Response to TAC Questions on PGRR031

TAC– January 28, 2014Jeff Billo, ERCOT

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PGRR031 Questions from December 3 TAC Meeting

• How did OPSTF determine 95% to be the appropriate number to use for PGRR031?

• What is the cost of PGRR031?

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Why 95%? (see Appendix 1 for details)In 2012 ERCOT conducted an analysis to determine the impact of a 90% or 95% criterion on the 2012 Five-Year Transmission Plan 2015 case

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Issue % Loading Variance

Construction Delays ~2%-5%

Typical wide-area generation unavailability ~4%

Dynamic ratings on hot days ~3%

Long-term load forecast error ?

Transmission outages Large variation

Total ?

Criterion # Elements

Loaded between 90% and 100% 155

Loaded between 95% and 100% 40

Numbers reference #

Total Projects in 2013 Regional Transmission Plan 105

Total Future Projects in November 2013 TPIT 621

Total Elements in 2012 Five-Year Transmission Plan 2015 case ~7000

PGRR031 Cost Calculation Process

• ERCOT conducted an analysis of the final 2016 reliability case from the 2013 Regional Transmission Plan

• Disclaimer: ERCOT made assumptions about projects and used generic cost estimates to determine project costs. In order to perform the analysis in a timely manner TSPs were not consulted to verify the accuracy of the assumptions or costs

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PGRR031 impact on 2016 model

• 61 elements were loaded over 95%• 31 of those elements were assumed to drive

project accelerations under the PGRR031 criteria

• The cost of accelerating these projects was estimated to be $96.35 million– $54.85 million of that (more than half) was due to

the theoretical acceleration of the Houston Import Project from 2018 to 2016.

• Details can be found in Appendix 2 5

Reliability – Congestion Cost Relationship

Production cost impact of congestion

Price of congestionR

elia

bilit

y Li

mit

Constraint Loading

$

*Note: Curves are hypothetical and cost/price curves of a given constraint may differ

ReliabilityEconomic

Shadow price limit

Positive cost impacts of PGRR031

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Total January – November 2013 At Shadow Price Limit

SCED-binding element intervals 95,935 3,884 (4%)

Congestion rent $464.8 million $168.5 million (36%)

Total 2012 At Shadow Price Limit

SCED-binding element intervals 121,869 8,292 (7%)

Congestion rent $665.9 million $326.8 million (49%)

Questions?

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Appendix 1:Background for 95% threshold

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OPSTF issues addressed by PGRR031

#3: Ensuring projects in the Five Year Transmission Plan are completed in a timely manner. This includes unforeseen consideration of load variability, transmission outages and construction complexities that may require earlier completion. #4a: Appropriate Ratings - Ensure Load and Ratings assumption consistency. #4c: Appropriate Ratings - Should planning studies be more conservative by using the planning normal rating (Rate A) for a select set of contingencies? #8c: Generator unit unavailability and modeling issues - Use of “typical” or “historical” Planned, Maintenance and Forced Outages and/or derates in an area

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OPSTF Observations

• As OPSTF investigated the issues they identified seven factors that could lead to line overloads in real-time that were not observed in planning studies

• The investigation of these factors led to the conclusion that 95% was an appropriate criteria threshold

• The following slides detail the OPSTF discussions surrounding these observations

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OPSTF Observation #1Construction delays for projects planned to resolve a constraint could lead to overloads in Real-Time until the planned project is complete. This could occur for multiple summer seasons depending on the length of the delay.•It was observed that several actual reliability problems experienced in real-time could have been mitigated had planned projects been implemented on time (examples: Moore-Downie in 2012, North-South in 2008 (Clear Springs-Hutto-Salado))•An analysis was conducted using the 2012 Five-Year Transmission Plan. Loading of constraints that exceeded reliability limits in multiple years of the study were found to increase approximately 2% to 3%per year on average with a median of approximately 5%•One alternative approach (to the 95% criterion) was to just plan to implement all projects one year earlier than the identified need. This was eventually dismissed due to compliance implications and the thought that many projects may unnecessarily be accelerated

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OPSTF Observation #2The current practice to test the unavailability of any given unit in planning studies may miss overloads that occur in operations when multiple units in an area are out of service or derated. Historically over summer peak as much as 10% of capacity in ERCOT has been either derated or unavailable altogether. OPSTF analysis shows that this could increase loadings on circuits by 4% or higher.•OPSTF looked at historic generator outage and derate data for summer peak periods including a presentation given by ERCOT to ROS in September 2011 and data collected by the IMM (see following slide).•OPSTF conducted a study to determine the impact of 10% generation outages over a wide area and found 38 constraints that were loaded higher than just using the current single-unit outage criterion. These constraints generally were loaded 4% higher than without•An approach to develop a wide area generation outage criterion was explored but OPSTF did not come to a consensus on how to implement this consistently across the entire ERCOT system 13

Potomac Economics 2003 – 2010 Annual Report related to generator Short-Term Outages and Deratings

Results of OPSTF analysis

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OPSTF Observation #3During severe weather that results in higher than anticipated temperatures and higher associated load conditions, facility thermal ratings are generally lowered for studies run by transmission operators per their ambient temperature adjusted dynamic ratings. As an example, one large TSP noted that if the temperature were just 4 degrees F higher than the assumed static rating temperature (104 degrees F) the dynamically rated lines on their system would be rated 3% below the static rating. Since planning reliability studies use static ratings, overloads may be observed in operations under these conditions.•OPSTF explored the possibility of rerating equipment based on a higher (worst-case) assumed temperature. This had implications beyond just circuit ratings and was abandoned

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OPSTF Observation #4Planning analysis utilizes load forecasts made several years before the operating conditions are realized. Sometimes load grows faster than anticipated and overloads occur in operations because the load level was not seen soon enough in the planning analysis to get the necessary improvements constructed. For example, the recently completed 2012 Five-Year Transmission Plan identified 20 reliability problems for summer 2013 for which the transmission solution for those problems will not be constructed before the problems will occur.•Examples of this include the Valley and oil and gas load•OPSTF did not come up with a feasible alternative to the 95% criterion. There was some discussion of using 90th percentile weather assumptions for load forecast, but this only takes into account load increases due to weather and not economically driven load growth

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OPSTF Observation #5Planning analysis assumes that all facilities are in-service. However, even over summer peak there is equipment that is out of service for maintenance, construction, or for an extended forced outage. This leads to line loadings in operations that are higher than anticipated in planning studies.•OPSTF did not quantify this effect•Recent planning study process changes at ERCOT are designed to find and solve high consequence n-1-1 contingency constraints, but that does not eliminate low or medium consequence situations•It was observed that other regions in North America plan their systems to be n-1-1 secure (no load loss), but OPSTF did not considered this for ERCOT•The 95% criterion was the only solution that was considered to address this issue

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OPSTF Observations #6 and #7Actual generation dispatch is different from that modeled in planning cases.

Construction and maintenance clearances are not known when planning studies are performed. During real-time operations, multiple clearances are in effect which cause SCED and RTCA results that differ from planning studies.

•These were general observations for which OPSTF did not quantify the effects

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Appendix 2:Details for cost analysis

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Analysis of 2016 case from 2013 RTP• 61 non-GSU elements were post-contingency loaded

greater than 95%. These were compared against their loading in the final 2018 case from the 2013 RTP

– 23 elements either had decreasing or flat loading so I assumed that we would not plan a project for those

– 1 element was protected by a non-modeled SPS so I assumed that we would not plan a project for it

– 1 element could be fixed by adjusting a phase-shifting transformer so I assumed that we would not plan a project for it

– 5 elements had TPIT projects that would be in place by 2015 so I assumed that there would be no acceleration needed

– 12 elements had projects (including Houston Import) planned for either 2017 or 2018 so I assumed that they would need to be accelerated to 2016

– The remaining 19 elements did not have projects planned. For these I estimated linear annual loading increases on the elements to determine when they would overload and assumed that the project to solve them would need to be accelerated to 2016. For these projects I estimated the upgrade cost using generic figures

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From NumberFrom Name To NumberTo Name Circuit 2016 2018 Notes3160 DIALVILL_8 3296 NECHESRI_8 1 99.99 0 Line upgrade in Dec 2016

15020 DFW_DE1T1_8 15045 DFW_CE1_8 1 99.91 0 Decreasing - no project37520 TNSYCAMORE0 37530 TNCORYELCO0 1 99.85 0 Line upgrade in 2017

1996 ATMEL1_T8 2388 HACKBRY1_8 1 99.76 0 SPS3522 HILLBORO1_8 3546 WHITNEY__8 1 99.65 100.48 Needs Project

45675 BETKA___138A 45770 FREMAN__138A 66 99.52 0 Katy area upgrades (partial acceleration)8371 S_MCALLN4A 8822 SLUBENT4A 1 99.36 99.81 Needs Project

41310 QUANAB__138A 41400 S_R_B___138A 6 99.35 0 Decreasing - no project44645 SNGLTN_345 44900 ZENITH__345A 99 99.33 0 Houston Import44645 SNGLTN_345 44900 ZENITH__345A 98 99.3 0 Houston Import

2733 RCKWL_AL_T8 2735 DALRCKRD1_8 1 99.16 99.96 Needs Project2472 ROYSE_B8 2733 RCKWL_AL_T8 1 99.13 99.93 Needs Project2404 NORWD_1T8 2418 NORWDSTR 1 99.12 0 Project already planned for 2015

803 COLLEGE9 815 LAWLERT 1 99.02 99.52 Project already planned for 201437420 TNLKWHITNY0 37410 TNLKWHITNY1 1 98.78 98.37 Needs Project42800 HITCOK__138A 43400 W_GALV__138D 93 98.56 99.99 Needs Project

2001 IRVNORTH_8 15021 DFW_DE1T2_8 1 98.35 99.91 Needs Project6333 WINT2A 60332 STMBOAT2A 1 98.34 97.25 Needs Project3271 PALSTNS_8 3296 NECHESRI_8 1 98.23 0 Line upgrade in Dec 20162082 HICKS_SW_1_8 2081 HICKS_SW1_5 1 98.03 93.86 Decreasing - no project8169 VICTORIA2A 8591 OCONNER2A 1 97.99 98.74 Needs Project2512 ALLENSW2_8 2545 ALLENSTR 1 97.98 0 Decreasing - no project5832 FRIOTOWNSUB9 5893 PEARSALLSW9 1 97.81 97.51 Flat - no project

40775 LNGSTN__138X 41113 MT_BEL__138B 86 97.74 93.89 Decreasing - no project38820 TNFRWYPARK1 38850 TNDICKNSON1 1 97.61 93.69 Decreasing - no project

2365 COLLIN2_8 2567 CUSTER2_P8 1 97.6 98.27 Project already planned for 20152210 JOSHUA_8 2279 CLEBRNSW_8 1 97.56 99.07 Needs Project6064 VERS2A 6066 VERS4A 1 97.52 94.37 Decreasing - no project2399 WLEVEE_E8 12481 RVRFRNT1_8 1 97.35 99.7 Needs Project

47580 DUNLVY__69A 47690 HYDEPK__69A 32 97.35 99.72 Project already planned for 20145868 BIGWELLSSUB9 5876 COTULLASUB9 1 97.25 95.01 Decreasing - no project8819 I_DUPP14B 8968 INGLCOSW4A 2 97.25 97.43 Flat - no project

331 RWMILLER 1576 PALOPNTO_T8 1 97.17 0 Decreasing - no project47500 DWNTWN__138A 47730 POLK____138A 91 97.11 98.24 Needs Project

8708 AZTECA4A 8963 DUKE4A 1 97.1 0 Line upgrade in 20181624 LEONSW_8 6310 PUTN2B 1 97.05 0 PST control - no project2347 RICETPL_9 3468 CORS__9 1 96.91 99.07 Needs Project6225 ABNW2B 6241 ELYT2A 1 96.87 98.24 Line upgrade in 20182882 GRNVL_W8 2884 BLKWEL1_8 1 96.68 100.16 Needs Project

40220 BRINE___138A 40775 LNGSTN__138X 86 96.63 92.99 Decreasing - no project3410 LAKE_CRK1_8 3452 WACOLASA1_8 1 96.56 95.3 Decreasing - no project7263 L_FRELSB8_1Y 7286 L_FAYETT8_1Y 1 96.52 0 Line upgrade in 20187126 L_FERGUS8_1Y 7127 L_SANDCR8_1Y 1 96.45 0 Project already planned for 20152571 CRLTNCC1_8 2578 CRLTNE_8 1 96.38 95.52 Decreasing - no project3104 SHAMBRGR_8 3141 TYLERNW_8 1 96.36 94.81 Decreasing - no project3140 TYLERWES_9 3166 TYLERSTR 1 96.3 95.85 Decreasing - no project5666 SANDIASUB9 8407 MATHIS2A 1 96.29 0 Line upgrade in 2018

821 FIREWHEEL 833 WYLIESW 1 96.28 97.54 Needs Project38530 TNTEJAS___1 38575 TNGRENBELT1 1 96.25 96.75 Flat - no project

8409 GRETA2A 8591 OCONNER2A 1 96.23 97.03 Needs Project1883 EVRMAN_A8 2208 MANSFLD_8 1 96.04 98.03 Needs Project2813 RECCRS1_8 2823 UTSWMC1_8 1 96.02 0 Line upgrade in 20182478 ROYSE_S5 3103 SHAMBRGR_5 1 95.73 0 Line upgrade in 20182421 CHILSW_S8 2999 DVIL1_8 1 95.65 94.05 Decreasing - no project3438 WACO_E1_8 3452 WACOLASA1_8 1 95.62 94.4 Decreasing - no project2662 MARSH1_8 2782 MRSN_E8 1 95.61 98.43 Needs Project2407 NORWDPL_E8 2800 REGRW1_8 1 95.46 99.83 Needs Project1951 HANDLEYD_8 2103 RANDL_W_T8 1 95.4 93.91 Decreasing - no project2441 PRCKSW1_8 2763 PRCK1_8 1 95.15 93.12 Decreasing - no project

937 STEAM D 945 MAMIE D 1 95.15 95 Flat - no project40220 BRINE___138A 40764 WINFRE__138X 86 95.02 91.28 Decreasing - no project

Results

Disclaimer:Inclusion or exclusion from

this list should not be implied as an ERCOT

determination of actual project need. This analysis was conducted solely for the purpose of evaluating the impact of PGRR031. Actual planning analysis may produce different

results.

Cost assumptions

• Upgrade cost assumptions:– 69 kV or 138 kV line rebuild = $1M/mile

– 345 kV reconductor = $0.5M/ mile– 345/138 kV transformer = $8M– Terminal equipment upgrade = $1M

• Cost of project acceleration assumptions:– 8% discount factor– 3% inflation

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