EEA Workshop

April 22, 2014

2

Workshop Process

Dan Woodfin

3

• Workshop 1– Background on EEA

– Identify Issues

• Workshop 2– Options to Resolve Issues

– Consensus Items

– Future Activities

Workshop Process

4

Background on EEA

Stephen Solis

5

• Energy Emergency Alerts were first part of the NERC Operating Policies (Policy 5.C.)

• NERC Operating Policy 5.C. was transferred to EOP-002 as part of version 0 standards related to FERC Order 693 in 2007.

• Appendix 5C (Energy Emergency Alerts) of the NERC Operating Policy was also moved over as Attachment 1-EOP-002 as part of EOP-002.

NERC Standards

6

• Primary Applicable Standard in effect is EOP-002-3.1 Capacity and Energy Emergencies.

• EOP-001-2.1b is applicable to ensure appropriate plans are in place.

• EOP-003-2 is applicable related to load shed plans and actions for EEA3.

• EOP-004-2 is applicable related to required reporting.

NERC Standards

7

Single vs Multiple BA Interconnection

• EEA requirements are built around the concept of minimizing risk associated with a BA area “leaning” on another area in a multiple BA Interconnection.

• CPS and DCS criteria are measures that are expected to be met even during emergencies to minimize the risk on the Interconnection.

8

Multiple BA Interconnection• Area Control Error (ACE) has

an Interchange component• Frequency is supported by

remainder of Interconnection• Emergency status allows

additional transmission capacity by modifying transmission service priority

• Importance of reducing risk associated with “leaning” on other areas highlighted by requirement to shed load if CPS and DCS cannot be met.

9

Single BA Interconnection

• ACE does not have an interchange component, only frequency.

• Frequency is only supported by the single BA area.

• Transmission capacity is not reserved (ERCOT)

• No “leaning” risk, frequency preservation is priority.

• Frequency Responsive Reserves are more critical without additional BA’s support for disturbance.

10

Single vs Multiple BA Interconnection

• ERCOT is a single BA Interconnection.

• Frequency preservation and frequency responsive reserves are focus during an EEA in a single BA area.

11

Questions

12

Physical Responsive Capability (PRC) Calculation

Bill Blevins

13

Physical Responsive Capability (PRC) A representation of the total amount of system wide On-Line capability that has a high probability of being able to quickly respond to system disturbances.

1. Control room operators monitor PRC for determining OCN, Advisory, Watch and EEA

2. Currently PRC includes available capability from Online Generation, Loads Resources and Hydro units on Synchronous Condenser mode

3. PRC uses a Reserve Discount Factor (RDF) to account for effect of temperature on Generator Capability

4. Conventional Generation Resources and Controllable Load Resources maximum contribution to PRC is limited to 20% of their HSL*RDF Why 20%? The Generator with a governor droop setting of 5% will provide

20% of its HSL as Governor Response if Frequency drops to 59.40 Hz from 60.00 Hz.

5. Hydro Resources operating under synchronous condenser fast response mode can contribute their full HSL*RDF towards PRC

6. Non-Controllable Load Resources providing RRS is 100% counted towards PRC.

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Physical Responsive Capability (PRC)

The ERCOT-wide Physical Responsive Capability (PRC) calculated as follows:

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Physical Responsive Capability (PRC)

16

Changes to PRC in near Future1. Once NPRR-573 is implemented, Wind Generation

Resources that are Primary Frequency Response capable will be contributing to the PRC. Maximum contribution from WGRs will also be limited to 20% of their HSL.

2. Once NPRR-555 is implemented Controllable Load Resource (CLR) that are active in SCED will also be contributing to PRC. Maximum contribution from CLR will also be limited to 20% of their net telemetered consumption.

3. Once recently approved NPRR-598 is implemented, Generation Resources telemetering ONTEST, STARTUP or SHUTDOWN Resources Status will be excluded from PRC calculation.

Questions?

18

Current Procedures and Triggers

Colleen Frosch

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Preliminary Actions

20

EEA Steps

Maintain 2,300 MW of on-line reserves1

2

3

Maintain 1,750 MW of on-line reserves. Interrupt loads providing Responsive Reserve Service. Interrupt loads providing Emergency Response Service (ERS).

Maintain System frequency at or above 59.8 Hz and instruct TSPs and DSPs to shed firm load in rotating blocks.

EEA procedure in the ERCOT Protocols defined by levels

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ERCOT shall:

• Notify the Southwest Power Pool Reliability Coordinator;

• Request available Generation Resources that can perform within the expected timeframe of the emergency to come On-Line by initiating manual HRUC or through Dispatch Instruction;

• Use available DC Tie import capacity not already being used;

• Issue a Dispatch Instruction for Resources to remain On-Line which, before start of emergency, were scheduled to come Off- Line; and

• At ERCOT’s discretion, deploy available contracted ERS-30. June – September weather-sensitive ERS is available.

EEA Level 1 – Maintain a total of 2,300 MW of PRC

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QSEs shall:

• Ensure COPs and telemetered HSLs are updated and reflect all Resource delays and limitations; and

• Suspend any ongoing ERCOT required Resource performing testing.

EEA Level 1 – Maintain a total of 2,300 MW of PRC

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• TO Load Management Program

– Deploy all available capacity from their Load Management Programs

– Only applies June through September

– Currently 5 TOs participate

EEA Level 1 – Maintain a total of 2,300 MW of PRC

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In addition to the measures associated with EEA Level 1, ERCOT shall take the following steps:

•Instruct TSPs and DSPs or their agents to:– reduce Customers’ Load by using distribution voltage reduction

measures, if deemed beneficial by the TSP, DSP, or their agents.

•Instruct QSEs to deploy:– available contracted ERS-10 Resources– RRS supplied from Load Resources (controlled by high-set

under-frequency relays).

ERCOT may deploy ERS-10, ERS-30, or RRS simultaneously or separately, and in any order. June – September Weather-Sensitive ERS is available.

EEA Level 2 – Maintain 60 Hz or 1,750 of PRC

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• In addition to measures associated with EEA Levels 1 and 2, ERCOT will direct all TSPs and DSPs or their agents to shed firm Load, in 100 MW blocks, as documented in the Operating Guides in order to maintain a steady state system frequency of 59.8 Hz.

• In addition to measures associated with EEA Levels 1 and 2, TSPs and DSPs or their agents will keep in mind the need to protect the safety and health of the community and the essential human needs of the citizens. Whenever possible, TSPs and DSPs or their agents shall not manually drop Load connected to under-frequency relays during the implementation of the EEA.

EEA Level 3 – Maintain 59.8 Hz or greater

Questions?

27

History of EEA

Bill Blevins

28

Objectives

• Summarize EEA historical information• Discuss recent weather challenges • Identify variables leading to EEAs

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History of Energy Emergencies

Note EECP was converted to EEA in after 2008EEA2A and EEA2B were combined into EEA 2 after 2011

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31

• Example

• 2010

• 2011

• 2014

Sudden Unit Trip

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EEA-1 May 15th 2010

Executive Summary At 16:13:49 on May 15th, 2010, Unit A tripped causing the loss of 815 MW. One minute and 18 seconds later, Unit B tripped causing the loss of 745 MW of generation, for a total of 1560 MW. ERCOT ISO frequency initially dropped to 59.71 Hz immediately after the Unit A trip at 16:13:49. System Frequency recovered to 59.76 Hz before Unit B tripped at 16:15:07. As a result of the trip of Unit B the frequency dropped to 59.69 Hz. This dip below 59.7 Hz caused a total of 1111.8 MW of Responsive Reserve, in the form of Load acting as Resource (LaaR), to be automatically deployed. In addition to the LaaRs, 1152 MW of Generation Responsive Reserve was deployed from the 3484 MW of Adjusted Responsive Reserve available at the beginning of the event.  ERCOT ISO Operators recognized that this was not a NERC Disturbance Control Standard (DCS) event as the two trips occurred more than 1 minute apart and were considered separate contingencies. At 16:30 ERCOT implemented Level 1 of its Energy Emergency Alert (EEA). EEA Level 1 was declared due to the ERCOT Adjusted Responsive Reserve (ARR) dropping below 2300 MW. ERCOT deployed 1107 MW of Non-Spin Reserve Service (NSRS) at 16:45. EEA Level 1 was cancelled at 17:00.The following operations report discusses primary and contributing factors leading up to and during the EEA event and action items that ERCOT has taken in response to the event.

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EEA-1June 23 2010

Executive Summary At 15:19:54 on June 23rd, 2010, Unit A at the 138 kV Station A tripped causing the loss of approximately 733 MW of generation due to the failure of the main power transformer high side ‘C’ phase disconnect switch.  At the same time, Circuit breakers CB1 and CB2 tripped at the 345 kV Station A. This opened one end of the 345 kV line from Station A to Station B, isolating 482 MW of generation output of units B, C and D at Station B and these units tripped approximately nine seconds later. Also, Unit E tripped at Station C causing the loss of 38 MW, for a total of 1253 MW.  Two 138 kV lines opened and automatically reclosed from Station A-Station D and Station A-Station E with no impact. ERCOT ISO PI Data shows the frequency dropped to 59.709 Hz immediately after the trip at 15:19:54. After the event, frequency recovered within 6 minutes and 32 seconds to its pre-disturbance value of 59.98 Hz at 15:26:26 and within 14 minutes and 22 seconds to 60 Hz at 15:34:16.  ERCOT ISO Operators responded to this event as a NERC Disturbance Control Standard (DCS) event by instructing Load acting as Resource (LaaRs) providing Responsive Reserve Service to deploy.  1150 MW of Generation Responsive Reserve was deployed (from 3281 MW of Adjusted Responsive Reserve (ARR) available). These reserves were deployed at the beginning of the event, along with approximately 246 MW of LaaRs, which tripped on under-frequency relay action. An additional 571 MW of LaaRs were deployed with VDIs between 15:31 and 15:34. A total of 817 MW of LAARs were deployed. Frequency recovered to 60 Hz at 15:34:16.  At 15:35 ERCOT implemented Level 1 of its Energy Emergency Alert (EEA). EEA Level 1 was declared because ERCOT’s ARR dropped below 2300 MW. ERCOT deployed 522 MW of Non-Spin Reserve Service (NSRS) at 15:45:09. By 15:48:12 ARR was above 2300 MW. At 16:00 all QSEs were instructed to restore all LAARs deployed. An additional 525 MW of NSRS was deployed at 16:00:07 for a total of 1047 MW. EEA Level 1 was cancelled at 16:03.

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EEA-1August 20 2010

Executive Summary At approximately 15:25:48 on August 20th, 2010, unit A at the 345 kV Station A tripped causing the loss of approximately 1319 MW of generation in the Houston area due to an inadvertent turbine trip signal initiated during planned surveillance testing.  Approximately eight seconds later, unit B at the 138 kV Station B tripped offline. At approximately 15:31:56 unit C tripped, and at approximately 15:32:36 unit D tripped. The total loss of generation from this west Texas plant was approximately 212 MW.  ERCOT ISO Operations responded to this event as a NERC Disturbance Control Standard event; however it should be excluded from compliance evaluation for being larger than the single largest contingency event. ERCOT ISO historical (PI) data indicates that frequency dropped to approximately 59.749 Hz immediately after the first trip of unit A. The system frequency recovered to 60 Hz in approximately 4 minutes and 42 seconds (~15:30:30). ERCOT ISO recovered from the frequency deviation as required by the NERC Reliability Standard BAL-002-0. At 15:25:48, 1150 MW of Generation Responsive Reserve was deployed due to the low frequency. These reserves were deployed at the beginning of the event, along with approximately 20 MW of Load acting as Resources (LaaRs), which tripped on under-frequency relay action. At 15:28 ERCOT ISO requested all Qualified Schedule Entities (QSE) to deploy all remaining LaaRs scheduled to provide Responsive Reserve Service. A total of 1320 MW of LaaRs were deployed.  At 15:41, all QSEs were instructed to restore LaaRs. Non-Spinning Reserve Service (NSRS) was deployed at 15:44 in the Houston zone for interval ending 16:15, and 15:45 in the South, North and West zones for interval ending 16:30. ERCOT ISO implemented Level 1 of its Energy Emergency Alert (EEA) at 15:48 due to Adjusted Responsive Reserve (ARR) dropping below 2300 MW. By 16:13:38, ARR was above 2300 MW and EEA Level 1 was cancelled at 16:35. The following operations report discusses primary and contributing factors leading up to and during the EEA event and action items that ERCOT has taken in response to the event.

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June 27th 2011 EEA - Frequency

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June 27th 2011 EEA – Physical Responsive Capability

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EEA-1Jan 18 2014

Executive Summary The morning of January 18, 2014, ERCOT entered into emergency operations. This was the result of a Disturbance Control Standard (DCS) qualifying event which occurred at approximately 08:41. Nuke unit X tripped, resulting in approximately 1237 MW of energy being lost to the grid shortly after the morning peak.

When the unit tripped, nearly 1000 MW of Physical Responsive Capability (PRC) was lost, as PRC dropped from approximately 3300 MW to 2300 MW in approximately 90 seconds. At approximately 08:47 ERCOT declared a Watch for PRC below 2500 MW, and then at approximately 09:02 ERCOT declared Emergency Energy Alert (EEA) Level 1 for PRC below 2300 MW.

Off-Line Non-Spin was deployed between 08:44 and 10:18. Responsive Reserve Service (RRS) from generators was also deployed as a result of the unit trip. Given that system frequency reached approximately 59.699 Hz, approximately 850 MW of RRS from Load Resources was provided from under-frequency relays. PRC was below 2300 MW for approximately 30 minutes, below 2500 MW for approximately 38 minutes, and below 3000 MW for approximately 50 minutes.

At approximately 09:47 ERCOT exited EEA level 1 due to improving conditions, and resumed normal operations. No firm load shed actions were taken.

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• Example

• 2011

• 2014

Large Cap Unavail due to Forced Outage and Derate

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February 1, 2011

The Coldest Week for North Texas in 22 Years

February 2, 2011Winter Returns with Fury

Extremely Cold Weather Grips Texas

A record-breaking arctic front was approaching prior to February 2, 2011

The arctic cold front that descended on the Southwest during the first weekof February 2011 was unusually severe in terms of temperature, wind, andduration of the event. In many cities in the Southwest, temperatures remained below freezing for four days, and winds gusted in places to 30 mph or more. The geographic area hit was also extensive, complicating efforts to obtain power and natural gas from neighboring regions.The storm, however, was not without precedent. There were prior severe cold weather events in the Southwest in 1983, 1989, 2003, 2006, 2008, and 2010. The worst of these was in 1989, the prior event most comparable to 2011.

February 1, 2011

Major Winter Storm Expected

to Develop Over Texas

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More than 8,000 megawatts (MW) of generation unexpectedly dropped offline overnight

40,000

45,000

50,000

55,000

60,000

65,000

MW

Time

Committed Generation vs. Committed Generation minus Forced Outages on February 2, 2011

Committed Generation Committed Generation minus Forced Outages

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The ERCOT System responded as expected Feb 2nd 2011

59.45

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

HZ

Frequency vs. Load Shed

Frequency

Load Resources Shed @ 5:20

1,000 MW Firm Load Shed and Emergency Interruptible Load @ 5:44

1,000 MW Firm Load Shed @ 6:04

2,000 MW Firm Load Shed @ 6:23

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5:20am5:08am

1,804 MW Non-Spin deployed Restored 500 MW

Restoration Complete

A timeline of the emergency steps that were taken leading to rotating outages in ERCOT Feb 2nd 2011

Issued Watch

Reserves below 2,500 MW

Issued EEA 2A

•Reserves below 1,750 MW

•Load Resources deployed

Issued EEA 3

•EILS deployed

•Firm Load Shed 1,000 MW

7:57am

Restored 500 MW (3,500 MW out)

8:22am

Restored 500 MW (3,000 MW out)

9:25am

Restored 500 MW (2,500 MW out)5:43am

6:04am

Firm load shed 1,000 MW (2,000 MW total)

6:05am

Frequency 59.576Hz

6:23am

Firm Load Shed 2,000 MW

(4,000 MW total)

6:59am

Media Appeal issued

Move to EEA 2B

From EEA 3

New winter Peak Record

56,480 MW

2:01pm

11:39amRestored 500 MW (2,000 MW out)12:04pmRestored 500 MW (1,500 MW out)12:25pmRestored 500 MW (1,000 MW out)12:49pmRestored 500 MW (500 MW out)

Load Resources Recalled

Move to EEA 2A

From EEA 2B

3:14pm

4:30am 1:07pm

1:57pm

7:15pm

FEB 2 FEB 3, 10 AM EEA 2A ENDS & EILS RECALLED

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Event Summary – January 6, 2014

• At 6:52, ERCOT declared Level 1 of its Energy Emergency Alert (EEA) and declared EEA Level 2 at 7:01, primarily due to the loss of a number of generating units

• Non-Spin Reserve Service (NSRS), Load Resources (LR) and Emergency Response Service (ERS) were deployed, but firm load shed was not required

• ERCOT moved from EEA2 to EEA1 at 7:51 and resumed normal operations at 9:12

• Generation outages & derates peaked at 9355 MW just before 07:00, with 3541 MW due to weather

• Hourly peak demand was 55,487 MW for HE08 and instantaneous peak demand was 56,478 MW at 07:08:24

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07:51 AMERCOT recalled EEA Level 2. EEA Level 1 remains in effect07:56 AMERCOT recalled 30 minute ERS07:58 AMERCOT recalled 10 minute ERS.

ERCOT deployed RRS to Generators for frequency below 59.91 Hz

06:37 AM 06:52 AM

ERCOT deployed Non-Spin for 187 MW

ERCOT deployed Group 1 RRS for 546.36 MW

07:43 AMERCOT recalled all Group 2 RRS07:50 AMERCOT recalled all Group 1 RRS

06:42 AM 09:12 AM

07:02 AMERCOT deployed 30 minute ERS for 111.68 MW07:05 AMERCOT deployed 10 minute ERS for 508.72 MW07:13 AMERCOT recalled all RRS from Generators due to frequency above 59.91 Hz

06:57 AM

Watch terminated as PRC was above 3000 MW

09:55 AM

Watch issued due to PRC below 2500 MW

ERCOT issued EEA Level 2 for PRC below 1750 MW

ERCOT deployed Group 2 RRS for 536.24 MW

ERCOT issued EEA Level 1 for PRC below 2300 MW

06:52 AM 07:01 AM

EEA Level 1 cancelled. Watch remains in effect.

08:10 :36 AMERCOT recalled all Non-Spin08:10:48 AMERCOT deployed RRS to Generators for frequency below 59.91 Hz08:17 AMERCOT recalled all RRS from Generators due to frequency above 59.91 Hz

06:42 AM

Timeline – January 6, 2014 EEA

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Reserves

46

• Example

• 2011

High Summer Demand

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August 2011Sunday Monday Tuesday Wednesda

yThursday

Friday Saturday

31 1 2

EEA 13

EEA 14

EEA 2B

5

EEA 16

7 8 9 10 11 12 13

14 15 16 17 18 19 20

21 22 23

EEA 124

EEA 2A25 26 27

28 29 30 31 1 2 3

2011 High Load Summer Energy Emergency Alerts

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August 2011 Peak Loads

8/3: Record Peak

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ERCOT Load, Wind, and PRC 8/4/2011 12:00–24:00

50

• Example

• Feb 26, 2008

Wind Forecast/Ramp

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EECP Feb 26 2008 Issues identified in March 17 Wind Workshop

Wind Output, T wo Wind P ower F orec as ts , and Day-Ahead R es ourc e P lan MW for 2/26/08

0

500

1000

1500

2000

2500

3000

3500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hour E nding

MW

Hour Aver. ActualO utput

* 50% Wind P owerF orecas t

* 80% Wind P owerF orecas t

R es ource P lan MWfrom WGR s inDay-Ahead

MAP E50% WP F : 20.80%80% WP F : 25.32%

52

Summary of some issues noted back in Zonal system related to Wind issues from 2008

• ERCOT offsets for known differences in actual output and scheduled output

• Resource Plan errors can cause the hour ahead study to indicate capability that is not available.– Resource Plans and Schedules should be updated often with the

latest and best information• Deployments for Wind Resources should be considered from actual

output and not scheduled output.• Abrupt generation changes tax regulation and adversely affect

frequency.• ERCOT should consider a ramp rate limit requirement for following

deployment instructions. For example a 5% limit for a 500 MW unit would mean the unit should not ramp faster than 25 MW/min.

• Implement an ERCOT wide forecast for wind and require this to be used for Resource Plans

53

• Example

• April 17, 2006

Unseasonable Weather during maint. season

54

Load Forecast Issues 04-17-06

• Load forecast was lower than actual loads– Peak load would have been ~ 53,817 MW if load had not been

interrupted (actual was 51,613 MW)

– All-time April peak was 49,280 MW in late April 2002

– April 17 Peak Load forecasts• 49,018 MW @16:00 April 16• 49,591 MW @01:00 April 17• 51,114 MW @13:00 April 17

• Why?– Temperature forecast for DFW area was 5° low (95° vs 100°)

• Accounts for about 1,000 - 1,500 MW error

– Parameter set incorrectly to adjust for past actual loads (fixed)

– Low load forecast for Coast (Houston) area (under investigation)

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Resource Plan/Available Capacity Issues 04-17-06

• The Resource Plan used for the 13:00 April 17 Replacement Study showed 55,283 MW of maximum generating capacity on-line at peak– Operator saw no problem meeting 51,114 MW forecast– Would have been enough to cover 53,817 MW load plus

1,150 Responsive Reserve on units, but not by much– Judgment call on whether to call an Alert if forecast had

been 53,817 MW

• However, Resource Plans at 13:00 for peak hour:– Showed 793 MW that had tripped before 13:00 or was

started late (after 16:00)– Included 1,683 MW capacity that tripped between 15:51 and

16:17

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What if? 04-17-06

• Peak load forecast used for the 16:00 April 16 Replacement Study had been 53,817 MW instead of 49,018 MW– An additional 1,026 MW of capacity off-line at peak April 17

would have been procured– Given actual unit trips, would have still been in EECP– Might have avoided Step 4, but would have been close

• Units had not tripped or started late– Might have avoided EECP altogether, but would have been

close

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• 2006 EECP4 http://www.ercot.com/content/meetings/ros/keydocs/2006/0515/Review_of_EECP_Event_050806_jd.ppt • 2008 Wind http://www.ercot.com/calendar/2008/03/20080317-WIND • 2010 http://www.ercot.com/content/meetings/ros/keydocs/2010/0610/06._

ERCOT_OPERATIONS_REPORT_EEA_051510_Public.doc • http://www.ercot.com/content/meetings/ros/keydocs/2010/0715/07._

ERCOT_OPERATIONS_REPORT_EEA_Level_1_062310_public_rev3.doc • http://www.ercot.com/content/meetings/ros/keydocs/2010/0916/06._

ERCOT_OPERATIONS_REPORT_EEA_Level_1_082010_public.doc • 2011• http://www.ercot.com/content/news/presentations/2011/Senate_EEA_Presentationfinaltg.pdf• http://www.ercot.com/content/meetings/ros/keydocs/2011/0915/05._ERCOT_Operations_Report_EEA_Events_080211-

080511_public.doc • http://www.ercot.com/content/meetings/ros/keydocs/

2011/0915/05._ERCOT_Operations_Report_EEA_August_23_24_Public.doc • 2014• http://www.ercot.com/content/meetings/ros/keydocs/2014/0306/07._Jan_6_EEA_ROS_Report.ppt• http://www.ercot.com/content/committees/board/keydocs/2014/ERCOT_Monthly_Operational_Overview_201401.pdf

Reference ERCOT reports

Questions?

59

Current Ancillary Services

Bill Blevins

60

Ancillary Service

A service necessary to support the transmission of energy to Loads while maintaining reliable operation of the Transmission Service Provider’s (TSP’s) transmission system using Good Utility Practice. Following are the Ancillary Service capacity products within ERCOT:

1.Responsive Reserve Service

2.Regulation Service

3.Non-Spinning Reserve Service

61

Responsive Reserve Service

An Ancillary Service that provides operating reserves that is intended to:

1.Arrest frequency decay within the first few seconds of a significant frequency deviation on the ERCOT Transmission Grid using Primary Frequency Response and interruptible Load;

2.After the first few seconds of a significant frequency deviation, help restore frequency to its scheduled value to return the system to normal;

3.Provide energy or continued Load interruption during the implementation of the EEA; and

4.Provide backup regulation.

62

Responsive Reserve Service

1. RRS may be provided through one or more of the following means:

a) By using frequency-dependent response from On-Line Resources as prescribed in the Operating Guides to help restore the frequency within the first few seconds of an event that causes a significant frequency deviation in the ERCOT System; and

b) Either manually or by using a four-second signal to provide energy on deployment by ERCOT

2. RRS Service may be used to provide energy during the implementation of an EEA. Under the EEA, RRS provides generation capacity, capacity from Controllable Load Resources or interruptible Load available for deployment on ten minutes’ notice.

63

Responsive Reserve Service

RRS Service may be provided by:

1.Unloaded, On-Line Generation Resource capacity;

2.Load Resources controlled by high-set, under-frequency relays;

3.Controllable Load Resources;

4.Hydro Responsive Reserves as Synchronous Condenser Fast Response Mode; and

5.Direct Current Tie (DC Tie) response that stops frequency decay as defined in the Operating Guides.

64

Responsive Reserve Service

Responsive Reserve (RRS) Service is a service used to restore or maintain the frequency of the ERCOT System:

1. In response to, or to prevent, significant frequency deviations;

2. As backup Regulation Service; and

3. By providing energy during an Energy Emergency Alert (EEA):• When PRC < 1750 MW or unable to maintain system

frequency at 60 Hz;• RRS from Generation Resources is deployed automatically at

59.91 Hz as calculated from the EMS

65

Regulation Service

1. An Ancillary Service that consists of either Regulation Down Service (Reg-Down) or Regulation Up Service (Reg-Up)An Ancillary Service that provides capacity that can respond to signals from ERCOT within five seconds to respond to changes in system frequency.

2. Fast Responding Regulation Service (FRRS) A subset of Regulation Service that consists of either Fast Responding Regulation Down Service (FRRS-Down) or Fast Responding Regulation Up Service (FRRS-Up):a)Provides Reg-Up capacity to ERCOT within 60 cycles of either its receipt of an ERCOT Dispatch Instruction or

b)Its detection of a trigger frequency independent of an ERCOT Dispatch Instruction.

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Regulation Service

1. ERCOT methodology aims to procure enough regulation so that regulation is not exhausted more than 1.2% of the time

2. Greater of the adjusted 98.8th percentile deployed regulation value from the previous year and the 98.8th percentile value from the previous 30 days is used to determine the initial requirement

3. During the previous 30 days, if the exhaustion rate of Regulation significantly exceeded the desired 1.2% for any hour, additional MWs are added for that hour in order to achieve 1.2%

4. ERCOT will add incremental MWs to Regulation to account for increased installed wind capacity

5. ERCOT will also procure additional Regulation during hours in which CPS1 scores are not above the desired threshold of 100%

67

Non-Spin Service Deployment

ERCOT may deploy Non-Spin, which has not been deployed as part of a standing On-Line Non-Spin deployment, under the following conditions:

1.When (HASL – Gen) – (30-minute load ramp) < 0 MW, deploy half of the available Non-Spin capacity.2.When (HASL – Gen) – (30-minute load ramp) < -300 MW, deploy all of the available Non-Spin capacity.3.When PRC < 2500 MW, deploy all of the available Non-Spin capacity.4.When the North-to-Houston (N_H) Voltage Stability Limit Reliability Margin < 300 MW, deploy Non-Spin (all or partial) in the Houston area as needed to restore reliability margin.5.When Off-Line Generation Resources providing Non-Spin are the only reasonable option available to the Operator for resolving local issues, deploy available Non-Spin capacity on only the necessary individual Resources.

Note : On-line Non-Spin capacity always remains available for SCED to dispatch.http://www.ercot.com/content/mktrules/guides/procedures/Non-Spinning%20Reserve%20Service%20Deployment%20and%20Recall%20Procedure.zip

68

Ancillary Service Deployment

NSPIN

RRS

RGU

RGD

GEN

LASL – Low Ancillary Service Limit

HSL – High Sustainable Limit

HASL – High Ancillary Service Limit

LSL – Low Sustainable Limit

SCED ROOM

Capacity Reserved

for AS

Regulation deployed every 4 seconds to balance generation with load

Capacity reserved by generator for Non-Spin and Responsive to be released to SCED when deployed by ERCOT

• SCED dispatches generation between HASL and LASL (SCED Room).

• Resource not providing AS:

- HASL = HSL

- So SCED can dispatch the unit up to HSL

• Resource providing AS:- HASL= HSL – RGU- RRS – NSPIN- Resource reserves part of the capacity for providing

AS (makes capacity unavailable for SCED)- Regulation is deployed as needed every 4 seconds to

maintain balance between generation and load- Responsive reserve and Non-spin are deployed when

required and the capacity reserved by the resource for RRS and NSPIN is released SCED to be economically dispatched

- RRS MWs are offered at the System Wide Offer Cap (Currently $5,000 will be $7000 beginning June 1, 2014)

- Non-Spin MWs has to be offered at a minimum of $120 for Online NSRS or $180 for offline NSRS (once NPRR 576 is effective, NSRS has to be offered ≥ $75)

Questions?

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Managing Constraints in EEA

Chad Thompson

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Background

• NPRR480 removed overarching language that allowed ERCOT to “relax” transmission constraints during emergency operations

• During recent EEA events, some generation has been limited as a result of binding constraints in SCED

• A mechanism is needed to allow generation capacity to be available to SCED during emergency operations in a manner that does not reduce transmission reliability

• The following slides apply only to those constraints that may limit generation

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NPRR480 Removed Language

• 6.5.9.1 Emergency and Short Supply Operation, (3) “…Under an Emergency Condition, the ERCOT Operator may relax transmission constraints to provide additional generation at the expense of temporarily creating a security violation as long as the violation does not physically overload any single Transmission Element above its emergency limit, as defined in the ERCOT Operating Guides...”

• Rationale– Attachment 1-EOP-002-2 of NERC Reliability

Standard EOP-002-3 does not support the relaxation of constraints during EEA

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Re-Evaluation

• Attachment 1-EOP-002 has provisions during EEA2 that allows the RC to review its SOLs and IROLs through consultation with the impacted BA and Transmission Provider about the possibility of revising SOLs

• During EEA3 there is a provision to revise SOLs and IROLs as allowed by the BA or TOP whose equipment is at risk, subject to considerations outlined in Attachment 1

• BUT, it does not say that the RC can stop managing congestion on the grid

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Attachment 1 - EOP-002-3

• 2.4 Evaluating and mitigating transmission limitations– The Reliability Coordinators shall review all System Operating

Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs) and transmission loading relief procedures in effect that may limit the Energy Deficient Entity’s scheduling capabilities. Where appropriate, the Reliability Coordinators shall inform the Transmission Providers under their purview of the pending Energy Emergency and request that they increase their ATC by actions such as restoring transmission elements that are out of service, reconfiguring their transmission system, adjusting phase angle regulator tap positions, implementing emergency operating procedures, and reviewing generation redispatch options.

• 2.4.4 Initiating inquiries on reevaluating SOLs and IROLs– The Reliability Coordinators shall consult with the Balancing

Authorities and Transmission Providers in their Reliability Areas about the possibility of reevaluating and revising SOLs or IROLs.

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Attachment 1 - EOP-002-3

• 3.4 Reevaluating and revising SOLs and IROLs– The Reliability Coordinator of the Energy Deficient Entity shall evaluate the risks of

revising SOLs and IROLs on the reliability of the overall transmission system. Reevaluation of SOLs and IROLs shall be coordinated with other Reliability Coordinators and only with the agreement of the Balancing Authority or Transmission Operator whose equipment would be affected. The resulting increases in transfer capabilities shall only be made available to the Energy Deficient Entity who has requested an Energy Emergency Alert 3 condition. SOLs and IROLs shall only be revised as long as an Alert 3 condition exists or as allowed by the Balancing Authority or Transmission Operator whose equipment is at risk. The following are minimum requirements that must be met before SOLs or IROLs are revised:

• 3.4.1 Energy Deficient Entity obligations– The deficient Balancing Authority or Load Serving Entity must agree that, upon

notification from its Reliability Coordinator of the situation, it will immediately take whatever actions are necessary to mitigate any undue risk to the Interconnection. These actions may include load shedding.

• 3.4.2 Mitigation of cascading failures– The Reliability Coordinator shall use its best efforts to ensure that revising SOLs or

IROLs would not result in any cascading failures within the Interconnection.

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Re-Evaluation

• What does this mean?– ERCOT has the ability to change the SOLs it

controls to during EEA3, after consultation (presumably which occurred before, or during EEA2) with the impacted transmission companies

– The SOLs utilized must not result in cascading failures or otherwise jeopardize safety or public well-being

– ERCOT cannot simply “stop constraining” because the generation behind a constraint is being limited

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Re-Evaluation

• What about CMPs?– CMPs should continue to be developed and

utilized when applicable; however the necessary review time is generally longer than what may be available during an EEA

– In general, CMPs are developed day-ahead or earlier, and while some TOAPs are developed in real-time, analysis and implementation of CMPs during EEA conditions may not be attainable in the timeframe of the EEA

– Constraints that limit generation tend to be getaway issues where reducing generation is the only means for relieving the SOL

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Potential Topics for Discussion

• NPRR or NOGRR which provides a mechanism for utilizing the transmission system to its fullest extent during emergency operations in a manner that maximizes generation delivery without negatively impacting reliability– Interim solution would be operator procedure

modifications ahead of a market rules change– Mechanism cannot risk operators’ ability to

manage overall system reliability during EEA

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Potential Topics for Discussion

• During non-EEA Conditions– SCED used to manage congestion consistent with

current practices• During a Watch Condition for PRC below 2500

MW– SCED used to manage congestion consistent with

current practices– ERCOT and TOs evaluate both active and binding

constraints which ERCOT identifies as potentially limiting generation, and discuss the potential for operating to the 15-Minute Rating, if available, in the event ERCOT enters EEA3

– Recall outages associated with constraints that may be limiting generation, where possible

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Potential Topics for Discussion

• During EEA1 Conditions– SCED used to manage congestion consistent

with current practices– ERCOT and TOs review double-circuit

contingency impacts and consider use of single-circuit contingencies as alternates

• During EEA2 Conditions– SCED used to manage congestion consistent

with current practices

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Potential Topics for Discussion

• During EEA3 Conditions– ERCOT may control to a different facility rating,

(e.g. 15-Minute Rating) in SCED where appropriate, based on the results of the evaluation with TOs during the Watch, so long as control to the alternative facility rating does not result in any cascading failures or otherwise jeopardize safety or public well-being

– During transition from EEA3 back to EEA2 or EEA 1, ERCOT and TOs will revert back to “standard” congestion practices in a manner that supports reliability, coordinated by the ERCOT and TO System Operators

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Stability Limits and IROLs

• Management of stability limits and IROLs in SCED will not change during EEA conditions

Questions?

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Identify Issues

Chad Thompson

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Identify Issues

• HASL Release

• Constraint Management

• PRC As A Trigger

• Wind Variability

• Review Issues Identified During Workshop

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HASL Release

• Manual deployment of all RRS

• OBD Changes to Non-Spin deployment

• SCR to create an “EEA button” to automatically deploy all AS though the EMS

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PRC As A Trigger

• How we got to PRC– April 17 2006 & ARRS

• Why 2300 MW

• Should PRC be replaced with something else?– Should Load Resources & Synchronous

condensers be considered in the calculations?

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Wind Variability

• Consider turbine shut down temperatures in Wind Forecast

• “Icing Forecast?”

• Consider ramp event predictions in RUC Process

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Next Steps

Dan Woodfin