ERCOT - beg.utexas.edu · * Prior to September 2008, ... • Did not alter the rule’s January 1,...
Transcript of ERCOT - beg.utexas.edu · * Prior to September 2008, ... • Did not alter the rule’s January 1,...
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Mike GentVice Chair, ERCOT Board of Directors
ERCOT
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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PRIMARY ISSUES OF INTEREST
• Wind Integration & Related Operational Challenges
• Resource Adequacy & Regulatory Uncertainties– Cross State Air Pollution Rule (CSAPR)
• Advanced Metering & Demand Response – GrowingOpportunities
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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3 CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
Wind Integration&
Related Operational Challenges
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WIND GENERATION
• ERCOT is #1 in the U.S. in windproduction.
• Our capacity is three times the amountof #2 (Iowa).
• If Texas were a separate country, we’dbe #5 in the world.
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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CHALLENGES RELATED TO INCREASED WIND RESOURCES IN ERCOT
• Wind is not as controllable or predictable as traditionalgeneration– Highly dependent on weather conditions– Cannot be dispatched (with exceptions)– Voltage control and reactive coordination are difficult
• Works best in conjunction with other generation in samearea– Conventional resources available to provide regulation &
responsive reserve services– Possible ancillary service impacts
• Creates new challenges in system design & operation– Difficultly in coordination of transmission outages and
construction, i.e., system off peak = wind peak production– Development of standard software stability models for operations
& planning environment
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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COUNTY LOCATION OF PLANNED GENERATION WITH INTERCONNECTION REQUESTS(WIND) SEPTEMBER 2011
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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SCENARIO 2 TRANSMISSION PLAN (18GW)
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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DAILY WIND GRAPH AT PEAK
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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9 CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
Resource Adequacy&
Regulatory Uncertainties
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RESERVE MARGIN, WITH POTENTIAL RESOURCES FROM QUEUE
0.00%
5.00%
10.00%
15.00%
20.00%
25.00%
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Installed Capacity Planned Units Coal * Natural Gas * Nuclear * Other * Solar * Wind * Suspended Projects ** 13.75% Target
* Fuel Composition of Projects Undergoing Full Interconnection Studies - theseprojects may be cancelled or delayed beyond the indicated commercial dates shown
** Potential in-service dates for suspended projects shown as the later of 2013 orthe date provided by the developer in their last update prior to suspension; may notreflect feasible in-service dates
• Installed Capacity and Planned Units areincluded in the CDR (top of light blue bar)
• Uncommitted Projects are not included inCDR
Uncommitted Projects
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
Reserve Margin Target – 13.75%
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GENERATION INTERCONNECTION PROJECTS UNDER STUDY
ACTIVITY
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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Proj
ect
Co
un
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MW
C
ap
aci
ty
MW Natural Gas MW Nuclear MW Coal MW Wind MW Solar *
MW Biomass * MW Other Total # Projects # Projects Cancelled
* Prior to September 2008, Category "Other" included "Solar" and "Biomass"Projects in all phases of interconnection study are reflected in this graphProject cancellation tracking by month began in March 2008
Note: Suspended Projects are not included in this chart
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12 CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
Cross State Air Pollution Rule
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CSAPR RULE REQUIREMENTS
• The CSAPR affects generating units in most of the eastern US (depictedon next slide).
• Under the CSAPR, generating units must have CSAPR allowances tomatch annual emissions of SO2 and NOX and separate allowances forpeak season (May – Sept.) NOX emissions.
• Units are allocated a number of allowances based on historicalgeneration. These unit allocations have been published.
• Trading of allowances within a state is unlimited. Interstate trading ofallowances is allowed, but net state-wide imports of allowances arecapped at approximately 18% of a state’s total allocation.
DECEMBER 8, 2011 CEE – UT ANNUAL MEETING
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STATES INCLUDED IN THE CSAPR
DECEMBER 8, 2011 CEE – UT ANNUAL MEETING
For SO2 allowances, owners of resources inTexas will be allowed to trade with ownersof resources in the “Group 2” states:Kansas, Nebraska, Minnesota, Alabama,Georgia, and South Carolina.
However, based on information obtained todate, ERCOT does not anticipate theemergence of an active market for trading ofGroup 2 SO2 allowances.
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CSAPR RELIABILITY IMPLICATIONS FOR 2012-13
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
Scenario 1 – Successful implementation of compliance plans– Mothballs and peak output reductions to ensure compliance– Extended outages during lower price periods– 1,200 to1,400 MW capacity reduction during peak months– 3,000 capacity reduction during off-peak months (Mar, Apr, Oct, Nov)
Scenario 2 – Plus Additional daily dispatching of base-load coal units– Additional maintenance requirements due to increased ramping and
starts/stops– Capacity reduction in Oct & Nov increases to 5,000 MW
Scenario 3 – Plus Limited availability of low sulfur coals– Output restrictions to ensure compliance– Capacity reduction in Oct & Nov increases to 6,000 MW
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CSAPR UPDATE
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
ERCOT is analyzing the reliability impacts of the proposed revisions to the CSAPR ruleannounced by the EPA on October 6, 2011.
The changes proposed:• Did not alter the rule’s January 1, 2012 implementation date• Did not revise modeling errors that ERCOT has reported do not reflect actual
conditions on the ERCOT electric grid• Have not been finalized, and may be altered or withdrawn by the EPA
The announced revisions to the rule arise from changes to model input assumptions inemissions rates of existing units in Texas. These changes lead to a 30% increase in thenumber of SO2 allowances given to plants in Texas.
The proposed changes also delay implementation of limits on interstate trading ofallowances until 2014.
ERCOT is gathering information from generators regarding changes to their complianceplans reported to ERCOT after the initial adoption of CSAPR.
Resource Adequacy predictions become quite challenging in the light ofRegulatory Uncertainties
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17 CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
Advanced Metering&
Demand Response
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ADVANCED METERING & DEMAND RESPONSE
• Part of “Smart Grid” efforts• Remote meter reading• Informed Customers• Dynamic pricing – limited approach• Demand Response Programs
– Decrease Consumption– Need programs to Increase Consumption
DECEMBER 8, 2011 CEE – UT ANNUAL MEETING
Demand Response presents a great opportunity to address bothWind Integration and Resource Adequacy issues
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SUMMER PEAK DAY LOAD SHAPE WITH FUEL MIX
Coal
DC Imports
Nuclear
Wind
Natural Gas
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
0
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20,000
30,000
40,000
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60,000
70,000
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0:00
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2:00
3:00
4:00
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8:00
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0
11: 0
0
12: 0
0
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0
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0
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0
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0
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0
22: 0
0
23: 0
0
August 3, 2011 Natural Gas Wind Nuclear Hydro
Other DC Imports Coal Energy Price
MW
$/M
Wh
$25 - $75
$3001
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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DEMAND RESPONSE POTENTIAL IN ERCOT
Source: FERC 2009 National Assessment of DR, page 42
• 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
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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OFF-PEAK VS. ON-PEAK LOAD
• Both days were Wednesdays• Customer class breakdown is for
competitive choice areas only• IDR meters are required at >700kW
Hot day, high A/C load
21,000 MW of residentialsummer peak load
Moderate day, low A/C load
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
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TODAY WE’RE SETTLING ABOUT FOUR MILLION ADVANCED METERS
Advanced Meter Deployment Plan
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
Advanced meters give customers the data they need to makeeducated decisions about their electricity usage
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QUESTIONS?
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CHANGES THAT AFFECT RESERVE MARGIN SINCE JUNE 2011CDR (FOR SUMMER 2012)
CEE – UT ANNUAL MEETINGDECEMBER 8, 2011
The Peak Demand forecast has been updated (increase in Firm Load Forecast of 738 MW for 2012)
Additional Mothballed Units Capacity (MW) Planned UnitsGreens Bayou 5 -406 09INR0001-Sandy Creek 1 -925 DelayedMidlothian 5 -225 09INR0029-CFB Power Plant Units 11&12 -260 In-service, but zero net capacity to gridMonticello 1 -565 11INR0086-RRE Austin Solar -60 DelayedMonticello 2 -565 08INR0011-Senate Wind Project -13 Delayed 150 MW Unit at 8.7%Sam Bertron 3 -230 Misc DG Units 25 NewSam Bertron 4 -230 -1234Sam Bertron T2 -13Change in Prob. Of Return %s 717 Changes to Unit Maximum Sustainable Limits reported in RARFs
-1517 Net Change 339Mothballed Units Returned to Service
Spencer 4 61 Change to PUN Available Generation based on Aug 2011 ActualsSpencer 5 61 Net Change -681 Based on Aug 2011 Actual OutputSam Bertron 1 174Sam Bertron 2 174 Total Change in Resources Available -2623
470
Jack County 2 (565MW) and Sherbino Mesa Wind 2 (150MW with ELCC of13MW) moved from Planned to Installed)