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Intermittent Resources and Demand Response Integration 2007–2016 Long-Term Reliability Assessment Workshop. Bill Bojorquez VP, System Planning August 16, 2007. North American Interconnected Grids. NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION (NERC). The ERCOT grid: - PowerPoint PPT Presentation
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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%).
66
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
77
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
1111
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.
1515
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?
2222
Q&A
ON
OFF
• Questions?