Intermittent Resources and Demand Response Integration

2007–2016 Long-Term Reliability Assessment Workshop

Bill Bojorquez

VP, System Planning

August 16, 2007

22

ERCOT connections to other grids are limited to direct current (DC) ties, which allow control over flow of electricity

North American Interconnected Grids

• The ERCOT grid:– Covers 75% of Texas

land– Serves 85% of Texas

load – 38,000 miles of

transmission lines– >550 generation units– Physical assets are

owned by transmission providers and generators, including municipal utilities and cooperatives

NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION (NERC)

33

Current Wind Development

• ~3,300MW installed capacity of wind generation in-service

• ~2,000MW additional wind development with signed interconnection agreements

• Steady build out has allowed for transmission, modeling and operation integration

Additional bulk transmission lines will be required for > ~5000MW from West Texas

• ~29,000 MW additional wind development in interconnection study process

ERCOT Load

• 62,339 MW summer peak demand

• Majority of load is concentrated in eastern half of state

– Dallas– Austin

– Houston– San Antonio

55

Effective Load Carrying Capability (ELCC) of Wind

Process: • Run the ERCOT LOLP model with the base set of generating units

and a generic thermal generator (550 MW) and determine the expected unserved energy.

• Remove the generic thermal generator and add new wind generation with detailed profiles until the same expected unserved energy is achieved.

• The amount of new wind generation will have the same effective load-carrying capability as the 550-MW generic thermal generator

• Update study every two years

Results:• 6,300 MW of wind had the same load carrying capacity as 550 MW of

thermal generation (i.e., 8.7%).

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TX Senate Bill 20 (2005)

• Increased renewable energy goal– 5,880 MW by 2015– 10,000 MW by 2025

• Set up process for the PUC to designate Competitive Renewable Energy Zones (CREZs)

• ERCOT contracted AWS Truewind to identify areas with best wind resource potential in Texas

• AWS identified highest CF 100MW sites and clustered into 25 areas

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Potential Wind Resource

10

600

83

00

12

000

96

007

900

69

00

60

00

62

004

700

29

00

46

00

30

002

200

27

00

• Nearly 100,000 MW above 35% capacity factor (CF)

• Concentrated in western half of state

Approximate west to east transfer capacity – 3,200MW

88

New Transmission Required

10

600

83

00

12

000

96

007

900

69

00

60

00

62

004

700

29

00

46

00

30

002

200

27

00

• Existing system from west Texas fully subscribed

• Significant distances and costs associated with adding bulk transmission

200 miles

150 miles

99

ERCOT Study Results

• ERCOT’s 2006 study identified new lines and upgrades to allow transfers from CREZ areas

• Allowed for incremental 1,000 to 5,000 MW of wind capacity– In addition to

5,000 MW existing plus planned

• Goal was to provide options from which the PUC could designate areas and amounts

1010

Draft CREZ PUCT Designations (Scenario 3)

28

90

45

60

37

205

215

20

51

Wind Zone Planned New Wind Capacity

(MW)

1, 2 4,560

4 3,720

5, 6 2,890

9,10 5,215

19 2,051

Total 18,436

5, 6

1, 2

9, 10

4

19

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Challenges

• Level of wind penetration relative to the size of the interconnection– Minimum system

load dispatch issues (~ 21,000 MW)

• Ancillary Services to support large wind changes

• Voltage and transient stability modeling and assessments

MW

Noon Midnight

• Completing system reviews for the CREZ designations over the next six months

1212

Next Steps

• Stage 1 (August): Final order in Docket 33672 on CREZs and “rough” transmission requirements

• Stage 2 (December/January): Completion of “CREZ Transmission Optimization Study”

• Stage 3 (December/February): PUC to designate transmission constructors

• Stage 4 (December ’08/February ’09): CCNs developed and submitted

• Stage 5 (June ’09/August ’09): CCNs approved• Stage 6 (TBD): Completion

Demand Response

1414

0%

5%

10%

15%

20%

25%

30%

35%

40%

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

12.5%

Reserve Margins 2000-2012

Percentage difference between projections for peak demand and available generation/resources

Target for reliability: 12.5%

Over 65,000 MW of new generation is in planning or under consideration, but not all will be built.

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Interruptible Tariffs in the Regulated World

• Prior to 2001, 3200 MW of customer load (mostly industrials) provided an emergency interruptible safety net

• Customers’ year-round electric rates were discounted in exchange for this

• In May 2000, ERCOT deployed interruptible loads four times during emergency conditions – Unseasonably hot weather– Generation outages– New wave of gas-fired generation had not yet come online

• ERCOT began full retail competition on January 1, 2002

1616

Interruptible Load in the New (restructured) Market

• Loads Acting as a Resource: – Market-based replacement for interruptible tariffs– 1,989 MW currently registered and qualified– ERCOT demand forecast is reduced by 1,112 MW of “high

confidence” demand response

• LaaRs can provide ERCOT Ancillary Services (operating reserves) & receive capacity payments regardless of whether they are actually deployed– LaaRs provide 50% of ERCOT Spinning Reserve requirement

(1,150 MW of 2,300 MW total)– Market price: ~$13 per MW per hour

• Price-responsive demand is significant in ERCOT – but not yet readily reported

• Additional demand response is obtained on coincident peak periods due to Transmission Tariff incentive

1717

LaaR Participation

Growth in LaaR registration in MW

1818

LaaR Deployments

• LaaRs can be deployed in 4 ways:1. Automatic trip based on Under Frequency Relay settings2. Verbal dispatch by ERCOT during EECP event (deployed as

block)3. Verbal dispatch by ERCOT during frequency event reportable

to NERC (deployed as block)4. Verbal dispatch by ERCOT to solve a local congestion issue

(location-specific)

• LaaRs have been deployed four times in the past 16 months:– April 17, 2006 Emergency Electric Curtailment Plan (manual)– Oct. 3, 2006 frequency event (manual)– Dec. 22, 2006 frequency event (UFR & manual)– July 2, 2007 frequency event (manual)

1919

Emergency Interruptible Load Service (EILS)

• Service provided by loads (customers) willing to interrupt during an electric grid emergency in exchange for a payment

• Last resort prior to firm load shedding (rotating outages)• Deployed ONLY in the late stages of a grid emergency• Goal is 500 MW to 1,000 MW subscription

– Minimum subscription not met for spring and summer 2007– New RFP out for fall 2007

‘Another tool for the operator toolbox’

2020

Deployment During Emergency Operations

Event/Action Trigger

ADVISORY Physical responsive below 3000 MW

ALERT: Start Reliability Must Run units, suspend unit testing, deploy Replacement & Non-spin Reserves

Physical responsive below 2500 MW

Emergency Electric Curtailment Plan

Step 1: Dispatch all generation, issue public media appeal, acquire maximum power thru DC Ties

Physical responsive below 2300 MW

Step 2: Deploy LaaRs Physical responsive below 1750 MW

Step 3: Deploy EILS Resources Maintain frequency at 60 Hz

Step 4: Instruct transmission owners to shed firm load

Frequency below 59.8 hz

ERCOT Operators have flexibility to skip Step 3 if frequency is decaying rapidly. In these cases EILS would be deployed immediately after Step 4 to enable faster recovery.

2121

Consideration on Demand Response (DR)

• Should DR be considered a firm resource? If so what types of DR

• Does DR defer transmission investment? – ERCOT concluded it should not – Summer 2006 MISO experience showed DR may not be useful

unless transmission additions are made• Does DR stifle development of newer, more efficient, and

cleaner generation resources?

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Q&A

ON

OFF

• Questions?