transmission planning process discussion joint plwg / cmwg meeting presented by: luminant energy...

Transmission Planning Process DiscussionJoint PLWG / CMWG Meeting

Presented by: Luminant Energy

June 14, 2011

Outline

2

Executive Summary

Background

Detailed Discussion

Rio Grande Valley Import

DFW Imports Southeast of Dallas

Long-Term Autotransformer Outage Risk

Next Steps

Executive Summary

3

ERCOT’s planning process is superior to most and continues to improve The RPG process open to all interested stakeholders to develop & submit projects ERCOT holds regular open meetings to discuss ongoing issues with the market The ERCOT RPG process reviews a large number of project proposals

This culture of continuous improvement requires periodic review to see if amendments to the current planning criteria / process may be appropriate Valley Import Situation in 2010/2011+ ($76 million) in the first 120 days after Nodal Go-Live1 DFW Imports SE of Dallas – congestion observed in 2010 & aggravated by Valley mothballing Long Term Auto Forced Outages – multiple outages (e.g. Bellaire, Cedar Hill, etc…) lasted

several months, which could have caused market impacts if occurring over summer peak

TAC’s May 5th, 2011 directive to the PLWG / CMWG to develop processes that close the gaps between operations and planning provides for reevaluation of: Specific ways to clarify the language of the existing planning criteria to ensure more

consistent application by all parties going forward Specific criteria / process changes, both reliability and economic, that are needed to better

align transmission planning with operational realities

1) Calculated from Shadow price congestion of the Valley Import interface, Lon Hill – NE Edinburg 345 kV Line, and Rio Hondo 345/138 kV auto. According to John Dumas’s May 5, 2011 TAC presentation, there were an additional 43+ hours of manual management of the Valley Import constraint that would have pushed this cost to $300+ million.

We are hopeful that PLWG discussion of the examples discussed in this presentation will lead to a tighter integration of operational realities into the planning criteria /

processes in order to mitigate much of the SCED irresolvable congestion outcomes.

Executive Summary

4

Aspects of the planning criteria that need to be clarified / improved are: Load Variability – lack of clarity regarding reasonable load variability in studies Thermal Generation Availability – need a common way to recognize large area

expected generation capacity unavailability Ancillary Service – planning process assumes real time co-optimization of energy

and A/S, to such a degree that outcomes of no RRS, URS, and NSRS capacity being carried in major load pockets (e.g. greater Houston & DFW) can occur1

Transmission Maintenance Outages – need a consistent method of protecting the transmission and generation maintenance windows.

Wind – need a clear definition of study requirements for high / low wind Dynamic Line Ratings – experience below nominal ratings when temperatures

associated with above normal weather load are studied Long Term Auto Outages – similar impact to system as loss of a large unit Operational Safety Margin – Operations has found the need to utilize a safety

margin in some cases (W-N, Valley import) that isn’t being utilized in planning

Planning criteria / process guidance is needed with regard to these items to insure that consistent treatment / application of these issues occurs in all planning studies.

1) Potentially in conflict with the location considerations of Operation Guides Section 2.1 (1) (h), as well as, may be impractical to run multiple SASMs to accommodate.

Outline

5

Executive Summary

Background

Detailed Discussion




Next Steps

Planning Criteria Review

6

Nodal Operating Guides - Section 5.3 (2) The contingency studies will be performed for:

Reasonable variations of Load level, Generation schedules, Planned transmission line Maintenance Outages, and Anticipated power transfers.

At a minimum, this should include projected Loads for the upcoming summer and winter seasons and a five-year planning horizon.

The TSPs involved should plan to resolve any unacceptable study results through the provision of: Transmission Facilities, The temporary alteration of operating procedures (i.e., RAPs), Temporary Special Protection Systems (SPSs), or Other means as appropriate.

1) This exact same Planning language has been utilized since at least 2/20/2001 and is believed to have been in use several years before that.

For over a decade1, ERCOT has relied on this language to make sure that studies reflected reasonable variations of system conditions and resolved unacceptable outcomes via the provision of RAPs, SPSs, and Transmission Facilities


7

Nodal Operating Guides - Section 1 (Credible Single Contingency)

A single facility, comprised of transmission line, auto transformer, or other associated pieces of equipment…

The Forced Outage of a DCKT in excess of 0.5 miles in length… Any Generation Resource:

A combined-cycle facility shall be considered a single Generation Resource; or

Each unit of a combined-cycle facility will be considered a single Generation Resource if the combustion turbine and the steam turbine can operate separately, as stated in the Resource Registration on the MIS Public Area

Contingency studies are to be performed for single branch outages, DCKT lines in

excess of 0.5 miles, and Generation Resource outages.


8

Nodal Operating Guides - Section 1 (Credible Single Contingency)

With any single Generation Resource unavailable, and with any other generation preemptively redispatched, the contingency loss of a single Transmission Facility… with all other facilities normal should not cause the following:

a) Cascading or uncontrolled Outages;

b) Instability of Generation Resources at multiple plant locations; or

c) Interruption of service to firm Demand or generation other than that isolated by the transmission facility, following the execution of all automatic operating actions such as relaying and SPSs.

Furthermore, the loss should result in no damage to or failure of equipment and, following the execution of specific non-automatic predefined operator-directed actions (i.e., RAPs) such as generation schedule changes or curtailment of interruptible Load, should not result in applicable voltage or thermal ratings being exceeded.

Contingency studies are expected to consider generation redispatch, where possible, and ensure that no damage to equipment occurs following the execution of RAPs and

SPSs while continuing to serve demand and generation

Outline

9

Executive Summary

Background

Detailed Discussion




Next Steps

Detailed Discussion

10

Three specific project situations from across ERCOT have been chosen to facilitate a deeper discussion of the issues outline above: Rio Grande Valley Import – Since Nodal Go-Live (~6 month period):

Has experienced severe congestion, irresolvable constraints, and firm load shed

DFW Imports Southeast of Dallas (Trinidad Area) Experienced frequent congestion in summer 2010 Studies indicate situation further stressed by mothballing of Valley generation

Long-term Autotransformer Outage Risk Review Outages can last for several months, sometimes 12 months Similar market impact in many cases to loss of a large generating unit

These recent & ongoing issues aren’t meant to single anyone/thing out, rather to facilitate a deeper discussion of how to avoid them going forward Combination of existing / old studies utilized to illustrate key observations

What is common about all three of these specific situations is that the current application of the planning criteria / processes in some cases has hamstrung ERCOT and/or the TDSPs from developing timely transmission projects to mitigate this risk

Outline

11

Executive Summary

Background

Detailed Discussion




Next Steps

Rio Grande Valley - Overview

12

In the six months since Nodal Go-Live: Experienced over ~$75 million in congestion1

Has experienced 6.5 hours of SCED irresolvable congestion (reliability issue)2

Transmission Watches Issued on 2/3/11 (17:35) and 2/10/11 (06:10)3

Transmission Emergency Notice on 2/3/11 (22:29)3,4

Initial situation had an entire CCCT train out of service for planned maintenance Temperatures were ~28 degrees At 21:47 approximately 486 MW of CCCT generation forced out Voltage dropped to 0.91 pu (125 kV) ~442 MW of firm load was shed to recover voltage to acceptable levels All load was restored approximately 25 ½ hours later (2/4/11 at 23:28) Only ~$20 million of the~ $75 million since Nodal go-live occurred during this

Emergency Excluding the period of the Transmission Emergency, it is the combination of a

CCCT train being out-service for a planned outage and N-1 transmission security requirements that are associated with all this congestion.

It is alarming that the current planning process indicates that no transmission upgrades are needed to remedy this situation. It is important to identify what is

causing this gap between operational outcomes and planning studies1) Calculated from Shadow price congestion of the Valley Import interface, Lon Hill – NE Edinburg 345 kV Line, and Rio Hondo 345/138 kV auto; 2) Calculated as when constraint shadow price hit the shadow price cap; 3) Based on February 2011 ERCOT Operations Report to ROS; 4) Temperatures from NOAA; 5) The December 2010 ERCOT Constraint and Needs Report indicates no expected congestion associated with Rio Grande Valley Imports, while the 2010 Five-Year Plan (issued March 2011) doesn’t recommend any projects to address this severe congestion either.

Rio Grande Valley - Overview

13

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The Rio Grande Valley is connected to the rest of ERCOT via two 345 kV lines and three 138 kV lines, contains 1,712 MW of generation located at four plants, and set an

all time peak load of 2,734 MW on February 3, 2011

Valley Interface

1. North Edinburg - Lon Hill 345 kV 2. Ajo – Rio Hondo 345 kV3. Raymond 2 – MV Yutt 138 kV4. North Edinburg - Rachal 138 kV5. Roma Switch – Falcon Switch 138 kV

Rio Grande Valley – Summer Load Variability

14

The load growth in the Rio Grande Valley appears to be quite strong, year over year (~10% at 100o F). Materially different temperature outcomes experienced in 2009 (109o

F) vs. 2010 (101o F).

Scatter plat provided by AEP in presentation titled “Lower Rio Grande Valley (LRGV) Import” at March 2011 RPG Meeting. Approximate trend lines developed heuristically by Luminant

Implies ~10% annual load growth

Rio Grande Valley – Winter Load Variability

15

Winter load growth is less clear from this graph. The peak 2011 load shown is potentially understated if it occurred during the firm load shed event on 2/3/2011.

Materially different temperature outcomes experienced in 2010 (39o F) vs. 2011 (28o F)1.

Scatter plat provided by AEP in presentation titled “Lower Rio Grande Valley (LRGV) Import” at March 2011 RPG Meeting.

500

1,000

1,500

2,000

2,500

3,000

25 30 35 40 45 50 55 60 65 70 75 80

Dai

ly P

eak

(MW

)

Daily Minimum Temperature (Degrees)

Valley - Winter Daily Peak & Temperature(no weekends or holidays)

2010 Winter

2011 Winter

1) Note the data shown on this slide excludes weekends and holidays. Ironically, the same 28 degree annual minimum temperature from 2011 also occurred in 2010, but on a Saturday.

Rio Grande Valley – Summer Load Variability

16

Across the prior 30 year period, the average (1 in 2 year outcome) summer maximum hour temperature for the year was 103.6o F. The 1 in 10 year peak temp was 107.1o F,

while the 1 in 20 year peak temp was 108.6o F1.

Analysis conducted by Luminant Energy utilizing 30 years of NOAA weather data

McAllen, Tx - Max of Hourly Max1981 to 2010

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Deg

rees

F

2010 peak hour temp were extremely mild. Only 1 year in the last

30 has had a lower peak hour temp

(2007).

1) Refer to Appendix 2 for summary of NOAA statistical details referenced above for McAllen.

Rio Grande Valley – Winter Load Variability

17

Across the prior 31 year period, the average (1 in 2 year outcome) winter minimum peak hour temperature for the year was 32.1o F. The 1 in 10 year peak temp was 26.0o

F, while the 1 in 20 year peak temp was 22.5o F1.

Analysis conducted by Luminant Energy utilizing 30 years of NOAA weather data

McAllen, Tx - Min of Hourly Min1981 to 2/28/2011

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Deg

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F

While the 28o F temperature outcome on 2/3/2011 was cold, it only represents a 1 in 5 year minimum

peak hour temperature for the

McAllen area

1) Refer to Appendix 2 for summary of NOAA statistical details referenced above for McAllen.

Rio Grande Valley – Load Variability Assessment

18

According to the scatter plots, winter hourly temps must stay at or above 40o F for Winter Peak loads to not exceed the 1,800 MW levels used in the planning cases.

NOAA weather data indicates, that there hasn’t been a single year in the last 30 where minimum hour temps for the year haven’t been below this level.

Valley Area Load (MW)

2011 2012 2013 2014 2015Winter Peak – 2010/2011 SSWG

model 1806 1733

Summer Peak - 2010 5YTP model 2214 2295 2353 2426 2495

Valley Area Load (MW)

2011 2012 2013 2014 2015Winter Peak – 2010/2011 SSWG

model 1806 1733

Summer Peak - 2010 5YTP model 2214 2295 2353 2426 2495Table provided by ERCOT in presentation titled “Lower Rio Grande Valley (LRGV) Import” at March 2011 RPG Meeting.

When combining the findings from the prior four slides, and compare them to the table showing the loads being used in planning it becomes clear: That expected (1 in 2) loads are materially higher than what is being planned

When reasonable variations in max and min hour seasonal temperatures are applied to the prior scatter plots and even a 5%1 annual load growth is used: 2011 Sum Peak – 1 in 2 year peak load of 2,415 MW, 1 in 10 year 2,520 MW 2011 Winter Peak – 1 in 2 year peak load of 2,550 MW, 1 in 10 year >3,000 MW

1) Note that on Slide 14, it appears as if the 2010 over 2009 load growth was ~10%

0

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1 6 11 16 21 26 31 36 41 46 51 56 61 66 71

Impo

rt L

imit

(MW

)Duration Curve of Valley Import Limit During Congestion

DAM/RT Versus Planning1/1/11 - 3/31/11

DAM/RT Planning

Rio Grande Valley – Operational Safety Margin

19

ERCOT Planning verbalized during

discussion at the March 2011 RPG meeting that

the thermal limit for Valley Import is ~1,400

MW

However, ERCOT Operations normally

utilizes a safety margin of ~300 MW and sets

the operational limit at 1,100 MW unless conditions drive it

lower

In the 90-day period from 1/1/2011 through 3/31/2011, the Valley Import Limit has been set at or below 1,100 MW in either the DAM or RT during 70 days. This ~300 MW operational safety margin appears to be a material driver of why congestion

occurs in operations that is not seen in planning.

Rio Grande Valley – Maintenance Outages

20

Discussion by AEP at the March 11, 2011 RPG meeting during the ERCOT presentation titled “Lower Rio Grande Valley (LRGV) Import”: “A major operational issue is the difficulty to grant clearances for both

transmission and generation maintenance outage in the LRGV.”

“There is a limited time windows to grant maintenance outages in the LRGV and any extreme weather during this period could require load shed.”

“There is a potential for severe weather (hurricanes) that could affect both the existing 345 kV lines sourced from the Corpus Christi area and significantly reduce the load serving capability in the LRGV.”

Nodal Operating Guide 5.3 (2) already states that contingency test must be performed for planned transmission line maintenance outages

However, this criteria doesn’t currently explicitly address the combination of area planned transmission and generation outages

AEP has uncovered a very real issue, in that the current planning criteria doesn’t explicitly cover the need to insure that a combination of both necessary planned

generation and transmission outages can be accommodated during the spring and fall maintenance windows

Outline

21

Executive Summary

Background

Detailed Discussion




Next Steps

DFW Imports SE of Dallas - Overview

22

Between August 2nd and August 20th, 2010 RPRS congestion was experience by ERCOT Operations 16 out of 18 days in a row

bringing on between 1 and 16 generating units to resolve this congestion

Source: ERCOT – Replacement Reserves Service – Daily Reports as posted on the ERCOT Website

Overload / Contingency 8/2

/20

10

8/3

/20

10

8/4

/20

10

8/5

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Big Brown - Venus (956 MVA) / Trinidad SES - Richland Chambers 345 kV

8

Richland Chambers - Trinidad (1072 MVA) /Big Brown SES - Venus Switch 345 kV

10 14 16 9 5

Richland Chambers - Trinidad (956 MVA) /Big Brown SES - Venus Switch 345 kV

8 4 14 3 3 15 10 9 3 5 1 14 10 14 4

Richland Chambers - Trinidad (956 MVA) /Watermill Switch - Limestone 345 kV

3

Date

ERCOT reported cost in the System Planning ReportContingency Binding Element Estimated Costs Transmission Project Clearance

Big Brown -Venus 345 kV

Richland Chambers -Trinidad 345 kV $569,438

Trinidad - Watermill 345kV Line [07TPIT0140] High load in North

Load growth in DFW revealed congestion here in 2010 that is expected to be worse in 2011 due to the retirements and mothballing at Permian and Valley. However, the

2010 Five-Year Plan (issued March 2010) doesn’t mention or recommend any projects to address this congestion

Source: September 2010 ERCOT System Planning Report for August 2010

23

The post summer 2010, mothballing / retirement of Permian and Valley increase the loading on these constraints. However, the current planning process indicates no

transmission upgrades are needed in 2011.1

Limiting Transmission

Limiting Terminal Equipment

DFW Imports SE of Dallas - Overview

The 2010 Five-Year Plan (issued March 2011) doesn’t mention or recommend any projects to address this congestion.

Constraining Elements

1. Richland – Trinidad 345 kV (both) ckts

2. Trinidad – Watermill 345 kV line

3. Trinidad – TriCorner 345 kV line

4. TriCorner – Seagoville 345 kV line

5. Big Brown – Venus 345 kV line

24

It is not possible to reflect ‘anticipated power transfers’ and expected ‘generation schedules’ without recognizing historical generator unavailability.1 Currently,

reliability studies only analyze the loss of the single largest unit, while economic studies completely ignore generation outages all together.

DFW Imports SE of Dallas – Gen Availability

Source: 2009 State of the Market Report (SOMR) for the ERCOT Wholesale Electricity Markets, page 56. A summary of 2003 – 2009 SOMR data is shown in Appendix 3.

1) The 2009 summer (June – Sept.) generator unavailability averaged ~13%. A review of a longer period of time (2003 –2009) suggests a range between 8% and 15%

25

RRU+URS NSRSHouston 353 215

North 591 662South 764 402West 15 741Total 1,722 2,020

Deploy RRS+URS 86Total 1,808 2,020

Data from highest 5 peak load days in July and August 2010, looking at 3 peak hours (1600-1800).

The QSE level data available makes it unclear in which zone this deployment took place

All of the reliability and economic studies performed currently assume a level of real time co-optimization of energy and A/S, to such a degree that outcomes of no RRS, URS, and NSRS capacity being carried in load pockets such as DFW and everything

electrically north of Trinidad in the study mentioned above.2

All of the reliability and economic studies performed currently assume a level of real time co-optimization of energy and A/S, to such a degree that outcomes of no RRS, URS, and NSRS capacity being carried in load pockets such as DFW and everything

electrically north of Trinidad in the study mentioned above.2

DFW Imports SE of Dallas – A/S Consideration During high load periods, there is a higher risk of congestion and reliance

on generators that have a portion of their capacity committed to the ancillary services market

To demonstrate this, the most recent data available for the high load conditions of July – August 2010) has been summarized below1

A review of historical generation schedules has shown that significant amounts of generation capacity is tied up carrying RRS, URS, and NSRS

1) Detailed results of this analysis are provided in Appendix 4; 2) Potentially in conflict with the location considerations of Operation Guides Section 2.1 (1) (h), as well as, may be impractical to run multiple SASMs accommodate.

26

Given the widespread application of dynamic line ratings that has occurred since the planning criteria was written and the 100% correlation of above normal temperatures causing both higher than normal loads and lower than nominal dynamic line ratings,

these two effects should be studied simultaneously

Given the widespread application of dynamic line ratings that has occurred since the planning criteria was written and the 100% correlation of above normal temperatures causing both higher than normal loads and lower than nominal dynamic line ratings,

these two effects should be studied simultaneously

DFW Imports SE of Dallas – Dynamic Line Ratings A number of the major TDSPs have implemented dynamic line ratings over

the past 5 years and ERCOT systems have been designed to reflect them Has the effect of freeing up more of the transmission capacity for market use

much of the year However, the above normal temperatures (e.g. 1 in 10 or 1 in 20) that drive

above normal loads, are 100% correlated with below nominal dynamic line ratings

The table below illustrates the relative temperature impact of dynamic line ratings on an Oncor 2-795 kcmil 345 kV line

For the DFW area expected peak hour annual temperatures, a: 1 in 10 year value is 107.4 oF, which equates to ~a 1.9% below nominal line rating 1 in 20 year value is 109.6 oF, which equates to ~a 3.8% below nominal line rating

Temperature oF 80 85 90 95 100 Nominal (static) 105 110 115Continous Rating (MVA) 1223 1194 1163 1132 1098 1072 1065 1031 994% Dev. From Nominal 14.1% 11.4% 8.5% 5.6% 2.4% 0.0% -0.7% -3.8% -7.3%

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

17.0% 18.0% 19.0% 20.0% 21.0% 22.0%

Wes

t & N

orth

Zone

Win

d Pro

ducti

on

West and North Zone Load as a % of Peak Load

2009 - 2010 Load Vs Wind Production1/1/2009 - 11/30/2010, West and North Zones

70.0% 75.0% 80.0% 85.0% 90.0% 95.0% 100.0%

27

Given the high degree of variability of wind from hour to hour, the planning requirement to study ‘anticipated power transfers’ should require studies at both very

high and very low wind generation conditions. Clearer definitions of study requirements are needed in the planning criteria to insure consistent study

application.

Given the high degree of variability of wind from hour to hour, the planning requirement to study ‘anticipated power transfers’ should require studies at both very

high and very low wind generation conditions. Clearer definitions of study requirements are needed in the planning criteria to insure consistent study

application.

DFW Imports SE of Dallas – Wind Generation The chart below depicts the top and bottom 4,000 intervals (1,000 hours) of load in

the combined North and West Congestion Zones for 23 months (1/1/2009 – 11/30/2010)

SSWG 11Sum1 Case has 796 MW West and North Zone wind

Low Load High Load

70%

80%

90%

100%

110%

120%

130%

Base Case SSWG 2011

Loss of Comanche Peak

1

Access to all generation

Loads for 1 in 10 year high

temperatures

Dynamic Line rating with 1 in

10 year high temperatures

De-rate generation so

total FO/Derate = 10.2%

Commit Generation to

Ancillary Services

Reduce West Wind

Production to 0 MW

Contingency Loading of Trinidad - Tricorner 345 kV LineContingency Big Brown - Venus Dbl Ckt 345 kV Line

DFW Imports SE of Dallas – Net Impact

28

A

B When considering the full set of impacts experienced on the line based during operations, the loading can easily be in the range of 110% - 120%

Without varying system conditions to the degree required by the criteria, the contingency loading on this line can be as low as 77%.

As a result of the lack of explanation in Section 5.3 (2) of the Operating Guides on how to apply ‘reasonable load variations, generation schedules…, and anticipated

power transfers’; most planning studies simply ignore them. This is a key factor on why many constraints become quite impactful in actual operations long before they

are identified for upgraded through the planning process.

As a result of the lack of explanation in Section 5.3 (2) of the Operating Guides on how to apply ‘reasonable load variations, generation schedules…, and anticipated

power transfers’; most planning studies simply ignore them. This is a key factor on why many constraints become quite impactful in actual operations long before they

are identified for upgraded through the planning process.

B

A

Outline

29

Executive Summary

Background

Detailed Discussion




Next Steps

30

Recent operational experience, pending NERC TPL standards, as well as, some historical TDSP planning criteria point out that long-term outages of auto

transformers can be just as impactful to the system as a long-term generator outage and perhaps should be treated equivalently1

Recent operational experience, pending NERC TPL standards, as well as, some historical TDSP planning criteria point out that long-term outages of auto

transformers can be just as impactful to the system as a long-term generator outage and perhaps should be treated equivalently1

Long-Term Autotransformer Outage Risk Given their large size and potential long-term outage characteristics,

autotransformer outages require careful planning consideration Forced outages of large autotransformers can be equally impactful to

the reliability and economics of the market as a generation plant Recent history has provided several notable examples:

Bellaire 345/138 kV auto – long term outage in spring 2010 Cedar Hill 345/138 kV auto – long term outage in summer 2010 Paris 345/138 kV auto – long term outage in winter 2010 / 2011

In each of the above examples, the potential for market impacts existed: Bellaire & Cedar Hill – significant congestion impacts in the market Paris – Monticello mining load was tripped by SPS #25, as well as,

transmission related backdown at Monticello plant also occurred Historically, some TDSPs (e.g. Oncor) planned the system to

accommodate one auto xfmr as unavailable and maintain N-1 security

1) NERC Standard TPL-001-2, which is currently being targeted for implementation in 3Q11, addresses this same concern in Section R2 2.1.5

Outline

31

Executive Summary

Background

Detailed Discussion




Next Steps

Conclusions and Next Steps

32

Conclusions The enhancements proposed within, will allow the PLWG / CMWG to

quickly respond to the TAC directive of finding ways of tightening up the planning process to mitigate continue SCED irresolvable constraint outcomes

Enhanced clarity of the study assumptions and performance requirements sought by the planning criteria / process, should result in a better match of planning studies to real time operational realities

These improvements are likely needed in both the Operational Planning and Long-Term Transmission planning studies

Next Steps PLWG drafts a PGRR to incorporate revisions to the planning criteria that

would codify these amendmants Recommend PGRR to ROS and TAC at their Jul. 14th and Aug. 4th meetings Hold joint PLWG / OWG meeting to review this material and the

associated companion OGRR associated with Operational Planning

33

Appendix

Congestion Cost December January February March sum violated hrsHours active in SCED 2.8 21.5 26.9 9.3 60.5Hours binding in SCED 1.3 6.0 6.8 2.1 16.3Hours violated in SCED 0.0 2.1 5.2 0.0 7.3Hours with Violated & overridden 0.1 3.9 39.3 0.0 43.3 50.5

34

SP*MW Flow December January February March Sum Sum in SCED

VALIMP binding in SCED $3,089.05 $56,224.85 $33,959.97 $2,011.26 ($95,285.14

VALIMP violated in SCED @SP5000 $0.00 $11,831,250.00 $34,809,583.33 $0.00 + $46,640,833.33) = $46,736,118.47

Violated & overridden @ SP5000 $469,121.70 $17,241,771.70 $281,173,247.58 $0.00 $298,884,140.98






Violated & overridden with 2 step limits $200 & $2000 MSP $18,764.87 $1,465,179.63 $97,588,665.34 $0.00 $99,072,609.83

Violated & overridden with 2 step limits $200 & $2000 MSP – One constraint at limit + margin with Max Shadow Price at $200 and another at limit with Max Shadow Price at $200 0

Appendix 1) John Dumas’ TAC presentation “Valley Import Constraint” May 5, 2011

Appendix 2) Statistical Summary of NOAA Temp Data for McAllen

35

Appendix 3) Potomac Economics 2003 – 2009 annual report related to generator Short-Term Outages and Deratings

36

Year Forced Outage Planned Outage Other Deratings Total2003 2.4% 2.0% 6.7% 11.1%2004 2.7% 1.5% 5.0% 9.2%2005 2.5% 0.7% 5.2% 8.4%2006 3.0% 0.9% 8.0% 12.0%2007 0.8% 0.4% 6.7% 7.9%2008 1.7% 0.8% 7.3% 9.8%2009 2.1% 1.0% 10.0% 13.1%

Average 2.1% 0.9% 7.2% 10.2%

2003 3.0% 0.9% 5.7% 9.6%2004 1.8% 0.9% 5.9% 8.6%2005 2.5% 0.2% 6.8% 9.5%2006 2.1% 0.2% 8.9% 11.3%2007 1.9% 0.0% 6.7% 8.5%2008 1.9% 0.2% 7.7% 9.8%2009 2.3% 0.4% 10.2% 12.9%

Average 2.1% 0.9% 7.2% 10.2%

2003 2.4% 1.1% 5.0% 8.5%2004 1.8% 0.9% 5.9% 8.6%2005 2.3% 0.1% 6.0% 8.4%2006 1.4% 0.2% 6.6% 8.2%2007 1.7% 0.2% 6.3% 8.1%2008 2.1% 0.0% 7.9% 10.0%2009 1.5% 0.6% 10.4% 12.5%

Average 1.9% 0.4% 6.9% 9.2%

2003 1.7% 2.8% 6.9% 11.3%2004 1.6% 3.0% 7.0% 11.6%2005 3.0% 0.7% 6.8% 10.5%2006 1.6% 2.0% 7.3% 10.9%2007 1.7% 1.5% 6.7% 9.8%2008 2.9% 1.0% 7.9% 11.9%2009 2.7% 0.6% 11.5% 14.8%

Average 2.1% 0.9% 7.2% 10.2%

June

July

August

Sepember

Year Forced Outage Planned Outage Other Deratings TotalAverage 2.1% 0.9% 7.2% 10.2%

Generating capacity that has historically been unavailable during summer months

ranges from 7.9% to 14.8%, with an average of 10.2%

Above: Source: 2009 State of the Market Report for the ERCOT Wholesale Electricity Markets, page 56.

Appendix 4) Details of Generation Capacity Committed to Ancillary Services

37

Table Continued on next page

Houston 345 216 North 583 663 South 736 396 West 15 740Unit name RRS+URS NSRS Unit name RRS+URS NSRS Unit name RRS+URS NSRS Unit name RRS+URS NSRSCBY_CBY_G2 77 0 LH2SES_UNIT2 170 0 FERGUS_FERGUSG1 61 0 MGSES_CT3 0 70WAP_WAP_G4 57 0 BOSQUESW_BSQSU_1 0 150 B_DAVIS_B_DAVIG1 59 0 MGSES_CT2 0 70TGF_TGFGT_1 0 50 BOSQUESW_BSQSU_2 0 135 BRAUNIG_VHB2 54 0 MGSES_CT4 0 68CBY_CBY_G1 29 0 DCSES_CT10 0 71 CALAVERS_OWS2 49 0 MGSES_CT5 0 68GBY_GBYGT82 0 28 DCSES_CT20 0 70 GIDEON_GIDEONG3 49 0 MGSES_CT1 0 67GBY_GBYGT83 0 28 DCSES_CT30 0 69 LEON_CRK_LCPCT1 2 46 MGSES_CT6 0 66GBY_GBYGT84 0 28 DCSES_CT40 0 68 LEON_CRK_LCPCT3 1 46 PB2SES_CT5 0 61AZ_AZ_G4 0 27 OLINGR_OLING_4 1 61 LEON_CRK_LCPCT4 1 46 PB2SES_CT4 0 60THW_THWGT51 1 17 LHSES_UNIT1 38 0 LARDVFTN_G5 0 45 PB2SES_CT3 0 59THW_THWGT52 1 17 GRSES_UNIT2 33 0 DECKER_DPGT_3 1 41 PB2SES_CT1 0 59AZ_AZ_G3 0 15 BOSQUESW_BSQSU_5 26 0 CALAVERS_OWS1 41 0 PB2SES_CT2 0 56GBY_GBY_5 14 0 THSES_UNIT2 25 0 LARDVFTN_G4 4 36 WFCOGEN_UNIT1 0 13SRB_SRB_G4 11 0 DANSBY_DANSBYG1 24 0 INGLCOSW_STG_V 0 39 WFCOGEN_UNIT2 0 10CBY4_CT41 10 0 VLSES_UNIT3 24 0 BRAUNIG_VHB3 34 0 WFCOGEN_UNIT3 0 10CBY4_CT42 10 0 OLINGR_OLING_3 17 0 GIDEON_GIDEONG1 33 0 QALSW_GT4 3 0CAL_CALGT1 9 0 ATKINS_ATKINSG7 3 14 GIDEON_GIDEONG2 33 0 WFCOGEN_UNIT4 0 3WAP_WAP_G1 8 0 GRSES_UNIT1 14 0 DECKER_DPGT_4 3 30 QALSW_STG1 3 0PSG_PSG_GT3 7 0 OLINGR_OLING_2 13 0 DECKER_DPG2 28 0 QALSW_GT3 2 0PSG_PSG_GT2 7 0 VLSES_UNIT1 13 0 DECKER_DPG1 27 0 QALSW_GT1 2 0WAP_WAP_G2 7 0 SC2SES_UNIT1 12 0 VICTORIA_VICTORG5 26 0 QALSW_GT2 1 0SRB_SRB_G3 7 0 FRNYPP_GT21 12 0 DECKER_DPGT_2 1 24 FLCNS_UNIT1 1 0THW_THWGT53 1 6 TRSES_UNIT6 12 0 BRAUNIG_VHB1 18 0 FLCNS_UNIT2 1 0PSG_PSG_ST1 7 0 FRNYPP_GT11 11 0 WIRTZ_WIRTZ_G2 13 0 QALSW_STG2 1 0PSA_PSA_G2 4 0 VLSES_UNIT2 11 0 MARSFO_MARSFOG1 12 0 FLCNS_UNIT3 1 0PSA_PSA_G1 4 0 FRNYPP_ST20 11 0 WIRTZ_WIRTZ_G1 11 0PSA_PSA_G5 4 0 MIL_MILLERG5 0 10 MARSFO_MARSFOG3 11 0THW_THWGT54 4 0 BOSQUESW_BSQSU_4 1 8 RAYBURN_RAYBURG1 0 11CAL_CALSTG1 3 0 SCSES_UNIT2 9 0 RAYBURN_RAYBURG2 0 11PSA_PSA_G6 3 0 OLINGR_OLING_1 7 0 MARBFA_MARBFAG2 11 0PSA_PSA_G4 3 0 FRNYPP_GT22 6 0 MARBFA_MARBFAG1 10 0LHM_CVC_G4 3 0 FRNYPP_GT23 6 0 SANDHSYD_SH_5A 10 0THW_THWGT56 3 0 FRNYPP_ST10 6 0 SANDHSYD_SH_5C 10 0PSA_PSA_G3 3 0 FRNYPP_GT12 5 0 B_DAVIS_B_DAVIG2 9 0CBY4_ST04 3 0 FRNYPP_GT13 5 0 SILASRAY_SILAS_10 0 8BVE_UNIT3 2 0 FREC_GT2 5 0 BUCHAN_BUCHANG3 8 0PSA_PSA_G7 2 0 LPCCS_UNIT2 5 0 NUECES_B_NUECESG7 7 0CBEC_STG1 2 0 DANSBY_DANSBYG2 4 0 RAYBURN_RAYBURG9 7 0BVE_UNIT1 2 0 LPCCS_CT21 4 0 RAYBURN_RAYBURG7 7 0THW_THWGT55 2 0 BOSQUESW_BSQSU_3 4 0 BUCHAN_BUCHANG1 7 0THW_THWST_3 2 0 ATKINS_ATKINSG6 4 0 RAYBURN_RAYBURG8 7 0CVC_CVC_G5 2 0 STEAM_STEAM_3 4 0 MARSFO_MARSFOG2 7 0WAP_WAP_G3 2 0 OLINGR_OLING_2V 2 2 BRAUNIG_AVR1_CT2 6 0CBEC_GT2 2 0 LPCCS_CT12 3 0 DECKER_DPGT_1 1 5BYU_BYU_G3 2 0 STEAM_STEAM_3V 0 3 NEDIN_NEDIN_G2 6 0CBEC_GT4 2 0 LEG_LEG_G2 3 0 DUKE_DUKE_GT2 6 0

MW Committed MW Committed MW Committed MW Committed

Appendix 4) Details of Generation Capacity Committed to Ancillary Services (continued)

38

The generation capacity committed to ancillary services was approximated by collecting data for the five highest peak load days in July and August 2010, for Hours Ending 16-18. Additional sources include the Resource Plans, QSE AS Schedules, ERCOT dispatch instructions for AS and BES, and MCPE

Houston North SouthUnit name RRS+URS NSRS Unit name RRS+URS NSRS Unit name RRS+URS NSRSBTE_BTE_G1 2 0 TNP_ONE_TNP_O_1 2 0 DUKE_DUKE_GT1 6 0CBEC_GT3 2 0 ATKINS_ATKINSG5 2 0 INKSDA_INKS_G1 5 0BTE_BTE_G4 1 0 LPCCS_UNIT1 2 0 RAYBURN_RAYBURG10 4 0THW_THWST_4 1 0 SPNCER_SPNCE_5 2 0 LGE_LGE_STG 3 0BVE_UNIT2 1 0 ATKINS_ATKINSG4 2 0 DUKE_DUKE_ST1 3 0CVC_CVC_G2 1 0 STEAM_STEAM_2 2 0 PEARSAL2_ENG1 0 2CVC_CVC_G1 1 0 TNP_ONE_TNP_O_2 2 0 PEARSAL2_ENG2 0 2CVC_CVC_G3 1 0 LPCCS_CT22 2 0 NEDIN_NEDIN_G1 2 0BTE_BTE_G2 1 0 OLINGR_OLING_4V 0 2 BRAUNIG_AVR1_ST 2 0THW_THWGT34 1 0 FREC_GT1 2 0 CALAVERS_JTD2 2 0BTE_BTE_G3 1 0 MIL_MILLERG3 2 0 LGE_LGE_GT1 2 0THW_THWGT41 1 0 ETCCS_CT1 1 0 LGE_LGE_GT2 2 0CBEC_GT1 1 0 MLSES_UNIT2 1 0 BUCHAN_BUCHANG2 2 0THW_THWGT31 1 0 STEAM_STEAM_2V 1 0 VICTORIA_VICTORG6 2 0WAP_WAP_G8 1 0 ATKINS_ATKINSG3 1 0 SANDHSYD_SH4 2 0THW_THWGT32 1 0 DANSBY_DANSBYG3 1 0 PEARSAL2_ENG4 0 2TXCTY_ST 1 0 LPCCS_CT11 1 0 AUSTPL_AUSTING2 2 0THW_THWGT44 1 0 FREC_GT4 1 0 SANDHSYD_SH1 2 0WAP_WAP_G5 1 0 WCPP_CT1 1 0 AMISTAD_AMISTAG2 2 0WAP_WAP_G7 1 0 FREC_ST3 1 0 PEARSAL2_ENG3 0 2THW_THWGT42 1 0 MIL_MILLERG1 1 0 SANDHSYD_SH3 2 0

MIL_MILLERG2 1 0 BRAUNIG_AVR1_CT1 2 0WCPP_CT2 1 0 LOSTPI_LOSTPST1 2 0FREC_GT5 1 0 B_DAVIS_B_DAVIG3 2 0LEG_LEG_G1 1 0 NUECES_B_NUECESG9 1 0FREC_ST6 1 0 NUECES_B_NUECESG8 1 0MCSES_UNIT8 1 0 B_DAVIS_B_DAVIG4 1 0

AMISTAD_AMISTAG1 1 0FORMOSA_FORMOSG1 1 0SANDHSYD_SH2 1 0PENA_UNIT2_J03 0 1FALCON_FALCONG2 1 0AUSTPL_AUSTING1 1 0PEARSAL2_ENG24 0 1PEARSAL2_ENG21 0 1PEARSAL2_ENG22 0 1PEARSAL2_ENG23 0 1PEARSAL2_ENG5 0 1SANDHSYD_SH7 1 0FPPYD1_FPP_G2_J02 1 0PEARSALL_PEARS_1 1 0SANDHSYD_SH6 1 0SANMIGL_SANMIGG1_J01 1 0FPPYD1_FPP_G1_J02 1 0FALCON_FALCONG1 1 0NEDIN_NEDIN_G3 1 0FALCON_FALCONG3 1 0CALAVERS_JKS2 1 0

MW CommittedMW CommittedMW Committed

transmission planning process discussion joint plwg / cmwg meeting presented by: luminant energy...

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