ercot demand response - department of electrical and

ERCOT Demand Response

Paul Wattles

Senior Analyst, Market Design & Development, ERCOT

Whitacre College of Engineering, Texas Tech University

April 6, 2012

North American Bulk Power Grids

• The ERCOT Region is one of 3 grid interconnections in USA-Canada

• The ERCOT grid:

– Covers 75% of Texas land

– Serves 85% of Texas

2 Texas Tech College of EngineeringApril 6, 2012

– Serves 85% of Texas load

– >40,000 miles of transmission lines

– >550 generation units

– Physical assets are owned by transmission providers and generators, including municipal utilities and cooperativesERCOT connections to other grids are limited to direct current (DC)

ties, which allow control over flow of electricity

North American ISOs and RTOs

Independent System

Operators and Regional Transmission Organizations

are the ‘air traffic

controllers’ of


controllers’ of the bulk

electric power grids

Peak Load Fuel Mix

40000

50000

60000

70000

80000

August 3, 2011 Generation by Fuel

Gas Wind Other* Coal Nuclear

*Other includes Hydro, Biomass, Solar, and unknown sources

>28 GW


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Off-peak vs. on-peak load by customer type

Residential

51.2%

(~35,000 MW)

Wed., Aug. 3, 20115:00 PMERCOT Load: 68,416 MWTemperature in Dallas: 109°

WednesdayMarch 9, 20115:15 PMERCOT Load: 31,262 MWTemperature in Dallas: 64°


• Customer class breakdown is for competitive choice areas; percentages are extrapolated for munis and co-ops to achieve region-wide estimate

• Large C&I are IDR Meter Required (>700kW)

8/3/2011 IE 17:003/9/2011 IE 17:15

Large C&I

23.7%

Residential 27.4%

(~8,500 MW) Small Commercial

25.2%

Small Commercial

28.9%

Large C&I

43.7%

One more way of looking at ERCOT

26.3%

NOIE Retail Choice

Competitive Choice vs. Muni/Co-op Load

Muni’s and co-ops are still vertically integrated

Many have existing and developing smart grid initiatives:

Dozens of REPs competing for residential and small commercial accounts

Mostly flat-price options including pre-paid, renewables


73.7%

smart grid initiatives:-- AMI-- Smart thermostats-- Other DLC

Possible triggers: Real-time prices, congestion management, 4CP response

paid, renewables

AMI deployment underway

‘Utility’ in the traditional sense in no longer a valid term

MWh 12/1/10 thru 8/11/11

Resource Adequacy

13.75% target


* Projects undergoing full Interconnection studies - may be cancelled or delayed beyond the commercial dates shown*** Monticello 1&2 – 1130MW (as a result of a federal court’s order to stay EPA’s CSAPR)

Definitions of Demand Response

• ‘The short-term adjustment of energy use by consumers in response to price changes or incentives.’ (FERC)

• ‘Changes in electric use by demand-side resources from their normal consumption patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use at times of high wholesale market


induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized.’ (NERC)

• ‘A temporary change in electricity consumption by a Demand Resource in response to market or reliability conditions.’ (NAESB)

Definitions of Demand Response

• The common threads:

– Change in Load

– In response to a signal (economic or operational)

• 3 key questions relative to any DR:

1. What is the incentive?


1. What is the incentive?

2. What is the signal?

3. Who takes the action (pushes the button)?

DR potential in ERCOT

• FERC estimates >18 GW of DR potential in Texas by 2019

– Attributed to high peak demand

– This would represent 20-25% of total ERCOT peak


Source: FERC 2009 National Assessment of DR, page 42

ERCOT DR Summary

Load Type Service Requirements Description/Notes

Voluntary Load Response (VLR)

Load reduction in response to Market Price, 4CP signals or other factors

• Metering • Load reduction technology • Retail contract with demand response

incentives

• Economic: not dispatched by or reported to ERCOT ISO

• May include dynamic pricing (Time of Use, Critical Peak, Real-Time Pricing) and/or centrally dispatched load control

Load Resources (LRs)

Responsive Reserves

• Interval metering• Telemetry• Under-Frequency Relay• Load reduction technology• ERCOT Qualification

• Industrial Loads • 197 LRs with ~2400 MW of total

registered capacity• Limited to 50% of total RRS (1150 of

2300 MW) Dispatched during Energy Emergency Alert (EEA) or


• ERCOT Qualification Emergency Alert (EEA) or automatically due to frequency drop

Controllable Load Resources (CLRs)

Regulation ServiceResponsive Reserves

• Interval metering• Telemetry• Ability to receive AGC-type signals• Governor-type frequency response• ERCOT Qualification

• Industrial Loads with sophisticated control systems and ramping capability

• 1 CLR (~20 MW) currently enrolled

Emergency Interruptible Load Service (EILS)

10-minute special emergency DR service

• Interval metering• Load reduction technology• ERCOT Qualification

• Mid- to large commercial & industrial Loads

• Procured 3 times per year for 4-month Contract Periods

• Dispatched during EEA• ~450 MW enrolled depending on Time

Period

DR in ERCOT today

• Operational DR (these MW we know):

– 207 Load Resources with 2400+ MW of registered DR capacity• Participation in Responsive Reserves capped at 1400 MW

– Minimal participation by Controllable Load Resources in RRS (not capped) and Regulation service

– 475 MW of participating EILS from ~900 Load sites

– ~150 MW enrolled in TDSP Load Management SOPs• Summer peak hours only; some overlap with EILS

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• Economic DR (these MW we don’t):

– Load curtailing in anticipation of 4CP intervals• 11,000+ IDR-metered Loads subject to tariffs

• Behavior is well-baked into ERCOT load forecasting

• Initiated by customer or thru direct load control by REP/third party

– Real-time & critical peak price response• Initiated by customer or thru direct load control by REP/third party

– Time of Use

Texas Tech College of EngineeringApril 6, 2012

DR incentives, signals and actions

DR Type Incentive Signal Action-taker

Load Resources providing RRS

Day-ahead Ancillary Service market clearing prices

ERCOT dispatch (EEA or frequency recovery), UFR trip

QSE (via SCADA or direct load control), UFR (automatic), Load personnel

EILS (ERS)4-month capacity payment

ERCOT dispatch (EEA)

QSE (via SCADA or direct load control), Load personnel


4CP Response TCOS avoidanceProbability of a 4CP interval

Load personnel (IDR-metered Loads, NOIEs) or 3rd party

Critical Peak Response

High price avoidance or rebatefrom LSE

Real-time Load Zone prices above a level specified in contract

Load personnel, or LSE or 3rd party via direct load control

DR incentives, signals and actions (continued)

DR Type Incentive Signal Action-taker

Real-TimePricing

Energy price avoidance

Probability of high Load Zone price -- signal provided by LSE or 3rd

party

Load personnel, or LSE or 3rd party via direct load control

TDSP Load Mgmt. Std.Offer Programs

Capacity paymentInstruction from TDSP(coordinated with ERCOT EEA)

Load personnel or aggregator


Time of Use

Potential to save by using lower priced off-peak power

Prices change at known time of day

Load (behavioralshift)

Load Resource deployments since 2006

Day Date Time Type of Deployment Season

1 Mon 4/17/2006 15:34 EECP Step 2 Systemwide Verbal Dispatch Instruction (VDI) Spring

2 Tue 10/3/2006 17:37 Systemwide VDI for frequency restoration Fall

3 Fri 12/22/2006 2:54 Under-frequency (UF) Event followed by VDI for frequency restoration Winter

4 Mon 7/2/2007 19:38 Systemwide VDI for frequency restoration Summer

5 Wed 9/5/2007 7:57 Systemwide VDI for frequency restoration Summer

6 Wed 12/12/2007 1:56 Systemwide VDI for frequency restoration Winter

7 Tue 2/26/2008 18:49 EECP Step 2 Systemwide VDI Winter

8 Sun 3/16/2008 11:37 UF Event, frequency < 59.7 Hz Spring

9 Mon 8/11/2008 17:14 Systemwide VDI for frequency restoration Summer

10 Tue 12/16/2008 15:49 Systemwide VDI for frequency restoration Winter


10 Tue 12/16/2008 15:49 Systemwide VDI for frequency restoration Winter

11 Sat 1/9/2010 10:32 Systemwide VDI for frequency restoration Winter

12 Sat 5/15/2010 16:14 UF Event, frequency < 59.7 Hz Spring

13 Wed 6/23/2010 15:20 UF Event followed by VDI to selected QSEs for frequency restoration Summer

14 Fri 8/20/2010 15:28 Systemwide VDI for frequency restoration Summer

15 Wed 11/3/2010 10:21 UF Event followed by VDI to selected QSEs for frequency restoration Fall

16 Wed 2/2/2011 5:20 EEA Level 2A Systemwide VDI Winter

17 Wed 3/23/2011 14:47 UF Event (partial), frequency dropped to near 59.7 Hz Spring

18 Thu 8/4/2011 14:32 EEA Level 2A Systemwide VDI Summer

19 Wed 8/24/2011 15:11 EEA Level 2A Systemwide VDI Summer

20 Tue 11/29/2011 3:29 UF Event, frequency < 59.7 Hz Fall

Peak vs. off-peak DR

• Unlike many ISO products, ERCOT DR is not designed specifically to reduce summer peak demand

– Responsive Reserves and EILS/ERS are procured 24/7/365

• Of 20 Load Resource deployments since 2006:

– 5 occurred during summer peak hours (3-7 PM weekdays, June through September)

– 6 occurred during winter months

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– 9 occurred during non-business hours (overnights or weekends)

• However, 8 deployments were for frequency restoration

– Typically caused by generation unit trips

– Nodal market design (implemented 12/1/10) has reduced the need for deployments of this type

• Due to thinning reserve margins, ERCOT now views DR resources as important element for meeting peak load


EILS

• Emergency Interruptible Load Service has been an ERCOT operational tool since 2008

– Created through detailed PUC Rule with goal of enhancing reliability and opening DR to loads of all types

– Deployed only in late stages of grid emergency prior to firm load shedding (rotating outages)

– Open to individual Loads or aggregations of Loads

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– Procured via RFP for four-month contract periods

– Offers selected by ERCOT management

– Participation has grown from 0 to >450 MW

• 2 EILS deployments in 2011

– One just prior to winter peak (Feb. 2), related to large number of unit trips

– One during summer peak (Aug. 4)


EILS → ERS

• Following summer of 2011, resource adequacy concerns prompted ERCOT and PUC to seek ways to increase EILS participation

– Goal: more capacity under contract by summer 2012

• Rule amendments adopted in March; follow-on Protocol revisions are scheduled for 6/1/12 implementation

• New name: Emergency Response Service (ERS)

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– Now open to participation from unregistered generators (such as distributed generation) capable of injecting power to the grid

– Allows for contract period renewals to deal with sustained weather/grid reliability events

• Feb. 2-3 event in 2011 lasted 28 hours

– Minimum offer reduced from 1 MW to 0.1 MW – will allow more flexibility in assembling aggregations


Smart Grid

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Smart grid at the bulk power level: ‘Macomber Map’

• ERCOT identified the need for situation awareness and improved user experience in control rooms

• Main issues:

– Need for wide-area and high-level views

– “Alarm storm”

– “Dust storm”

20 ERCOT InternalFeb. 22, 2012

– “Dust storm”

– Locations of equipment

– Navigation between one-lines

– Naming conventions for equipment

– Data integration across multiple systems

– Increased cognitive load as operators increasingly managing more tasks with more complex systems.

• This trend is only continuing (e.g., AMI)

The ‘Macomber Map’

• Visualization tool used by ERCOT operators for situational awareness

• Allows operators to see all data for single element (e.g., a generator), across applications and systems

• Used for many ERCOT applications:

– Control room

– Network modeling group

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– Network modeling group

– Congestion Revenue Rights

– Market Information System (contour map of LMPs and SPPs)

– Training

– Engineering

• Developed in-house; named for one of the developers who passed away in 2008

ERCOT InternalFeb. 22, 2012

Smart grid at the bulk power level: Synchrophasors

• Joint project of ERCOT, Transmission Owners (AEP, Oncor, Sharyland) and the Center for the Commercialization of Electric Technologies (CCET)

• Initiated in Fall 2008 with 3 AEP PMUs

• Currently 14 Phasor Measurement Units (PMUs) installed at 12 TO locations

– Real-Time Dynamic Monitoring System (RTDMS) at ERCOT

• Expanding to 23 PMUs, provide TOs access to RTDMS

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• Expanding to 23 PMUs, provide TOs access to RTDMS visualization applications

• GOALS:

– Provide real-time dynamic information

– Identify precursor conditions to undesirable grid performance and behavior

– Identify changes in operating procedures or actions to facilitate integration of phasor measurements, hence improving grid reliability

– Recalibrate dynamic models


What the Phasors Do

• Phasor measurement technology offers a means of capturing wide-area snapshots of phase angle profiles and comparing them.

23Feb. 22, 2012 ERCOT Internal

ERCOT Phasor Locations

24Feb. 22, 2012 ERCOT Internal

Benefits of Phasor Measurements

• Direct measurement phasor angles

– In EMS, phasor (voltage or current) angles only can be calculated by State Estimator, which runs every 5 mins

– PMUs continuously measure voltage/current angles with high sampling rate (≥ 30 samples/s)

• High sampling rate

– Conventional SCADA measurements update in seconds

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– Conventional SCADA measurements update in seconds

– PMUs typically take 30 observations per second

• Voltage phasor angle difference can be used as a good indicator of grid stress

Feb. 22, 2012 ERCOT Internal

Benefits of Phasor measurements

• Phasors are valuable tools for validation of stability studies and other real-time and after-the-fact evaluations of grid events

– Example: Real-time oscillations experienced at a unit during testing were monitored and reported back to ERCOT

– Max output level then established for the unit causing the oscillation

• Phasor data has also been helpful in ERCOT’s evaluations of Load Resource under-frequency relay trips

– Supplement to the high-speed frequency recorders present at

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– Supplement to the high-speed frequency recorders present at ERCOT Control Centers

– Retrieving frequency data from multiple points across the System gives ERCOT a more complete view of an event

– Example: when a UFR event trips only part of the LR fleet, there may be more than one reason:

• Some LRs have their UFRs set slightly higher than 59.7 Hz requirement

• Frequency may not dip below 59.7Hz for full 20 cycles at all points on the System


Smart grid at the distribution level

• Improved elasticity of demand among small customers

– Advanced metering

– Home Area Networks

– Load control devices

– Dynamic price offerings

• A ‘self-healing’ grid that responds dynamically to shortages,

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• A ‘self-healing’ grid that responds dynamically to shortages, disturbances or high price events

– Automatic response to signals at the device level

• ‘Demand Response 2.0’


Smart Grid initiatives

• Municipals and Co-ops (24% of ERCOT Load) have a number of existing and developing smart grid initiatives

– AMI deployments

– Smart thermostats

– Other DLC

• Investor-owned TDSPs serving competitive-choice areas are over 75% of the way toward eventual deployment of 6 million-plus advanced meters

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plus advanced meters

• As of early April:

– TDSPs have installed nearly 5 million advanced meters

– ERCOT keeping pace, settling on 15-minute data

• Robust TDSP features:

– Meter-reads-on-demand enhance retail switching

– Automatic outage detection

– Remote connect/disconnect


AMI and the retail market

• Smart Meter Texas portal has a low sign-up rate among customers with advanced meters

• Customer education initiatives and dynamic price offerings are scarce

– Vast majority of AMI customers are still buying flat-priced electricity

• Home Area Networks are still in pilot stage

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• Low participation by REPs and aggregators in the AMIT process

• REP investments in customer smart-grid tools subject to:

– Risk of losing the customer to switching: potential stranded costs

– Lack of financial incentives due to low flat electricity prices

• $2 natural gas


Path to the Smart Grid

TDSP Back Office

15-minute Settlement

REP Back Office

Customer Education

Incentives

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Office EducationIncentives

Home Area Network

Load Control Equipment


Relevant questions

• How many REPs will build AMI DR portfolios?

– Does DR capability = smarter energy consumers = enhanced customer loyalty?

• How much mass market DR potential is out there?

– FERC estimate is simply a calculation of peak demand, not a projection of adoption rates

• How fast will it develop?

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• Who is most likely to push the button?

– Customer, REP, third party?

• Will shortage/scarcity conditions result in high prices?

• Will the signals all be economic?

– What energy prices (i.e., natural gas) are needed to stimulate DR?

– Will mass market AMI customers enroll in ERCOT DR services?


DR and intermittent renewables

• Wind integration is an ongoing initiative at ERCOT

– >10,000 MW of wind on a 68,000 MW system

– Wind blows better off peak, as you all know in West Texas

– Wind ramps tend to coincide with load ramps – creating ‘net load’ effect

• Feb. 2008 LR deployment helped recover from a net load event

• Recommendations from study of wind integration by GE (2009):

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• Recommendations from study of wind integration by GE (2009):

– Improve wind forecasting

– Increase procurement of Regulation service and possibly Nonspin during hours with likely net load events

– Consider a new 15-minute Ancillary Service

• New products could potentially accommodate DR participation as well as generator participation


Challenges for ERCOT DR

• ERCOT energy-only market design

– DR in the eastern ISOs has grown much faster due to forward (long-term) capacity markets

– Energy-only market success depends on very high prices during scarcity condtions

• This creates opposition to DR due to tendency to suppress prices

• Price response hindered by:

– Inability for DR to compete with generation in the real-time energy

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– Inability for DR to compete with generation in the real-time energy market, SCED (Security Constrained Economic Dispatch)

– Lack of advance notification of prices paid by Loads

– Both of these issues being addressed but will take years • ‘Nodal 2.0’

• Current ERCOT DR products require 10-minute response

– ERCOT will pilot a 30-minute DR product this summer, assuming PUC adoption of Rule enabling pilot projects


Lessons Learned

• Load Resource participation in Ancillary Services has matured into an extremely valuable operational tool

– However, participation drops off during high peaks, for a number of reasons including price/4CP response

• EILS growing pains:

– Harsh suspension provisions – Loads subject to 6-month suspensions for narrow failures of availability

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• This has kept dozens of MWs sidelined at any time

– 28-hour deployment in Feb. 2011 has made marketing the product very difficult for aggregators

– Many issues addressed in new Rule/Protocols

• Low natural gas = cheap electricity = diluted incentives for retail DR/load management products

– Will policymakers need to jump-start the smart grid?


ON

Questions?


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ercot demand response - department of electrical and

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