

759

.9859

.99 60

60.0

160

.02

60.0

360

.0460

.05

60.0

660

.07

60.0

860

.09

60.1

O

2010 2008

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29

Frequency Response

150.00

Deadband Setting

Hz

600.000Capability (MW)

0.036

± 36 mHz Deadband – Step Response

0.00

50.00

100.00

MW

Cha

nge

Step response at deadband.


-150.00

-100.00

-50.00

59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50

Hz

deadband.

30

Frequency Response

150.00

Deadband Setting

0.0166 Hz

600.000Capability (MW)

± 16.6 mHz Deadband – No Step Response

0.00

50.00

100.00

MW

Cha

nge

No step response at


-150.00

-100.00

-50.00

59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50

Hz

p pdeadband.

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31

Deadbands in ERCOT

• Moving to ±16.67 mHz deadbands (1 rpm on a 3,600 rpm machine)

• Continuous proportional response (no step) at deadband• Continuous proportional response (no step) at deadband

• Results in a improved frequency response for small disturbances

• Results in generators responding more often in smaller i


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

120000

140000

545670.0

404989.0 2010 MW Response of 0.0166 db 25.78% Decrease in MW movement with lower deadband.

2008 MW Response of 0.036 db

MW Minute Movement of a 600 MW Unit @ 5% Droop

40000

60000

80000

100000

MW

p


0

20000

59.9

59.9

159

.9259

.9359

.9459

.9559

.9659

.9759

.9859

.99 60

60.0

160

.0260

.0360

.0460.0

560

.0660

.0760

.0860

.09

60.1

2008 MW Response of 0.036 db 2010 MW Response of 0.0166 db

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33

Frequency Response Performance


34

3,500

4,000

* * 1999 Data Interpolated

Source 1994-2009: J. Ingleson & E. Allen, "Tracking the Eastern Interconnection Frequency Governing Characteristic" presented at 2010 IEEE PES.

Source 2010-2011: Daily Automated Reliability Reports

Concerns Raised

2,000

2,500

3,000

MW

/ 0.

1 H

z

Initial projections based on historical data


1,000

1,500

Year

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35

3,500

4,000

* 1999 Data Interpolated

Source 1994-2009: J. Ingleson & E. Allen, "Tracking the Eastern Interconnection Frequency Governing Characteristic" presented at 2010 IEEE PES.

Source 2009-2011: Reliability Metrics Working Group

Updated EI Frequency Response

Eastern Interconnection Mean Frequency Response

2,000

2,500

3,000

MW

/ 0.

1 Hz

*

Change in Value A & B Calculation Method


1,000

1,500

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!

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371,711 MW Loss – Sat 3:30 pm EDT

Value A60 021 HZ

ΔF = 0.0722 HzFR = -2,369 MW/0.1 HZ

60.021 HZ

V l B


Value B59.948 Hz

381,049 MW Trip – Sun 11:20 pm EDT

Value A60 026

ΔF = 0.0799 HzFR = -1,312 MW/0.1 HZ

60.026 HZ


Value B59.946 Hz

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20

39

Eastern Interconnection Simulations


40Generic Simulations

3,700 MW Resource Loss1,400 MW/0.1 Hz Response

59.5 Hz

59.7 Hz

Lower Squelch

Higher Squelch


NERC Operating Committee Frequency Response Report Vote

Date 10/10/2012

Name of Report FRI Report `

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


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 0 0 0

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 1 0.29 YES 0.29

RRO‐FRCC Ron Donahey 0 0.00 0.00

RRO‐MRO Lloyd Linke 1 0.29 YES 0.29

RRO‐NPCC Jerry Mosier 1 0.29 YES 0.29

RRO‐RFC Jacquie Smith 1 0.29 YES 0.29

RRO‐SERC Gerry Beckerle 1 0.29 ABSTAIN 0.00

RRO‐SPP Jim Useldinger 1 0.29 YES 0.29

RRO‐WECC Jerry Rust 1 0.29 NO 0.00

State Government Vacant

State Government Jerry Murray 0 0 0

Members Present Votes Present Vote Total

15.33

14.00

Quorum Reached Yes 14.45

1 = present, 0 = absent

Totals

Quorum for meeting

Quorum for voteApproved Yes

26 21

Page 1 of 1

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Exhibit E

NERC Operating Committee ALR Definition Vote

Date 10/10/2012

Name of Report ALR Definition `




Investor Owned Utility Jim Case 1 1 NO 0

Investor Owned Utility Paul Johnson 1 1 NO 0



Cooperative Keith Carman 1 1 YES 1

Cooperative Chris Bolick 1 1 YES 1



Federal/Provincial Martin Huang 1 1 YES 1




Electricity Marketer Vacant 0 0


Merchant Electricity Generator JT Thompson 1 1 YES 1


Small End‐Use Electricity Customer Michael Goggin 1 1 YES 1

Small End‐Use Electricity Customer Kevin Conway 1 1 YES 1










RRO‐SERC Gerry Beckerle 1 0.29 YES 0.29


RRO‐WECC Jerry Rust 1 0.29 YES 0.29

State Government Vacant 0 0



15.33

14.00



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Project 2013-01 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, 2012. If you have questions please contact Howard Gugel at [email protected] or by telephone at 609-651-2269. Project 2013-01 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 weather-proofing 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

Exhibit G

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mailto:[email protected]�

http://www.nerc.com/filez/standards/Project2013-01_Cold_Weather.html�

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Unofficial SAR Comment Form: Project 2013-01 Cold Weather Preparedness 2

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


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


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-008-1 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:

…

R1.3.2. Design criteria (e.g., including applicable references to industry Rating

practices such as manufacturer’s warranty, IEEE, ANSI or other standards).

R1.3.3. Ambient conditions.

R1.3.4. Operating limitations.

….

And “Provide Information”: FAC-009-1

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-009-1 R2 to convey this generation capability information to their host BA, although they are required to notify their TOP. We suggest that FAC-009-1 R2 be revised to state:


“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-009-1 R2.

In addition, EOP-001-2.1b 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.


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.

NERC Operating Committee Cold Weather Preparedness Comments Vote

Date 10/10/2012

Name of Report

Cold Weather

Preparedness

Comments

`




Investor Owned Utility Jim Case 1 1 YES 1

Investor Owned Utility Paul Johnson 1 1 YES 1



Cooperative Keith Carman 1 1 YES 1

Cooperative Chris Bolick 1 1 YES 1



Federal/Provincial Martin Huang 1 1 YES 1




Electricity Marketer Vacant 0 0 YES


Merchant Electricity Generator JT Thompson 1 1 YES 1


Small End‐Use Electricity Customer Michael Goggin 1 1 YES 1

Small End‐Use Electricity Customer Kevin Conway 1 1 YES 1










RRO‐SERC Gerry Beckerle 1 0.29 YES 0.29


RRO‐WECC Jerry Rust 1 0.29 YES 0.29

State Government Vacant 0 0



15.33

14.00



Totals

Quorum for meeting


26 21

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Exhibit H

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Documents

Operating Committee - nerc.com Highlights and Minutes DL... · Operating Committee Conference Call and Webinar Minutes October 10, 2012 Jerry Mosier moved to approve the revised definition