NERC Resources Subcommittee MISO BA Integration Update April 2013 MISO Reliability Coordination expansion 6/1/2013 # Acronym BA Name CWAY 215 MW NLR 245 MW WMU 95 MW SME 1,601 MW 1 CLEC CLECO 2 SME South Mississippi Electric Power Association 3 LAGN Louisiana Generating, LLC 4 LAFA Lafayette Utilities System 5 LEPA Louisiana Energy and Power Authority 6 WMU City of West Memphis, AR 7 CWAY City of Conway, AR 8 NLR Cityof North Little Rock, AR CLEC 2,209 MW LEPA 231 MW LAGN 2,247 MW LAFA 495 MW 2 1
MISO Balancing Authority Expansion 12/19/2013 # Acronym BA Name 2 9 BA s expected to dissolve on 12/19/2013 BRAZ 87 MW CWAY 215 MW NLR 245 MW PLUM 1 665 MW PUPP 1 2,267 MW CLEC LEPA 231 MW BUBA 80 MW DERS 69 MW 2,209 MW WMU 95 MW OMLP 38 MW EES (incl. EAI) 23,211 MW BBA 1 578 MW SME 1,601 MW LAGN 2,247 MW LAFA 495 MW EES Entergy (Louisiana, Texas, Mississippi, New Orleans, Arkansas*) 1 * Entergy also committed to Arkansas Commission to split off Entergy Arkansas into a separate LBA (EAI) 2 CLEC CLECO 3 SME South Mississippi Electric Power Association 4 LAGN Louisiana Generating, LLC 5 LAFA Lafayette Utilities System 6 LEPA Louisiana Energy and Power Authority 7 BRAZ Brazos Electric Cooperative 8 DERS City of Ruston, LA 9 OMLP Cityof Osceola, AR 10 PUPP Union Power Partners, L.P. 11 PLUM Plum Point Energy Associates, LLC 12 WMU City of West Memphis, AR 13 BUBA City of Benton, AR 14 CWAY City of Conway, AR 15 NLR City of North Little Rock, AR 16 BBA Batesville Generation merging into SME 6/1/13. 1 Generaton only Balancing Authorities. 2 Several BAs plan to dissolve BAs and integrate 12/19/2013. 3 BA Area Interfaces- Existing OKGE EDE AECI MISO PLUM CWAY OMLP TVA CSWS SPA NLR PUPP WMU BUBA BBA EES DERS SME ERCO SOCO CLEC BRAZ LEPA LAFA LAGN AEC 4 2
MISO Balancing Authority (BA) / Local Balancing Authorities Areas 12/19/2013 # Acronym LBA Name MISO BA EAI EES SME EES Entergy (Louisiana, Texas, Mississippi, New Orleans, Arkansas*) 1 * Entergy also committed to Arkansas Commission to split off Entergy Arkansas into a separate LBA (EAI) 2 EAI Entergy Arkansas 3 CLEC CLECO 4 SME South Mississippi Electric Power Association 5 LAGN Louisiana Generating, LLC 6 LAFA Lafayette Utilities System 7 LEPA Louisiana Energy and Power Authority CLEC LAGN LEPA LAFA 5 RC and BA Integration Schedule # Acrony m BA Name RC BA/Market 1 EES Entergy (Louisiana, Texas, Mississippi, New Orleans, Arkansas*) * Entergy also committed to Arkansas Commission to split off Entergy Arkansas into a separate LBA Area (EAI) MISO 12/1/2012 MISO 12/19/2013 2 CLEC CLECO MISO 6/1/2013 MISO 12/19/2013 3 SME South Mississippi Electric Power Association MISO 6/1/2013 MISO 12/19/2013 4 LAGN Louisiana Generating, LLC MISO 6/1/2013 MISO 12/19/2013 5 LAFA Lafayette Utilities System MISO 6/1/2013 MISO 12/19/2013 6 LEPA Louisiana Energy and Power Authority MISO 6/1/2013 MISO 12/19/2013 7 BRAZ Brazos Electric Cooperative SPP until dissolving BA dissolving 12/19/2013 8 DERS City of Ruston, LA SPP until dissolving BA dissolving 12/19/2013 9 OMLP Cityof Osceola, AR SPP until dissolving BA dissolving 12/19/2013 10 PUPP Union Power Partners, L.P. SPP until dissolving BA dissolving 12/19/2013 11 PLUM Plum Point Energy Associates, LLC SPP until dissolving BA dissolving 12/19/2013 12 WMU City of West Memphis, AR MISO 6/1/2013 BA dissolving 12/19/2013 13 BUBA City of Benton, AR SPP until dissolving BA dissolving 12/19/2013 14 CWAY City of Conway, AR MISO 6/1/2013 BA dissolving 12/19/2013 15 NLR City of North Little Rock, AR MISO 6/1/2013 BA dissolving 12/19/2013 16 BBA Batesville Generation BA dissolving into SME 6/1/2013 6 3
Summary MISO is merging a number of BA Areas into its BA Area. Several BAs are dissolving. Certification Team will verify MISO will have necessary tools, procedures, and training to perform RC and BA functions for the expanded footprint. There will be separate certifications for the RC footprint expansion and the BA Area expansion. Working with Certification Team on NERC s Housekeeping Tasks for New, Reconfigured or Retiring Balancing Authorities that need to be done if there is a change in Balancing Authority footprints or names. Coordinated Functional Registration (CFR ID#: *JRO00001) details division of responsibilities detween MISO BA and Local BAs- No gaps in coverage will be updated to reflect new Local BAs 7 4
Wind Generators Providing Primary and Secondary Control Resources Subcommittee April 24 and 25, 2013 Sydney Niemeyer Wind Generators and Primary Frequency Response 6465 MW of Wind Generation capacity has Primary Frequency Response active. Present maximum dead band of +/ 0.036 Hz. Reduces to +/ 0.017 Hz under BAL 001 TRE 1. Droop at 5% of Real Time Pmax based on available wind. Approximately 200 MW/0.1 Hz from fleet when full wind is available. No requirement to hold spinning reserve. 2409 MW of Wind Generation capacity has been granted a PFR requirement waiver. 2200 MW of Wind Generation capacity has unknown PFR status. 1
Wind Generator Primary Frequency Response Challenges Load Reference while operating at maximum output and responding to high frequency. Once grid frequency exceeds the governor dead band on the high side what load reference can be used to determine how many MW of response is appropriate? Calculate a pseudo Load Reference using Production Potential calculation that is smoothed over a short time period. While not operating at maximum output the Load Reference will be similar to traditional generators. Wind Resources and Primary Frequency Response EVIDENCE OF PERFORMANCE 2
Response to a High Frequency Period ERCOT TOTAL WIND GENERATION 60.06 Friday, April 12, 2013 Unit:Wind Fleet 1.002 Initial P.U. Performance 1.305 Sustained P.U. Performance 2960.0 2940.0 60.04 2919.74 60.024 2920.0 60.02 2900.0 Frequency Hz 60 2867.006 2880.0 MW 59.98 59.988 2866.91 2860.0 59.96 Evaluation based on 6465 MW of Wind Farm capacity available that has Primary Frequency Response. 2840.0 2820.0 59.94 2800.0 7:58:22 7:58:32 7:58:42 7:58:52 7:59:02 7:59:12 7:59:22 7:59:32 7:59:42 7:59:52 8:00:02 8:00:12 8:00:22 Hz Average Frequency MW Average MW "EPFR" ESPFR(Final@T(+46)) 3
60.06 60.04 Friday, April 12, 2013 Unit:Wind Fleet 7:59:22 Time of t(0) 7:59:28 Model Period Ending Time Primary Frequency Response provided during sudden increase in grid frequency. 3100.0 3000.0 60.02 2900.0 60 Frequency Hz 59.98 59.96 2800.0 2700.0 MW 59.94 59.92 Wind Fleet ramping down due to loss of wind. Dropping about 30 MW/min on average. 2600.0 2500.0 59.9 2400.0 7:58:227:59:228:00:228:01:228:02:228:03:228:04:228:05:228:06:228:07:228:08:228:09:228:10:228:11:228:12:228:13:228:14:22 Hz Unit:Wind Fleet MW Model Period Target MW Model Period Ramp MW 60.10 60.08 60.06 60.04 60.02 60.00 3/29/2013 Frequency high during early morning off peak to on peak transition. Total Wind Generation 6660. 6636. 6612. 6588. 6564. 6540. 59.98 59.96 59.94 59.92 59.90 59.88 59.86 59.84 Primary Frequency Response provided during gradual increase in grid frequency. Output of fleet dropped about 175 MW during the high frequency. Output returned to normal as frequency returned to schedule. 6516. 6492. 6468. 6444. 6420. 6396. 6372. 6348. 59.82 6324. 59.80 6300. 5:43:00 5:45:05 5:47:10 5:49:15 5:51:20 5:53:25 5:55:30 5:57:35 5:59:40 6:01:45 6:03:50 6:05:55 6:08:00 Hz Wind Generation 4
60.10 60.08 60.06 60.04 60.02 60.00 59.98 59.96 59.94 59.92 3/30/2013 Total Wind Generation 6215. 6174. 6133. 6092. 6051. 6010. 5969. 5928. 5887. 5846. 59.90 59.88 59.86 59.84 59.82 Provided similar Primary Frequency Response during the next day s high frequency period. 5805. 5764. 5723. 5682. 5641. 59.80 5600. 5:48:00 5:50:05 5:52:10 5:54:15 5:56:20 5:58:25 6:00:30 6:02:35 6:04:40 6:06:45 6:08:50 6:10:55 6:13:00 Hz Wind Generation Low Frequency Event while the Wind Farm is curtailed to zero MW output due to transmission congestion. WIND FARM DELIVERY OF PRIMARY FREQUENCY RESPONSE 5
At all times the generator is Released for Dispatch ERCOT PROTOCOLS REQUIRE GOVERNORS TO BE IN SERVICE Friday, December 14, 2012 59.98 Unit: Wind Farm 5% Droop @ +/ 0.036 Hz dead band 59.964 0.900 Initial P.U. Performance 0.820 Sustained P.U. Performance 6.0 59.96 5.4 59.94 4.8 59.92 4.2 Frequency Hz 59.9 59.88 59.86 59.84 Wind Farm curtailed to zero MW output with 111 MW of wind available. Governor in service and free to respond to all frequency deviations outside dead band. 2.23 59.906 2.448 3.6 3.0 2.4 1.8 MW 59.82 1.2 59.8 0.25 0.6 59.78 0.0 16:12:10 16:12:20 16:12:30 16:12:40 16:12:50 16:13:00 16:13:10 16:13:20 16:13:30 16:13:40 16:13:50 16:14:00 16:14:10 Hz Average Frequency MW Average MW "EPFR" ESPFR(Final@T(+46)) 6
60.08 60.06 60.04 60.02 Friday, December 14, 2012 Unit: Wind Farm 5% Droop @ +/ 0.036 Hz dead band 16:13:10 Time of t(0) 16:16:56 Model Period Ending Time 6.0 5.0 60 Frequency Hz 59.98 59.96 59.94 59.92 59.9 59.88 59.86 59.84 As grid frequency returned to 60 Hz the governor provided proportional Primary Frequency Control. Frequency returned to normal in 3.5 minutes. 4.0 3.0 2.0 MW 59.82 1.0 59.8 59.78 59.76 0.0 59.74 59.72 1.0 Hz Unit: Langford MW Model Period Target MW Model Period Ramp MW WIND FARM AND SECONDARY CONTROL 7
17-FEB-13 00:15:00 UDBP -0.117 Output ROC 0.128 60.1 0.293 0.014-3.482-3.190-6.963-6.504 155 MW Wind Farm -5.317 1.375-1.516-5.280 1.016-1.299-2.420-2.435 1.483 1.281 6.003 5.548 6.521 6.566 2.785 MW/min avg 3.087 150 60.08 135 60.06 120 60.04 105 60.02 Frequency Hz 60 90 75 MW 59.98 60 59.96 59.94 59.92 Wind Farm receives a curtailment from the ISO. 5 minute Economic Base Point steps down. AGC of Wind Farm follows 4 second ramped base point Cyan. 45 30 15 59.9 0 0:15:00 0:20:00 0:25:00 0:30:00 0:35:00 0:40:00 0:45:00 0:50:00 0:55:00 1:00:00 1:05:00 1:10:00 1:15:00 Frequency BP UDBP Target MW 17-FEB-13 00:15:00 UDBP -0.117 Output ROC 0.128 20 18 16 14 12 10 0.293 0.014-3.482-3.190-6.963-6.504 155 MW Wind Farm -5.317 1.375-1.516-2.420-5.280 1.016-1.299-2.435 1.483 1.281 6.003 5.548 Cyan is the target, Magenta is the MW output of the wind farm. Target ramps for four minutes to the next 5 minute Economic Base Point. The target includes expected Primary Frequency Response. 6.521 6.566 2.785 MW/min avg 3.087 165 150 135 8 120 6 Control Error - MW 4 2 0-2 -4 105 90 75 MW -6-8 -10-12 -14-16 0.328-0.009 0.627 1.433 0.736-0.955 0.017 0.081-1.033-2.422 Average Control Error - 5 minute. Limit is 10 MW over-production. The Control Error is the difference between the Target and the Actual MW output. -2.117-1.082 60 45 30-18 -20 15 0:15:00 0:20:00 0:25:00 0:30:00 0:35:00 0:40:00 0:45:00 0:50:00 0:55:00 1:00:00 1:05:00 1:10:00 1:15:00 Langford Control Error BP UDBP Target MW 8
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Primary and Secondary Control Interaction Resources Subcommittee April 24 & 25, 2013 Sydney Niemeyer Primary and Secondary Control Interaction Concern that if a resource is providing Primary Frequency Control it could impact the BA s As performance and recovery during a DCS or BAAL event. Valid concern when ACE Bias setting does not match actual Primary Frequency Response of the BA. BAL 003 1 allows for a gradual reduction of the overbias of the Interconnections and also allows for the use of a Variable Bias Setting. Bias setting in the ACE equation that closely matches actual Primary Frequency Response minimizes interaction of Control. 1
Droop Implementation Correct implementation of the droop function at the resource. Proportional control to frequency change that is bidirectional. Reducing governor dead bands will reduce frequency movement of the Interconnection. This will reduce resource movement due to Primary Frequency Control. Elimination i of step t response of the governor at the dead band. Incorrect implementation of droop at the resource will impact Secondary Control and DCS and BAAL performance. Governor Droop Governor droop implementation. Slope = MW PMAX /(3.0 Hz Governor Dead Band Hz) For 5% droop Result is MW/Hz change of generator output. Slope = MW PMAX /(2.4 Hz Governor Dead Band Hz) For 4% droop Result is MW/Hz change of generator output. 2
For Frequency below 60 Hz and below governor dead band MW Pr imarycontrol Primary Frequency Control HZ actual 60 DB *( Re )*( 1) 60* Frequency sponsivecapacity Droop DB Droop expressed as 0.05 for 5% droop. Dead band in Hz. Generator Output MW = Load Set point MW + MW Pi PrimaryControl Where Load Set point is the Economic Dispatch Base Point or Plant Load Reference and may include any Regulation Ancillary Service. For Frequency Above 60 Hz and Above Governor Dead band MW Pr imarycontr ol Primary Frequency Control HZ 60 actual DB *( Re )*( 1) 60* Frequency sponsivecapacity Droop DB Droop expressed as 0.05 for 5% droop. Dead band in Hz. Generator Output MW = Load Set point MW + MW PrimaryControl Where Load Set point is the Economic Dispatch Base Point or Plant Load Reference and may include any Regulation Ancillary Service. 3
750 MW Steam Unit @ 5% Droop with Mechanical Governor 60.08 60.06 60.04 Primary Control 275.00 264.00 253.00 60.02 242.00 60 231.00 59.98 220.00 59.96 209.00 Frequency 59.94 59.92 59.9 Secondary Control 198.00 187.00 176.00 MW 59.88 165.00 59.86 154.00 59.84 143.00 59.82 132.00 59.8 121.00 59.78 110.00 0:10:00 0:15:00 0:20:00 0:25:00 0:30:00 0:35:00 0:40:00 0:45:00 0:50:00 0:55:00 1:00:00 1:05:00 1:10:00 Frequency Actual MW Perfect Target Minimum Target 750 MW Steam Unit @ 5% Droop with Mechanical Governor 60.08 260.00 60.06 60.04 60.02 Primary Control 254.00 248.00 242.00 60 236.00 59.98 230.00 59.96 224.00 Frequency 59.94 59.92 218.00 212.00 MW 59.9 206.00 59.88 200.00 59.86 59.84 Secondary Control 194.00 188.00 59.82 182.00 59.8 176.00 59.78 170.00 0:25:00 0:26:00 0:27:00 0:28:00 0:29:00 0:30:00 0:31:00 0:32:00 0:33:00 0:34:00 0:35:00 0:36:00 0:37:00 0:38:00 0:39:00 0:40:00 Frequency Actual MW Perfect Target Minimum Target 4
Consortium for Electric Reliability Technology Solutions NERC Applications Status NERC Applications Status for Resources Subcommittee Gil Tam San Diego, CA April 24-25, 2013 Agenda NERC Application Status Summary Implemented 2013 CPS 2 Bounds Report values in all NERC applications 2012 ARR Yearly Report Highlights Review Draft WECC Interconnection Frequency Performance Report for Year 2012 per RS Request at Last Meeting. Apr 2013 Page 1 1
NERC Applications Status Summary Application Resource Adequacy (ACE Frequency) Inadvertent Area Interchange Error (AIE) NERC Applications Status and Authorized Users (Many companies have several authorized users) Release 7.0 Current Production version 171 authorized users. Release 3.5 Current Production version 281 authorizedusers users Completion of new website design to resolve existing application interface with Window 7 is ongoing. Release 1.0 Current production version 122 authorized users Intelligent Alarms Frequency Monitoring and Analysis (FMA) Automated Reliability Reports (ARR) Release 1.0 Current production version 140 authorized users Release 2.5 Current production version 121 authorized users Release 1.0 Current production version 64 authorized users Monthly reports through March 2013, Seasonal reports through Winter 2013 and 2012 Yearly Report have been posted in ARR website. Apr 2013 Page 2 Interconnections Annual Reliability Report ARR 2012 Report Highlights: Number of hours during which Interconnections Epsilon Variability Exceeded Statistical Process Control (SPC) Criteria increased from year 2011 for the EI and WI, and decreased dfor ERCOT Eastern, increased from 4 to 5 ERCOT, decreased from 7 to 1 Western, increased from 3 to 6 Interconnections CPS1 and CPS2 Trend: All three Interconnections operated above CPS1 threshold Eastern and Western operated below CPS2 threshold; ERCOT operated above CPS2 threshold (ERCOT is exempted from CPS2) Graph for 6 years attached Number of Events when Frequency > FTL Low/High Limits: FTL Low limit All three interconnections decreased from 2011 FTL High limit All three interconnections decreased from 2011 Apr 2013 Page 3 2
Interconnections CPS1 6 Year Trend Apr 2013 Page 4 Interconnections CPS2 6 Year Trend Apr 2013 Page 5 3
Interconnections Frequency Response Trend These Frequency Response values are calculated using 1-second frequency data collected under the BAL-003-1 field trial process and the reported actual MW loss data. Frequency Response values are calculated by the equation: Fr = MWLoss/10(FreqB - FreqA) Apr 2013 Page 6 WECC Frequency Control & Time Error Correction Report DRAFT Prepared By: Electric PowerGroup For: RESOURCES SUBCOMMITTEE MARCH 2013 4
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THANK YOU. Gil Tam Tam@ElectricPowerGroup.com 201 South Lake Avenue, Ste 400 Pasadena, CA 91101 626 685 2015 www.electricpowergroup.com Apr 2013 Page 28 15
ERCOT Frequency Control & Time Error Correction Report Resources Subcommittee Meeting San Diego, California April 25, 2013 ERCOT Time Error Corrections 2013 Time Corrections Total Hours on Avg Hours Avg Corrections % Time on Year Month Days Fast Slow Count Control Per Correction Per Day Correction 2013 Jan 31 0 3 3 9.50 3.17 0.10 1.3% Feb 28 0 6 6 18.00 3.00 0.21 2.7% Mar 31 0 5 5 17.50 3.50 0.16 2.4% November 1, 2012 ERCOT changed the maximum allowed Time Error to 30 seconds before initiating a TEC. When executing a Time Correction they stopped when a total of 3 seconds were corrected. It took almost 30 days to reach the first TEC. Then in December the corrections occurred at the normal interval. 1
November 1, 2012 ERCOT performs TEC at +/ 30 seconds. Jan 8, 2013 ERCOT Load Frequency Control Tuning adjusted. Monthly Hours on Time Correction 90 80 70 Total Hours on Correction 60 50 40 30 20 10 0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Hours on Control 2
Monthly Time Correction Summary 25 20 Number of Corrections 15 10 5 0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Slow Fast Frequency Profile, CPS1 & 2, Daily RMS1 & ERCOT Total Energy and Wind Generation. ERCOT FREQUENCY CONTROL PERFORMANCE 3
50000 ERCOT Frequency Profile Comparison January through December of each Year 45000 40000 One Minute Occurances 35000 30000 25000 20000 15000 10000 5000 0 59.9 59.91 59.92 59.93 59.94 59.95 59.96 59.97 59.98 59.99 60 60.01 2010 2013 60.02 60.03 60.04 60.05 60.06 60.07 60.08 60.09 60.1 ERCOT Frequency Control Tuning Adjustments to LFC tuning are scheduled for later in the month of April. ERCOT modification to Generation to be Dispatched to include a portion of average Regulation deployed. Minor LFC tuning changes included. Goal to correct the Up Regulation service deployment bias. Frequency profile skew is above 60.0000 Hz Consistent slow time error corrections. Correctly price energy by minimizing dependence on Regulation. 4
170 ERCOT CPS1 12 Month rolling average CPS1 = 165.23 170 160 160 150 150 CPS1 Average e 140 130 140 130 120 120 110 100 Jan-06 Nov-05 Sep-05 Jul-05 May-05 Mar-05 Jan-05 Nov-04 Sep-04 Jul-04 May-04 Mar-04 Jan-04 Nov-03 Sep-03 Jul-03 May-03 Nov-09 Sep-09 Jul-09 May-09 Mar-09 Jan-09 Nov-08 Sep-08 Jul-08 May-08 Mar-08 Jan-08 Nov-07 Sep-07 Jul-07 May-07 Mar-07 Jan-07 Nov-06 Sep-06 Jul-06 May-06 Mar-06 Mar-13 Jan-13 Nov-12 Sep-12 Jul-12 May-12 Mar-12 Jan-12 Nov-11 Sep-11 Jul-11 May-11 Mar-11 Jan-11 Nov-10 Sep-10 Jul-10 May-10 Mar-10 Jan-10 110 100 Monthly Average 12 Month Rolling Average 100 ERCOT CPS2 Score* *ERCOT as a single control area is exempt from CPS2. These scores are For Information Only 95 90 CPS2 85 80 75 70 Jan-09 Oct-08 Jul-08 Apr-08 Jan-08 Oct-07 Jul-07 Apr-07 Jan-07 Oct-06 Jul-06 Apr-06 Jan-06 Oct-05 Jul-05 Apr-10 Jan-10 Oct-09 Jul-09 Apr-09 Jan-13 Oct-12 Jul-12 Apr-12 Jan-12 Oct-11 Jul-11 Apr-11 Jan-11 Oct-10 Jul-10 Month CPS2 5
Daily RMS1 of ERCOT Frequency 0.0500 0.0450 00400 0.0400 0.0350 0.0300 0.0250 0.0200 0.0150 0.0100 1/1/2000 7/1/2000 1/1/2001 7/1/2001 1/1/2002 7/1/2002 1/1/2003 7/1/2003 1/1/2004 7/1/2004 1/1/2005 7/1/2005 1/1/2006 7/1/2006 1/1/2007 7/1/2007 1/1/2008 7/1/2008 1/1/2009 7/1/2009 Daily RMS1 of ERCOT Frequency 1/1/2010 7/1/2010 1/1/2011 7/1/2011 1/1/2012 7/1/2012 1/1/2013 0.0500 0.0450 0.04000400 0.0350 0.0300 0.0250 0.0200 0.0150 0.0100 1/1/2004 4/1/2004 7/1/2004 10/1/2004 1/1/2005 4/1/2005 7/1/2005 10/1/2005 1/1/2006 4/1/2006 7/1/2006 10/1/2006 1/1/2007 4/1/2007 7/1/2007 10/1/2007 1/1/2008 4/1/2008 7/1/2008 10/1/2008 1/1/2009 4/1/2009 7/1/2009 10/1/2009 1/1/2010 4/1/2010 7/1/2010 10/1/2010 1/1/2011 4/1/2011 7/1/2011 10/1/2011 1/1/2012 4/1/2012 7/1/2012 10/1/2012 1/1/2013 6
Daily RMS1 of ERCOT Frequency 0.0500 0.0450 00400 0.0400 0.0350 0.0300 0.0250 0.0200 0.0150 0.0100 1/1/2007 4/1/2007 7/1/2007 10/1/2007 1/1/2008 4/1/2008 7/1/2008 10/1/2008 1/1/2009 4/1/2009 7/1/2009 10/1/2009 1/1/2010 4/1/2010 7/1/2010 10/1/2010 1/1/2011 4/1/2011 ERCOT Total Energy 7/1/2011 10/1/2011 1/1/2012 4/1/2012 7/1/2012 10/1/2012 1/1/2013 45,000,000 40,000,000 35,000,000 30,000,000 MWH 25,000,000 20,000,000 15,000,000 10,000,000 5,000,000 0 January February March April May June July August September October November December 2008 2009 2010 2011 2012 2013 7
4,000,000 ERCOT Total Energy from Wind Generation Peak Wind Generation 9,477 MW Feb 9 @ 19:08 10,570 MW installed capacity. 3,500,000 3,000,000 2,500,000 MWH 2,000,000 1,500,000 1,000,000 500,000 0 January February March April May June July August September October November December 2008 2009 2010 2011 2012 2013 ERCOT % Energy from Wind Generation 16.00% 14.00% 12.00% 10.00% 8.00% 6.00% 4.00% 2.00% 0.00% January February March April May June July August September October November December 2008 2009 2010 2011 2012 2013 8
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