EEA Workshop 2 June 19, 2014

EEA Workshop 2

June 19, 2014

2

EEA Workshop 1 Recap

Dan Woodfin

3

Review of Current EEA Practices

Chad Thompson

4

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

EEA Levels and Triggers

• EEA 1– Request available Generation Resources

come on-line through manual HRUC or Dispatch Instructions

– Suspend any Resource testing– Obtain DC Tie Imports if available– If needed, deploy ERS-30– June – September Only

• Deploy weather sensitive ERS• Deploy available TO Load Management Programs


• EEA 2– Instruct TSPs & DSPs or their agents to use

voltage reduction measures, if available and beneficial

– Deploy ERS-10– Deploy RRS from Load Resources with high-

set under-frequency relays


• EEA 3– Direct TSPs & DSPs or their agents to shed

firm load in 100 MW blocks to maintain 59.8 Hz as documented in the Operating Guides

– 6.5.9.4 (8) indicates that ERCOT may immediately implement EEA 3 when steady-state frequency is 59.8 Hz, and shall implement EEA 3 when below 59.5 Hz

• Will be discussed later

EEA 1 Comparison

August 3 2011 VS. January 18 2014

•August 3 2011– Cause: diminishing reserves– PRC below 2300 MW for ~3 hours– Contingency Reserves (Non-Spin) deployed– Event Duration (PRC below 3000 MW): ~6

hours

EEA 1 Comparison

59.88

59.91

59.94

59.97

60

60.03

60.06

60.09

60.12

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

7,500

8,000

MW

PRC Non-Spin deployed 2,300 MW Frequency

HZ

EEA Level 1Declared

EEA Level 1Terminated

2,300

EEA 1 Comparison


•January 18 2014– Cause: Unit trip– PRC below 2300 MW for ~ 30 minutes– Frequency recovered in 45 seconds– Contingency Reserves deployed and quickly

recalled– Event Duration (PRC below 3000 MW): ~1

hour

EEA 1 Comparison

59.7

59.75

59.8

59.85

59.9

59.95

60

60.05

60.1

2000

2300

2600

2900

3200

3500

3800

4100

4400

07:00 07:30 08:00 08:30 09:00 09:30 10:00 10:30

Freq

uenc

y (H

z)

Phys

ical

Res

pons

ive

Capa

bilit

y (M

W)

Time (HH:MM)

Physical Responsive Capability and FrequencyJanuary 18 2014

Physical Responsive Capability Frequency

EEA 1 Declared EEA 1 Terminated

EEA 1 Comparison


•Observations:– The August 2011 event was a true capacity

shortage condition• Low capacity, sufficient frequency-responsive MW

– The January 2014 event was a short-duration, system recovery to a disturbance condition

• Sufficient capacity, low frequency-responsive MW

EEA 1 Comparison


•Observations:– During the January 18 2014 event, PRC dipped

below 2300 MW twice. Load Resources have 3 hours to come back when recalled, and if the LRs had restored sooner, the second drop may have been avoided.

• Similarly, if another disturbance had occurred during this event, there may not have been enough frequency-responsive reserves for that next contingency

14

Dynamic Simulation

Fred Huang

• NERC Requirement– BAL-003-1– BAL-001-2

• Dynamic Assessment

• Responsive Reserve Service Study

Outline

• Effective Date: R1 (4/1/2016), R2-R4 (4/1/2015)

• Interconnection Frequency Response Obligation (IFRO)– ERCOT: 413 MW/0.1 Hz,

http://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/FR%20Annual%20Report%2012-27-13%20Final.pdf

• Resource Contingency Criteria (RCC) is the largest category C (N-2) event. – ERCOT: 2,750 MW

• One of the needs is to prevent UFLS first step

• From ERCOT’s perspective:– No firm Under Frequency Load Shed (UFLS) following RCC

NERC BAL-003-1

• Adopted by the NERC Board of Trustees on August 15, 2013

• Requirement R2: Average of ACE does not exceed its Balancing Authority ACE Limit (BAAL) for more than 30 minutes– ERCOT Interconnection

• Low Frequency Trigger Limit = 59.91 Hz• High Frequency Trigger Limit = 60.09 Hz

NERC BAL-001-2

2013 Net Load (GW)

• ERCOT performed a frequency response assessment for the selected system conditions for the Future Ancillary Service framework.

Frequency Response Test

*PRC: Physical Responsive Capability**Wind Penetration = Wind output / Load***System Inertia (GW-second) = Sum of (Machine MVA * H) / 1,000

• Primary Frequency Response (PFR):– The immediate proportional increase or decrease in real

power output provided by a Resource and the natural real power dampening response provided by Load in response to system frequency deviations. This response is in the direction that stabilizes frequency.

• Fast Frequency Response (FFR):– A response from a resource that is automatically self-

deployed and provides a full response within 30 cycles after frequency meets or drops below a preset threshold.

– Two FFR subgroups: • FFR1: trigger frequency at 59.8 Hz• FFR2: trigger frequency at 59.7 Hz

• PFR and FFR help to stabilize the frequency but do not recover the frequency back to nominal frequency.

Definition

• Study Assumptions– Only PFR units provide governor response– Load damping is assumed as 2%/Hz– Two stages of FFR services at different frequency

threshold• FFR1: 59.8 Hz, FFR2: 59.7 Hz

• ERCOT Firm Under Frequency Load Shed Settings

Key Assumptions and Criteria

Frequency Threshold Load Relief59.3 Hz 5% of the ERCOT System Load (Total 5%) 58.9 Hz An additional 10% of the ERCOT System Load (Total 15%) 58.5 Hz An additional 10% of the ERCOT System Load (Total 25%)

• SC1: Only System Inertia (and natural load damping)

• SC2: Minimum PFR needs without FFR

• SC3: Frequency response at different PFR and FFR reserves under High Wind Low Load condition

• SC4: Under EEA 3 condition, frequency response with/without PFR after tripping one largest unit

Scenarios

Bus frequency (Hz)

Time (sec)

0 12 24 36 48 60 54.80

55.86

56.92

57.98

59.04

60.10

Bus frequency (Hz)

Time (sec)

0 12 24 36 48 60 54.80

55.86

56.92

57.98

59.04

60.10

Bus frequency (Hz)

Time (sec)

0 12 24 36 48 60 54.80

55.86

56.92

57.98

59.04

60.10

Bus frequency (Hz)

Time (sec)

0 12 24 36 48 60 54.80

55.86

56.92

57.98

59.04

60.10

Bus frequency (Hz)

Time (sec)

0 12 24 36 48 60 54.80

55.86

56.92

57.98

59.04

60.10

Bus frequency (Hz)

Time (sec)

0 12 24 36 48 60 54.80

55.86

56.92

57.98

59.04

60.10

SC1: No PFR, No FFR, Only System Inertia

SI (GW-second): 1 > 2 > 3

60.0 Hz60.0 Hz

54.8 Hz54.8 Hz

59.4 Hz59.4 Hz

Bus frequency (Hz)

Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.30

59.46

59.62

59.78

59.94

60.10Bus frequency (Hz)

Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.30

59.46

59.62

59.78

59.94


Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.30

59.46

59.62

59.78

59.94


Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.30

59.46

59.62

59.78

59.94


Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.30

59.46

59.62

59.78

59.94


Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.30

59.46

59.62

59.78

59.94

60.10

SC2: Minimum PFR Needs w/o FFR

PFR (MW): 3 > 2 > 1

Generation Trip: 2750 MWCase 1---: Net Load = 65 GW, PFR=1,300MWCase 2---: Net Load = 35 GW, PFR=2,500MWCase 3---: Net Load = 17 GW, PFR=4,700MW

60.0 Hz60.0 Hz

59.3 Hz59.3 Hz

SC3: PFR/FFR at HWLLBus frequency (Hz)

Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.40

59.54

59.68

59.82

59.96

60.10

Bus frequency (Hz)

Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.40

59.54

59.68

59.82

59.96

60.10

Bus frequency (Hz)

Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.40

59.54

59.68

59.82

59.96

60.10

Bus frequency (Hz)

Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.40

59.54

59.68

59.82

59.96

60.10

Bus frequency (Hz)

Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.40

59.54

59.68

59.82

59.96

60.10

Bus frequency (Hz)

Time (sec)

0.000 7.200 14.40 21.60 28.80 36.00 59.40

59.54

59.68

59.82

59.96

60.10

60.160.1

59.459.4

Case 3: Load = 25 GW, Wind = 7.2 GWDisconnect two STPsScenario 1---: PFR=1,400 MW, FFR(59.7Hz)=1,400MWScenario 2---: PFR=2,650 MW, FFR(59.7Hz)=900MWScenario 3---: PFR=4,700 MW, FFR(59.7Hz)=0MW

Case 3: 1 MW FFR ≈ 2.35 MW PFR

SC4: Frequency Response, Net Load = 65 GW

Net Load = 65 GW, Generation Trip 1350 MW1---: PFR = 12502---: PFR = 9003---: PFR = 6004---: PFR = 3005---: PFR = 100 with UFLS


Net Load = 35 GW, Generation Trip 1350 MW1---: PFR = 14002---: PFR = 9003---: PFR = 600 with UFLS

SC4: Frequency Response, Load = 67 GW

Load = 67 GW, 500 MW Load Ramp + One STP Trip1---: PFR = 12502---: PFR = 9003---: PFR = 6004---: PFR = 300 with UFLS5---: PFR = 100 with UFLS

3---: PFR = 600, ~59.91 Hz

3---: PFR = 600, ~59.91 Hz


Load = 36 GW, 500 MW Load Ramp then Trip 1350 MW generation1---: PFR = 14002---: PFR = 900 with UFLS3---: PFR = 600 with UFLS

1---: PFR = 1400, ~59.93 Hz

1---: PFR = 1400, ~59.93 Hz

Note

SCED “see” PFR

Reserve? Pros Cons

YesBetter maintain 60 Hz

Less “frequency responsive” reserve for generation loss

NoLarger “frequency responsive” reserve for generation loss

No control to maintain 60 Hz

Partial In between In between

• ERCOT will perform a RRS study and the results will support the annual revision of “Methodologies for Determining Ancillary Service Requirements”– Identify the minimum needs for RRS to meet the

NERC and ERCOT requirements– Identify the cap for LRs in RRS– Explore the potential for the followings,

• Different needs based on system conditions.

• Substitution ratio between Generation Resources and LRs in RRS

Responsive Reserve Study

32

Physical Responsive Capability

Sandip Sharma

Outline1. Review the intent of Physical Responsive Capability

(PRC)

2. Use of PRC as trigger for Energy Emergency Alert (EEA)

3. Review current PRC calculation

4. Current PRC calculation isn’t necessarily representative of available capacity that can “quickly respond to system disturbances”I. Examples from April 29, 2013 and May 22nd, 2014

5. Review possible PRC calculation changes

6. ERCOT recommendation for PRC change

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. Conventional Generation Resources and Controllable Load Resources maximum contribution to PRC is limited to 20% of their HSLWhy 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.

2. Hydro Resources operating under synchronous condenser fast response mode can contribute their full HSL*RDF towards PRC (full response within 20 seconds)

3. Non-Controllable Load Resources providing RRS is 100% counted towards PRC. (full response within 0.5 seconds)

Example 1 –Response from Combustion Turbine

Prior to event the CT was generating at 94 MW

CT responded with roughly 40 MW for this event

At HSL of 150 MW, maximum PRC contribution is limited to 30 MW

Example 2 – Response from Gas Steam Unit

HSL is 375; Prior to event this unit was generating at 49 MW

The unit responded with roughly 59 MW for this event, PRC contribution would have been limited to 75 MW

Example 3 – Coal Unit

The unit responded with roughly 54 MW for this event, PRC contribution would have been limited to 83 MW

HSL is 597 MW; Prior to event this unit was generating at 514 MW

Example 4 – Hydro under Fast Response Mode

HSL is 28 MW; Prior to event this unit was at 0 MW

The unit responded with 28.30 MW for this event, PRC contribution would have been limited to 28.3 MW

ERCOT monitors PRC for determining OCN, Advisory, Watch and EEA

ERCOT monitors PRC for declaring EEA

Physical Responsive Capability (PRC)

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

Physical Responsive Capability (PRC)

PRC = PRC1 + PRC2 + PRC3 + PRC4 + PRC5

Changes to PRC in near Future

1. Once NPRR-573 is implemented, Wind Generation Resources that are Primary Frequency Response capable and under curtailment, will be contributing to the PRC. Maximum contribution from WGRs will also be limited to 20% of their HSL. WGR

Issues with PRC Calculation

1. It includes capacity that cannot respond quickly to the system disturbances in other words it includes Non-Frequency Responsive Capacity (NFRC)

2. For Non-Controllable Load Resources (NCLR) PRC only includes portion of NCLR MW, that is under RRS obligation not the MW that would be triggered by Under Frequency Relay (UFR) set at 59.70 Hz.

3. Accuracy of HSL

4. Since June 1st - Generation Resources telemetering ONTEST, STARTUP or SHUTDOWN Resources Status are now excluded from PRC calculation

April 29, 2013 Unit Trip Event

Example 1 – Non-Responsive PRC

HSL = 1007 MW

Example 2– Non-Responsive PRC

HSL = 555 MW

May 22, 2013 Unit Trip Event


HSL = 1017 MW


HSL = 590 MW


HSL = 563 MW

Proposed Changes to PRC calculationOption 1- Lower the HSL of Combined Cycle Resources used for

PRC1 calculation by telemetered NFRC

Min(Max((RDF*(HSL-NFRC) – Actual Net Telemetered Output)i , 0.0) , 0.2*RDF*(HSL-NFRC)i),

PRC1* =

*where the included On-Line Generation Resources do not include WGRs, nuclear Generation Resources, or Generation Resources with an output less than or equal to 95% of telemetered LSL or with a telemetered status of ONTEST, STARTUP, or SHUTDOWN.

Non-Frequency Responsive Capacity (NFRC)

The telemetered portion of a Combined Cycle Generation Resource’s HSL that represents the sustainable non-Dispatched power augmentation capability from duct firing, inlet air cooling, auxiliary boilers, or other methods which does not immediately respond, arrest, or stabilize frequency excursions during the first minutes following a disturbance without secondary frequency response or instructions from ERCOT.

Proposed Changes to PRC calculation

Option 2- For Combined Cycle Resources, PRC1 calculation would only apply to individual Combustion Turbines (CTs), and this would require;

1.ERCOT to use the droop setting and HSL to calculate maximum contribution from a CT to PRC2.Resource Entities who owns Combined Cycle to telemeter HSL of the individual CTs that are part of Combined Cycle configuration in real-time.

54

EEA Level Triggers

Bill Blevins

Recap of EEA discussion• 2 example EEA events

– Frequency responsive capacity available, but low reserves (Aug 3 2011)

– Sufficient reserves, but low Frequency responsive capacity (Jan 18 2014)

• Requirement from BAL-003 could lead to future changes.

• Under EEA 3, ERCOT may have to maintain frequency at 59.91 Hz (BAAL requirement) instead of current 59.80 Hz

• PRC should reflect frequency responsive capacity but the current implementation includes capacity that is not frequency responsive

Overview

• EEA Levels• Current and Proposed EEA Level 3 Triggers and

Objectives• Current and Proposed EEA Level 2 Triggers and

Objectives• Current and Proposed EEA Level 1 Triggers and

Objectives

EEA Level Overviews (EOP-002 Attachment)• EEA 1

– All available resources in use

• EEA 2– Load management procedures in effect

• EEA 3– Firm load interruption imminent or in

progress

Current EEA 3 Trigger and Objective

• Current EEA 3 Trigger– When all other resources and demand side resources will not allow for

steady state frequency to be maintained at 59.8 Hz or greater ERCOT may enter EEA-3.

– ERCOT shall enter EEA-3 if steady state frequency falls below 59.5 Hz.

– No trigger based on remaining PRC.

• Current EEA 3 Objective– ERCOT directs all TSPs and DSPs or their agents to shed firm Load, in

100 MW blocks, in order to maintain a steady state system frequency of 59.8 Hz.

– No objectives concerning amount of PRC that should be restored when determining the amount of load shed, only frequency.

EEA 3 : Firm load interruption imminent or in progress

Proposed EEA 3 Trigger and Objective

• Proposed EEA 3 Trigger– PRC (frequency responsive) sustained below 1000 MW; or– System frequency sustained below 59.8 Hz (may change to 59.91 Hz

upon approval of BAL-001-2)

• Proposed EEA 3 Objective– Maintain frequency responsive PRC so that Most Severe Single

Contingency (MSSC) will not cause 1st Stage UFLS to trip.– Do not allow system frequency below 59.8/59.91 Hz greater than 30 min.

• contingent upon BAL-001-2 standard getting approved– ERCOT will continue to shed firm Load, in 100 MW blocks in order to

maintain a steady state system frequency of 59.8/59.91 Hz or greater.– 30 minute out Resource status and Demand outlook is typically considered

in addition to current conditions in determining the magnitude of firm Load Shed.

EEA 3 : Firm load interruption imminent or in progress


Net Load = 35 GW, Generation Trip 1350 MW1---: PFR = 14002---: PFR = 9003---: PFR = 600 with UFLS


Load = 67 GW, 500 MW Load Ramp + One STP Trip1---: PFR = 12502---: PFR = 9003---: PFR = 6004---: PFR = 300 with UFLS5---: PFR = 100 with UFLS

1,000 MW is a conservative PFR to account for winter peak (~58 GW) and or lower than studied frequency starting point.


• Current EEA 2 Trigger– Maintain system frequency at 60 Hz, or – Maintain a total of 1,750 MW of PRC.

• Current EEA 2 Objective– Utilize Load management procedures to maintain system frequency at 60 Hz,

or – Utilize Load management procedures to maintain a total of 1,750 MW of PRC.– Load management procedures utilize the following:

• Responsive Reserve Service (RRS) Load Resources (LR)• Any undeployed Emergency Response Service (ERS)• Distribution Level Voltage Reduction• Public Appeals for load reduction • Block Load Transfers (BLT)

– Load reduction by the load management procedures minimize or avoid the use of firm load shed if EEA 3 is needed.

EEA 2 : Load management procedures in effect


EEA 2 : Load management procedures in effect


• Current EEA 1 Trigger– Maintain a total of 2,300 MW PRC

• Current EEA 1 Objective– Maintain sufficient PRC for the loss of two large units

(1150 each) – Utilize all available Generation Resources and DC Tie

capacity that can respond in time for the EEA.– Utilize 30 minute ERS– EEA 1 may be declared even if due to a system

disturbance which temporarily reduces PRC to below 2,300 MW

EEA 1 : All available resources in use.


• Proposed EEA 1 Trigger– PRC sustained below 2,300 MW *

• Proposed EEA 1 Objective– Maintain current level of PRC

• 2300 MW of PRC should be sufficient to avoid 1st Stage UFLS for the largest category C (N-2) event(RCC) during expected scarcity conditions (high load).

– Utilize all available Generation Resources and DC Tie capacity that can respond in time for the EEA.

– Utilize 30 minute ERS


*May not enter EEA 1 due to a system disturbance which temporarily reduces PRC to below 2,300 MW unless PRC is not expected to be restored to above 2,300 MW within 30 minutes (allows NSRS and QSGRs to potentially restore PRC)

Comparison (Current vs Proposed)Physical Responsive

Capability (PRC)Frequency Responsive

PRC

EEA 1 Trigger : 2300 MW PRC



EEA 3 Trigger : Frequency Related (59.8 Hz), not PRC related




EEA 2 : Load management procedures

in effect

EEA 3 : Firm load interruption imminent

or in progress

EEA 1

EEA 1

EEA 2

EEA 2

EEA 3

EEA 3

Managing Constraints in EEA 2 & 3

Chad Thompson

• ERCOT is developing an NPRR & NOGRR to:• Allow generation being limited in SCED due to

a constraint to operate at a higher output during EEA 2 & 3 when possible (e.g. near radial injection constraints)

• Consider use of single circuit contingencies in lieu of double circuits during EEA 2 & 3 as system conditions allow

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

Background

• Attachment 1-EOP-002 has provisions during EEA 2 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 EEA 3 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

Rationale

• 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.

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.

Attachment 1 - EOP-002-3

Emergency Operations Prevention / Mitigation - EEA

Stephen Solis

Topics

• Categories of EEA

• Completed or In progress Initiatives

• Future Initiatives

Sudden Unit Trips

• Difficult to predict and may actually reflect a capacity emergency

• Actions to help prevent prior to event are limited.

• Review of EEA Level triggers – PRC calculation changes

(In progress)– EEA Level 1 Trigger (In

progress)

High Summer Demand

• Easier to predict and clearly reflects a capacity emergency

• Actions to help prevent prior to event are limited.

• Market signals for additional generation capacity

Large Capacity Unavailable due to Forced Outages and Derates

• Can somewhat predict and clearly reflects a capacity emergency

• Actions to help prevent prior to event are available.

• Weatherization plan reviews and site visits (on going)

• Natural Gas / ERCOT coordination (In progress)

• Wind Forecasting improvements icing/cold weather (In progress)

• Additional online spinning capacity procurement (on going)

Weatherization Plans

• Cold weather related forced outages and derates were significant contributors to more recent EEAs of higher severity (EEA 2 and EEA3).

• ERCOT review of weatherization plans, site visits, and cold weather preparation workshops may have yielded improvement in cold weather availability of resources.– 1/6/14 was not as cold as

2/2/11

Natural Gas/ERCOT Coordination

• During extreme cold weather, natural gas restrictions consistently cause lost capacity and derates.

• Coordination with natural gas companies directly may allow further advanced notice which may allow longer lead time decisions for alternate fuel or RUC commitments to be made.

Wind Forecasting Icing/Cold Weather Improvements

• While not directly contributing to recent events, risk exists for wind forced outages and derates to contribute to or aggravate EEAs.

• Being able to predict and account for those derates allows additional capacity to be procured to compensate for the lost capacity.

Additional Online Spinning Capacity

• Historical forced outage rates during cold weather provides feedback to plan for some amount of additional forced resource outages.

• ERCOT will use this information to formalize process for procuring additional online spinning capacity to account for anticipated additional forced resource outages.

0

2000

4000

6000

8000

10000

12000

20 25 30 35 40 45

Forced Outage Capacity on Coldest Days2005-2014

2/2/2011

1/9/2010

1/8/2010 1/17/2007

1/13/2011

Temperature (Fahrenheit)

MW

1/6/2014

Wind Forecast/Ramp• Can somewhat predict and clearly reflects a capacity

emergency• Actions to help prevent prior to event are available• Nodal Project Complete

– 5 min SCED re-dispatch– Hourly RUC– COP improvements

• Ancillary Services changes (on going)– Wind factored into required REG amounts currently– Net load forecast error factored into minimum

monthly NSRS requirements• Improved Wind Forecasting

– 50% probability forecasting (complete)– Icing/Cold Weather forecasting (In Progress)

• Wind Generation locations (on going)• Renewable Tools Enhancements

– New net ramp Renewable Tool (In progress)

Unseasonable Weather during Maintenance season

• Can somewhat predict and clearly reflects a capacity emergency

• Load Forecasting Improvements

• Nodal Project Complete – Hourly RUC– COP improvements

Future Initiatives

• All past and current improvement initiatives discussed enhance reliability and may help defend against unnecessary emergency operations.

• The risk for emergency operations will always exist and EEA processes/procedures will always be ready to be utilized if necessary and continually be evaluated for improvement.

• Future initiatives will also evaluate and ensure EEAs are initiated at the right level triggers to accomplish the intended objectives for each level.

Future Initiatives

• New Ancillary Services Framework

• PRC Calculation Changes

• HASL Release during EEA

• EEA constraint management

• EEA Level triggers

EEA Workshop 2 June 19, 2014

Documents

Transcript of EEA Workshop 2 June 19, 2014