5/1/2013

1

MISO BA Integration Update

NERC Resources Subcommittee

April 2013

MISO Reliability Coordination expansion– 6/1/2013

CWAY215 MW

NLRWMU

# Acronym BA Name 

1 CLEC CLECO

2 SMESouth Mississippi Electric Power Association

3 LAGN Louisiana Generating, LLC

SME1,601 MW

CLEC

NLR245 MW

95 MW

LAGN

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 City of North Little Rock, AR

2

LEPA231 MW

CLEC2,209 MW

LAFA495 MW

LAGN2,247 MW

5/1/2013

2

MISO Balancing Authority Expansion – 12/19/2013

OMLP38 MW

CWAY215 MW

NLRWMU

PLUM1

665 MW

# Acronym BA Name2

1

EES Entergy (Louisiana, Texas, Mississippi, New Orleans, Arkansas*)* 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

SME1,601 MW

CLEC

BUBA80 MW

NLR245 MW

DERS69 MW

95 MW

PUPP1

2,267 MW

LAGN

BBA1

578 MW

EES (incl. EAI)23,211 MW

pp

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 City of 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

9 BA’s expected to dissolve on 12/19/2013

3

LEPA231 MW

CLEC2,209 MW

LAFA495 MW

LAGN2,247 MWBRAZ

87 MW

13 BUBA City of Benton, AR

14 CWAY City of Conway, AR

15 NLR City of North Little Rock, AR

16BBA Batesville Generation – merging into

SME 6/1/13.

1Generaton only Balancing Authorities. 2 Several BAs plan to dissolve BAs and integrate 12/19/2013.

BA Area Interfaces- Existing

AECI

TVAOKGE

EDEMISO

OMLPCWAY

WMU

PLUM

BBA

SME

SOCO

CSWS

ERCO

SPA

BUBA

NLR

DERS

PUPP

EES

4

LEPA

CLEC

LAFALAGN

BRAZ

AEC

5/1/2013

3

MISO Balancing Authority (BA) / Local Balancing Authorities Areas – 12/19/2013

# Acronym LBA Name

1

EES Entergy (Louisiana, Texas, Mississippi, New Orleans, Arkansas*)* Entergy also committed to Arkansas Commission to split off Entergy Arkansas into a separate LBA (EAI)

SME

CLEC

EES

EAI

MISOBA

LBA (EAI)

2 EAI Entergy ‐ Arkansas

3 CLEC CLECO

4 SMESouth Mississippi Electric Power Association

5 LAGN Louisiana Generating, LLC

6 LAFA Lafayette Utilities System

7 LEPALouisiana Energy and Power Authority

5

LEPA

CLEC

LAFA

LAGN

RC and BA Integration Schedule

#Acronym

BA Name RC BA/Market

1EES 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 City of 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

6

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

5/1/2013

4

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 theprocedures, 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) detailsCoordinated 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

5/1/2013

1

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• 2409 MW of Wind Generation capacity has been granted a PFR requirement waiver.

• 2200 MW of Wind Generation capacity has unknown PFR status.

5/1/2013

2

Wind Generator Primary Frequency Response Challenges

• Load Reference while operating at maximum output and responding to high frequencyoutput 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 shortPotential 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

5/1/2013

3

Response to a High Frequency Period

ERCOT TOTAL WIND GENERATION

2920.0

2940.0

2960.0

60.04

60.06

Unit:Wind Fleet

60.024

2919.74

1.002 Initial P.U. PerformanceFriday, April 12, 2013

1.305 Sustained P.U. Performance

2860.0

2880.0

2900.0

59.98

60

60.02

Frequency ‐Hz

2866.91

MW

59.988

2867.006

2800.0

2820.0

2840.0

59.94

59.96

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))

Evaluation based on 6465 MW of Wind Farm capacity available that has Primary Frequency Response.

5/1/2013

4

2900.0

3000.0

3100.0

60.02

60.04

60.06

Unit:Wind FleetFriday, April 12, 2013

7:59:28 Model Period Ending Time

7:59:22 Time of t(0)

Primary Frequency Response provided during sudden increase in grid frequency.

2600.0

2700.0

2800.0

59.94

59.96

59.98

60

Frequency ‐Hz

MW

Wind Fleet ramping down due 

2400.0

2500.0

59.9

59.92

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

to loss of wind.  Dropping about 30 MW/min on average.

6564.

6588.

6612.

6636.

6660.

60.02

60.04

60.06

60.08

60.10

Total Wind Generation3/29/2013

Frequency high during early morning off‐peak to on‐peak transition.

6396

6420.

6444.

6468.

6492.

6516.

6540.

59 88

59.90

59.92

59.94

59.96

59.98

60.00

Output of fleet dropped about 175 MW during the high frequency.  Output returned to normal as frequency returned to schedule.

6300.

6324.

6348.

6372.

6396.

59.80

59.82

59.84

59.86

59.88

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

Primary Frequency Response provided during gradual increase in grid frequency.

5/1/2013

5

6051.

6092.

6133.

6174.

6215.

60.02

60.04

60.06

60.08

60.10

Total Wind Generation3/30/2013

5764

5805.

5846.

5887.

5928.

5969.

6010.

59 88

59.90

59.92

59.94

59.96

59.98

60.00

Provided similar Primary

5600.

5641.

5682.

5723.

5764.

59.80

59.82

59.84

59.86

59.88

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

Provided similar Primary Frequency Response during the next day’s high frequency period.

Low Frequency Event while the Wind Farm is curtailed to zero MW output due to transmission congestion.

WIND FARM DELIVERY OF PRIMARY FREQUENCY RESPONSE

5/1/2013

6

At all times the generator is “Released for Dispatch”

ERCOT PROTOCOLS REQUIRE “GOVERNORS TO BE IN SERVICE”

4.8

5.4

6.0

59.94

59.96

59.98 Unit: Wind Farm 5% Droop @ +/‐0.036 Hz dead‐band

0.900 Initial P.U. PerformanceFriday, December 14, 2012

0.820 Sustained P.U. Performance

59.964

1.8

2.4

3.0

3.6

4.2

59.84

59.86

59.88

59.9

59.92

Frequency ‐Hz

2.23

59.906 MW

2.448

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

0.0

0.6

1.2

59.78

59.8

59.82

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))

0.25

band.

5/1/2013

7

4.0

5.0

6.0

59.98

60

60.02

60.04

60.06

60.08

Unit: Wind Farm 5% Droop @ +/‐0.036 Hz dead‐band

Friday, December 14, 2012

16:16:56 Model Period Ending Time

16:13:10 Time of t(0)

1.0

2.0

3.0

59.8

59.82

59.84

59.86

59.88

59.9

59.92

59.94

59.96

Frequency ‐Hz

MW

As grid frequency returned to 60 Hz the governor provided proportional Primary Frequency Control.  Frequency returned to normal in 3.5 minutes.

‐1.0

0.0

59.72

59.74

59.76

59.78

59.8

Hz Unit: Langford MW Model Period Target MW Model Period Ramp MW

WIND FARM AND SECONDARY CONTROL

5/1/2013

8

155 MW Wind Farm

60.06

60.08

60.1

120

135

150

-0.117

0.128

0.293

0.014

-3.482

-3.190

-6.963

-6.504

-5.317

-5.280

1.375

1.016

-1.516

-1.299

-2.420

-2.435

1.483

1.281

6.003

5.548

6.521

6.566

2.785

3.087

UDBP

Output ROCMW/min avg

17-FEB-13 00:15:00

59.96

59.98

60

60.02

60.04

Fre

qu

ency

Hz

60

75

90

105

MW

59.9

59.92

59.94

59.96

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

0

15

30

45

Frequency BP UDBP Target MW

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”.

155 MW Wind Farm

10

12

14

16

18

20

135

150

165

-0.117

0.128

0.293

0.014

-3.482

-3.190

-6.963

-6.504

-5.317

-5.280

1.375

1.016

-1.516

-1.299

-2.420

-2.435

1.483

1.281

6.003

5.548

6.521

6.566

2.785

3.087

UDBP

Output ROCMW/min avg

17-FEB-13 00:15:00

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.

-8

-6

-4

-2

0

2

4

6

8

Co

ntr

ol

Err

or

- M

W

60

75

90

105

120

MW

0.328 -0.009 0.627 1.433 0.736 -0.955 0.017 0.081 -1.033 -2.422 -2.117 -1.082

-20

-18

-16

-14

-12

-10

8

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

15

30

45

60

Langford Control Error BP UDBP Target MW

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.

5/1/2013

9

Questions?

5/1/2013

1

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 Frequency Control it could impact the A sperformance 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 “over‐bias” of the Interconnections and also allows for the 

f V i bl Bi S iuse of a Variable Bias Setting.

• Bias setting in the ACE equation that closely matches actual Primary Frequency Response minimizes interaction of Control.

5/1/2013

2

Droop Implementation

• Correct implementation of the droop function at the resource.the resource.– Proportional control to frequency change that is bi‐directional.

– Reducing governor dead‐bands will reduce frequency movement of the Interconnection.  This will reduce resource movement due to Primary Frequency Control.Eli i ti f “ t ” f th t th– Elimination of “step 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 = MWPMAX/(3 0 Hz – Governor Dead‐Band Hz)Slope = MWPMAX/(3.0 Hz  Governor Dead Band Hz)

– For 5% droop

– Result is MW/Hz change of generator output.

• Slope = MWPMAX/(2.4 Hz – Governor Dead‐Band Hz)– For 4% droop

– Result is MW/Hz change of generator output.

5/1/2013

3

)1(*)R(*

60

ii CFDBHZ

MW actual

For Frequency below 60 Hz and below governor dead‐band

Primary Frequency Control

)1(*)Re(*

*60Pr

pacitysponsiveCaFrequencyDBDroop

MW actualolimaryContr

Droop expressed as 0.05 for 5% droop.Dead‐band in Hz.

Generator Output MW = Load Set‐point MW + MWP i C t lGenerator Output MW   Load Set point MW + MWPrimaryControl

Where Load Set‐point is the Economic Dispatch Base Point or Plant Load Reference and may include any “Regulation Ancillary Service”.

)1(*)Re(*

60P

pacitysponsiveCaFrequencyDBHZ

MW actualli C t

For Frequency Above 60 Hz and Above Governor Dead‐band

Primary Frequency Control

)1(*)Re(**60

Pr

pacitysponsiveCaFrequencyDBDroop

MW olimaryContr

Droop expressed as 0.05 for 5% droop.Dead‐band in Hz.

Generator Output MW = Load Set‐point MW + MWPrimaryControl

Where Load Set‐point is the Economic Dispatch Base Point or Plant Load Reference and may include any “Regulation Ancillary Service”.

5/1/2013

4

231.00

242.00

253.00

264.00

275.00

60

60.02

60.04

60.06

60.08

750 MW Steam Unit @ 5% Droop with Mechanical Governor

Primary Control

165.00

176.00

187.00

198.00

209.00

220.00

59.88

59.9

59.92

59.94

59.96

59.98

MW

Fre

qu

en

cy

Secondary Control

110.00

121.00

132.00

143.00

154.00

59.78

59.8

59.82

59.84

59.86

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

236.00

242.00

248.00

254.00

260.00

60

60.02

60.04

60.06

60.08

750 MW Steam Unit @ 5% Droop with Mechanical Governor

Primary Control

200.00

206.00

212.00

218.00

224.00

230.00

59.88

59.9

59.92

59.94

59.96

59.98

MW

Fre

qu

en

cy

170.00

176.00

182.00

188.00

194.00

59.78

59.8

59.82

59.84

59.86

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

Secondary Control

5/1/2013

1

Consortium forElectric ReliabilityTechnologySolutions

NERC Applications

StatusSolutions

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

Page 1

Performance Report for Year 2012 per RS Request at Last Meeting.

Apr 2013

5/1/2013

2

NERC Applications Status Summary

Application NERC Applications Status and Authorized Users(Many companies have several authorized users) 

ResourceAdequacy

(ACE Frequency)

Release 7.0 – Current Production version – 171 authorized users.

Release 3 5 Current Production version 281 authorized users

Inadvertent

Area InterchangeError (AIE)

IntelligentAlarms

Release 3.5 – Current Production version – 281 authorized usersCompletion of new website design to resolve existing application interface with Window 7 is  on‐going.

Release 1.0 – Current production version – 122 authorized users

Release 1.0 – Current production version – 140 authorized users

Page 2

FrequencyMonitoring andAnalysis (FMA)

Release 2.5 – Current production version – 121 authorized users

Automated ReliabilityReports (ARR)

Release 1.0 – Current production version – 64 authorized usersMonthly reports through March 2013, Seasonal reports through Winter 2013 and 2012 Yearly Report have been posted in ARR website.  

Apr 2013

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 f th EI d WI d d d f ERCOT2011 for the EI and WI, and decreased for 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)

Page 3

( p )

• 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

5/1/2013

3

Interconnections CPS1  6‐Year Trend

Page 4Apr 2013

Interconnections CPS2  6‐Year Trend

Page 5Apr 2013

5/1/2013

4

Interconnections Frequency Response TrendThese 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)

Page 6Apr 2013

WECC Frequency Control & Time Error Correction Report

DRAFT

Prepared By: Electric Power GroupPrepared By: Electric Power Group

For: RESOURCES SUBCOMMITTEEMARCH 2013

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THANK YOU.

Gil Tam – Tam@ElectricPowerGroup.com

201 South Lake Avenue, Ste 400

Page 28

Pasadena, CA 91101 

626‐685‐2015

www.ElectricPowerGroup.com

Apr 2013

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1

ERCOT Frequency Control & Time Error Correction Report

Resources Subcommittee Meeting

San Diego, California

April 25, 2013

ERCOT Time Error Corrections2013

Total Hours on Avg Hours Avg Corrections % Time onYear Month Days Fast Slow Count Control Per Correction Per Day Correction

Time CorrectionsYear Month Days Fast Slow Count Control Per Correction Per Day Correction2013 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.

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November 1, 2012 ERCOT performs TEC at +/‐ 30 seconds.  Jan 8, 2013 ERCOT Load Frequency Control Tuning adjusted.

Monthly Hours on Time Correction

70

80

90

30

40

50

60

To

tal H

ou

rs o

n C

orr

ec

tio

n

0

10

20

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Hours on Control

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Monthly Time Correction Summary

20

25

10

15

Nu

mb

er o

f C

orr

ecti

on

s

0

5

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

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ERCOT Frequency Profile Comparison

40000

45000

50000s

January through December of each Year

10000

15000

20000

25000

30000

35000

On

e M

inu

te O

ccu

ran

ces

0

5000

10000

59.9

59.9

159

.92

59.9

359

.94

59.9

559

.96

59.9

759

.9859

.99 60

60.0

160

.02

60.0

360

.0460

.05

60.0

660

.07

60.0

860

.09

60.1

2010 2013

ERCOT Frequency Control Tuning

• Adjustments to LFC tuning are scheduled for later in the month of April.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 00 HzFrequency profile skew is above 60.00 Hz– Consistent slow time error corrections.– Correctly price energy by minimizing dependence on Regulation.

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ERCOT CPS1

150

160

170

e

150

160

170

12 Month rolling average CPS1 = 165.23

120

130

140

CP

S1

Av

era

ge

120

130

140

100

110

May-03

Jul-03S

ep-03N

ov-03Jan-04M

ar-04M

ay-04Jul-04S

ep-04N

ov-04Jan-05M

ar-05M

ay-05Jul-05S

ep-05N

ov-05Jan-06M

ar-06M

ay-06Jul-06S

ep-06N

ov-06Jan-07M

ar-07M

ay-07Jul-07S

ep-07N

ov-07Jan-08M

ar-08M

ay-08Jul-08S

ep-08N

ov-08Jan-09M

ar-09M

ay-09Jul-09S

ep-09N

ov-09Jan-10M

ar-10M

ay-10Jul-10S

ep-10N

ov-10Jan-11M

ar-11M

ay-11Jul-11S

ep-11N

ov-11Jan-12M

ar-12M

ay-12Jul-12S

ep-12N

ov-12Jan-13M

ar-13

100

110

Monthly Average 12 Month Rolling Average

ERCOT CPS2 Score*

95

100

*ERCOT as a single control area is exempt from CPS2. These scores are For Information Only

75

80

85

90

CP

S2

70

Jul-05O

ct-05Jan-06A

pr-06Jul-06O

ct-06Jan-07A

pr-07Jul-07O

ct-07Jan-08A

pr-08Jul-08O

ct-08Jan-09A

pr-09Jul-09O

ct-09Jan-10A

pr-10Jul-10O

ct-10Jan-11A

pr-11Jul-11O

ct-11Jan-12A

pr-12Jul-12O

ct-12Jan-13

MonthCPS2

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Daily RMS1 of ERCOT Frequency

0 0400

0.0450

0.0500

0.0200

0.0250

0.0300

0.0350

0.0400

0.0100

0.0150

1/1/

2000

7/1/

2000

1/1/2

001

7/1/2

001

1/1/

2002

7/1/

2002

1/1/

2003

7/1/2

003

1/1/2

004

7/1/

2004

1/1/

2005

7/1/2

005

1/1/2

006

7/1/

2006

1/1/

2007

7/1/

2007

1/1/

2008

7/1/2

008

1/1/2

009

7/1/

2009

1/1/

2010

7/1/2

010

1/1/2

011

7/1/

2011

1/1/

2012

7/1/

2012

1/1/2

013

Daily RMS1 of ERCOT Frequency

0 0400

0.0450

0.0500

0.0200

0.0250

0.0300

0.0350

0.0400

0.0100

0.0150

1/1/

2004

4/1/

2004

7/1/

2004

10/1

/200

4

1/1/

2005

4/1/

2005

7/1/

2005

10/1

/200

5

1/1/

2006

4/1/

2006

7/1/

2006

10/1

/200

6

1/1/

2007

4/1/

2007

7/1/

2007

10/1

/200

7

1/1/

2008

4/1/

2008

7/1/

2008

10/1

/200

8

1/1/

2009

4/1/

2009

7/1/

2009

10/1

/200

9

1/1/

2010

4/1/

2010

7/1/

2010

10/1

/201

0

1/1/

2011

4/1/

2011

7/1/

2011

10/1

/201

1

1/1/

2012

4/1/

2012

7/1/

2012

10/1

/201

2

1/1/

2013

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Daily RMS1 of ERCOT Frequency

0 0400

0.0450

0.0500

0.0200

0.0250

0.0300

0.0350

0.0400

0.0100

0.0150

1/1/

2007

4/1/

2007

7/1/

2007

10/1

/200

7

1/1/

2008

4/1/

2008

7/1/

2008

10/1

/200

8

1/1/

2009

4/1/

2009

7/1/

2009

10/1

/200

9

1/1/

2010

4/1/

2010

7/1/

2010

10/1

/201

0

1/1/

2011

4/1/

2011

7/1/

2011

10/1

/201

1

1/1/

2012

4/1/

2012

7/1/

2012

10/1

/201

2

1/1/

2013

ERCOT Total Energy

35,000,000

40,000,000

45,000,000

5 000 000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

MW

H

0

5,000,000

Janu

ary

Febru

ary

Mar

chApr

ilM

ayJu

ne July

Augus

t

Septe

mbe

r

Octob

er

Novem

ber

Decem

ber

2008 2009 2010 2011 2012 2013

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ERCOT Total Energy from Wind Generation

3,000,000

3,500,000

4,000,000Peak Wind Generation 9,477 MW Feb 9 @ 19:08

10,570 MW installed capacity.

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

MW

H

0

500,000

Janu

ary

Febru

ary

Mar

chApr

ilM

ayJu

ne July

Augus

t

Septe

mbe

r

Octob

er

Novem

ber

Decem

ber

2008 2009 2010 2011 2012 2013

ERCOT % Energy from Wind Generation

12.00%

14.00%

16.00%

2.00%

4.00%

6.00%

8.00%

10.00%

0.00%

2.00%

Janu

ary

Febru

ary

Mar

chApr

ilM

ayJu

ne July

Augus

t

Septe

mbe

r

Octob

er

Novem

ber

Decem

ber

2008 2009 2010 2011 2012 2013

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Questions?