ABB MINIMIZING BULK POWER COSTS STUDY IN THE ENTERGY - Southwest Power Pool
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ABB
MINIMIZING BULK POWER COSTS STUDY IN THE ENTERGY
SYSTEM
– ABB INPUT ASSUMPTIONS
August 31, 2011
SUBMITTED TO:
Southwest Power Pool
SUBMITTED BY:
Lan Trinh
Maria Moore
REVIEWED BY:
ABB Consulting
940 Main Campus Drive, Suite 300
Raleigh, North Carolina 27606-5202 USA
Telephone: (919) 856-3922
Fax: (919) 807-5060Table of Contents
Page
1 PRODUCTION COST MODELING ASSUMPTIONS ............................................................................................ 2
1.1. INTRODUCTION ............................................................................................................................................... 2
1.2. DATA SOURCES .............................................................................................................................................. 3
1.3. TRANSMISSION ............................................................................................................................................... 3
1.4. RMR GUIDELINE ............................................................................................................................................ 3
1.5. LOAD INPUTS .................................................................................................................................................. 4
1.6. THERMAL GENERATION UNITS ....................................................................................................................... 4
1.7. HYDRO UNITS ................................................................................................................................................. 5
1.8. RENEWABLE RESOURCES................................................................................................................................ 5
1.9. QUALIFIED FACILITIES .................................................................................................................................... 6
1.10. CAPACITY ADDITIONS AND RETIREMENTS ..................................................................................................... 6
1.11. OPERATING RESERVE REQUIREMENT ............................................................................................................. 6
1.12. EMISSION MODEL ........................................................................................................................................... 8
1.13. WHEELING CHARGE ....................................................................................................................................... 8
1.14. FUEL PRICES ................................................................................................................................................... 8
2 TRANSMISSION MODELING ASSUMPTIONS................................................................................................... 12
2.1. INTRODUCTION ............................................................................................................................................. 12
2.2. GENERATION AND LOAD LEVELS IN THE ENTERGY FOOTPRINT.................................................................... 12
2.3. POWER FLOW ANALYSIS CRITERIA............................................................................................................... 14
3 APPENDIXES ............................................................................................................................................................. 15
ABB1 Production Cost Modeling Assumptions
1.1. Introduction
ABB’s GridView Market Simulation Software was used for this analysis. The core of GridView is a
transmission constrained economic dispatch algorithm as shown in Figure 1.1. GridView mimics the
operation of an electric market by dispatching generating units based on their bid prices while taking into
account the flow limits on transmission lines and interfaces under normal, as well as contingency
conditions. The outputs of GridView are information such as hourly unit dispatch, Locational Marginal
Prices (LMPs) at buses, flow on lines and congestion cost of limiting lines.
Generator M odel: Hourly
Capacity, outage rate, Location
Operating Costs & Operating Dependent
Constraints Load
Detailed
Transm ission Sim ulation Engine:
M odel
Security Constrained
Unit Com m itm ent Market
Interface
& Economic Dispatch Scenarios
Transfer Lim its
Optim al Power Flow
Security
Constraints
Transm ission Power S ystem
LM P Price Generator Congestion & Reliability
Forecast Perform ance Utilizations Indices
Figure 1.1: GridView’s simplified block diagram
GridView determines the least-cost security constrained dispatch of generating units to satisfy a given
demand, on the assumption that the units are dispatched according to their variable costs. The major
advantage of GridView is its ability to simulate the hourly operation of generating units and transmission
systems (e.g. transformers, lines, phase shifters, busses) in significant detail. For example, it accurately
represents capacity constraints, minimum up time limitations, and thermal constraints on the transfer
capability of transmission lines, line and unit contingencies and scheduling limitations of hydro-plants. As
such, GridView provides a highly accurate, detailed simulation of the hourly operation of the individual
generating units and transmission system that constitute the wholesale market.
Among the key outputs of the GridView model is a set of Locational Marginal Prices (LMPs), computed
for each bus in each hour, and the hourly dispatch of all generators in each relevant geographic market.
ABBThe model’s geographic footprint encompasses the U.S. portion of the Eastern Interconnection with a
focus on the Southwest Power Pool (SPP) and Entergy footprints and surrounding regions.
The two years or GridView simulation are 2013 (the analysis start year) and 2022 (the analysis end year).
Results for years not simulated are interpolated.
1.2. Data Sources
The database represents Entergy’s power system with detailed models of generators, loads and
transmission network in entire Entergy footprint, SPP RTO and nearby areas (TVA, SOCO, and
AECI).The GridView database was created from publicly available sources, like EPA , EIA , GADS
(Generator Availability Data System), FERC Forms, SPP, and Entergy supplied data. The database was
reviewed and sanity-checked by SPP and Entergy
All financial assumptions specified in this document are expressed in real 2009 US dollars, unless
otherwise noted
1.3. Transmission
The transmission system was modeled in detail, exactly as in the PSS/E power flow cases with explicit
representation of all transmission facilities, including lines, transformers, phase shifters and DC ties.
SPP provided two power flow cases representing summer peak load conditions for study years 2013 and
2022. Additional details on these cases are given in Section 2 of this report.
For the purposes of production cost simulation, flowgates/ interfaces with their limits and selected N-1
contingencies were modeled. Furthermore, thermal limits of all transmission lines of 115kV and above
within the Entergy footprint and 345kV and above for the rest of the Tier 1 system, and lines related to
RMR guidelines are enforced. TRM of 3% is enforced in the GridView model.
Powerflow cases, flowgates/interfaces, and contingency definitions were provided by SPP. Entergy
provided RMR operating guidelines were also modeled.
1.4. RMR Guideline
All RMR operating guidelines were modeled with a nomogram feature in GridView. This feature allows
for the modeling of conditional limits or generator statuses that change dynamically during the simulation
based on generator commitment status, area load level, or line status, etc. This feature can be used to
model any particular RMR requirement.
All RMR guideline were provided by Entergy. ABB updated the GridView model to enforce these
Reliability Must Run (RMR) rules at appropriate area or zone load levels. The RMR rules account for
both fixed (non-conforming) and variable (conforming) loads.
ABB1.5. Load Inputs
The loads were represented with chronological 8760 hour curves for each area. For non SPP areas (AECI,
SOCO and TVA) load shapes were from 2006 historical load curves, published in FERC Form 714. Their
2013 and 2022 load forecasts (peak and annual energy) were also collected from FERC Form 714. For
SPP areas, load curves were provided by SPP and their load forecasts for 2013 were from 2010 SPP EIA-
411 report. For year 2022 their load forecast was extrapolated based on 2010-2019 forecast.
Entergy provided load curves and load forecasts for seven areas:
Entergy APL
Entergy Gulf States
Entergy LPL North
Entergy LPL South
Entergy MPL
Entergy NOPSI
Entergy Texas
Non-conforming loads in Entergy load serving areas were identified based on PSSE load ID: AX, CO and
IN. They were modeled as fixed load with a flat load curve throughout the year. Since Entergy load
forecast includes those non-conforming loads, the annual peak and energy of Entergy’s conforming loads
were calculated by subtracting non-conforming fixed load and annual energy from Entergy’s area load
forecast.
1.6. Thermal Generation Units
Thermal units in GridView are represented in detail, including: unit’s type, fuel type, heat rate blocks,
summer and winter capacities, variable O&M, start-up fuel usage, minimum up and down time, forced
outage, maintenance schedule, emission rate, ramping rate, quick-start and spinning reserve capabilities.
Generation data was collected from various sources, including EPA and EIA public sources. The
scheduled maintenance and forced outage rate with durations were estimated based on unit size and type
as reported by the GADS (Generator Availability Data System) database. Where unit-specific data was
not available, typical values were based on unit type, fuel, and size. Maintenance schedules of many
Entergy’s units were provided by Entergy.
To model generation units’ random forced outage, Monte-Carlo simulation with one intellidraw feature
was used for simulation. GridView’s Monte Carlo simulates the random outages of generating units based
on forced outage rate and duration from GADS table.
Modeled IPP units in Entergy footprint are listed in table 1.2 below
ABBTable 1.2: IPPs in Entergy and Cleco regions
Entergy
Carville Cogeneration Energy
Cottonwood CC 1 & 2 (Intergen)
Duke-Hinds
Duke Hot Springs 1
Hot springs (Tractabel)
Robert Ritchie 2
Union Power – Panda Energy
Cogentrix Batesville (MS) (a)
DOW AEP
Cleco
Cleco Evangeline
The heat rates of IPP units, listed below, were adjusted to be the same as Perryville CCGT’s with 10%
adder in 2022 and 4% adder in 2013. Variable O&M of those units were also matched to Perryville
CCGT’s.
Cottonwood CC 1 & 2 (Intergen)
Carville
Duke-Hinds
Duke Hot Springs 1
Hot springs (Tractabel)
Union Power – Panda Energy
LS Power (1LSPWRU)
DOW AEP (IDOWAEP)
Frontier 1-2 (10% adder in 2022 only)
1.7.Hydro Units
In GridView model, hydro generators are characterized by Minimum Capacity, Maximum Capacity,
monthly energy allocation, VO&M, all of which can vary monthly and annually. The minimum capacity
is treated as run of river generation. The difference between minimum and maximum capacities is treated
as dispatchable capacity. The dispatchable capacity is dispatched for peak shaving with the constraint that
the total accumulative generation in a month will not exceed the monthly energy allocation. The hydro
units’ monthly energy was provided by Entergy.
1.8.Renewable Resources
The wind units were modeled as hourly resources with given hourly generation curve and with the
capability of curtailment. 4 GW of wind capacity were added to the SPP region in year 2013 and 8 GW in
2022. Hourly wind production curves for the units in the SPP region were provided by SPP.
ABBGridView hourly resource is a generator with given hourly production curve for unit commitment cycle
and hourly production curve for economic dispatch cycle. It is must take energy with capability of
curtailment and the cost is zero.
1.9.Qualified Facilities
QF Puts were modeled as non-firm energy purchases: units are committed based on “no QF put”, but
dispatched with historical put value. GridView hourly resource model was used with zero curve for
commitment and hourly historical production curve for dispatch. Entergy provided hourly production
curve for all QF Put units. Besides producing energy for sale, QF units also produce energy for their own
self-serve loads. This part of QF unit production was modeled as an hourly resource with fixed/flat
production curves.
Some of the QF Puts may have curtailment or energy spillage in the reference case. If in the change case
or solution case, the amount of energy spillage is significantly less, it will cause the total annual energy
output of that QF units to be higher than in the reference case. In order to avoid this issue, the original
hourly production curve of the affected QF unit will be replaced with an adjusted hourly production
curve. The new curve is created by exporting the hourly output energy production of the QF unit from the
change case and scaling down every hour with the same amount of MWs so the annual energy of the
adjusted curve will equal the reference case unit output. The adjusted hourly production curve will be
used in the change case only.
1.10. Capacity Additions and Retirements
In the GridView database, 4 GW of wind generation capacity were modeled in SPP for year 2013,
increasing to a total of 8 GW by 2022.
In addition to known retirement units, several units were made unavailable based on information provided
by SPP/Entergy. Plum Point 2 commissioning date is Jan. 01 2022. Duke Hot Spring 2 and Washington
Parish CC were not included since they were not completed. Acadia Generation Block 2 was moved to
the Entergy control area.
1.11. Operating Reserve Requirement
Entergy footprint and Tier 1 regions were enforced with 5% reserve margin each. The definition for
Entergy footprint and Tier1 regions is in table 1.3 below. In addition, several of Entergy’s areas were
enforced with special operating reserve requirements. These requirements are typically based on the loss
of the largest single generator, or the largest single generator capacity plus half the second largest
generator capacity, or a percentage of peak demand, depending on the area.
ABBTable 1.1 Region definition
Region Name Area Name Name
Entergy Footprint BCA Batesville
Entergy Footprint BUBA Benton Utilities Balancing Authority
Entergy Footprint CELE Central Louisiana Electric Company
Entergy Footprint CONWAY Conway
Entergy Footprint DENL City of North Little Rock
Entergy Footprint DERS City of Ruston
Entergy Footprint Entergy APL Entergy APL
Entergy Footprint Entergy Gulf States Entergy Gulf States
Entergy Footprint Entergy LPL North Entergy LPL North
Entergy Footprint Entergy LPL South Entergy LPL South
Entergy Footprint Entergy MPL Entergy MPL
Entergy Footprint Entergy NOPSI Entergy NOPSI
Entergy Footprint Entergy Texas Entergy Texas
Entergy Footprint LAFA Lafayette Utilities
Entergy Footprint LAGN Louisiana Generating Company
Entergy Footprint LEPA Louisiana Energy and Power Authority
Entergy Footprint PUPP Panda Union Power Partners
Entergy Footprint WESTMEMP West Memphis
Tier 1 AECI Associated Electric Cooperative Inc.
Tier 1 AEPW American Electric Power
Tier 1 AMMO Ameren Missouri
Tier 1 EMDE Empire District Electric Company
Tier 1 GRDA Grand River Dam Authority
Tier 1 INDN City of Independence
Tier 1 KACP Kansas City Power and Light Company
Tier 1 KACY Board of Public Utilities
Tier 1 MIDW Midwest Energy
Tier 1 MIPU Missouri Public Service Company
Tier 1 MKEC Mid Kansas Electric Cooperative
Tier 1 OKGE Oklahoma Gas and Electric Company
Tier 1 OMLP Osceola Municipal Light & Power
Tier 1 OMPA Oklahoma Municipal Power Authority
Tier 1 SMEPA South Mississippi Electric Power Association
Tier 1 SOCO Southern Company
Tier 1 SPRM City Utilities of Springfield
Tier 1 SPS Southwestern Public Service
Tier 1 SUNC Sunflower Electric Cooperative
Tier 1 SWPA Southwestern Power Administration
Tier 1 TVA Tennessee Valley Authority
Tier 1 WERE Westar
Tier 1 WFEC Western Farmers Electric Cooperative
Tier 1 OPPD Omaha Public Power District
Tier 1 NPPD Nebraska Public Power District
ABB1.12. Emission Model
Unit emission rates for NOX, SO2, and CO2, collected from EPA source, were added to the GridView
database.
Emission allowance price forecast, used in this database, is listed in Table 1.4.
Table 1.4: Allowance Price ($ / short ton)
CO2 NOX SO2
2013 0 1,347 323
2022 0 1,770 351
1.13. Wheeling Charge
Wheeling charges are “per MWh” charges for moving energy from one area to another in an electric
system. In the GridView model, it is modeled as tariff for particular interfaces.
Wheeling charges are listed in the Table 1.5 below:
Table 1.5: Wheeling Charge
Market Wheeling Charge ($/MWh)
From To
Assumptio Commitment Dispatch
Cleco SPP, Entergy, LEPA and LAFA 10 6
Cleco LaGen 10 3
Entergy LaGen 10 3
Entergy Cleco, SPP, AECI, LEPA, LAFA, SMEPA 10 6
Entergy All Other 1000 8
Entergy is SPP Cleco, Entergy, AECI, LEPA, LAFA, LaGen 10 5
not in SPP SPP All Other 1000 5
Market LEPA Entergy and Cleco 10 6
LAFA Entergy and Cleco 10 6
LaGen Entergy and Cleco 10 3
LaGen SOCO 1000 8
AECI and SMEPA SPP and Entergy 10 6
AECI and SMEPA All Other 1000 8
1.14. Fuel Prices
The fuel prices (in $/MMBTU) for the study years were provided by SPP. These projected fuel prices are
in year 2009 real dollars for the year 2013 and 2022 as shown in Tables 1.6 to 1.8.
Table 16: Gas Price Forecast Summary ($/MMBtu)
ABBLouisiana Mississippi Arkansas Texas_W
Year Month
No LDC With LDC No LDC With LDC No LDC With LDC No LDC With LDC
1 $ 6.21 $ 6.30 $ 6.21 $ 6.39 $ 6.58 $ 6.81 $ 5.90 $ 5.92
2 $ 6.17 $ 6.25 $ 6.16 $ 6.34 $ 6.54 $ 6.77 $ 5.85 $ 5.88
3 $ 5.96 $ 6.05 $ 5.96 $ 6.14 $ 6.32 $ 6.55 $ 5.65 $ 5.68
4 $ 5.50 $ 5.59 $ 5.50 $ 5.68 $ 5.83 $ 6.06 $ 5.26 $ 5.29
5 $ 5.46 $ 5.54 $ 5.46 $ 5.64 $ 5.79 $ 6.02 $ 5.22 $ 5.24
2013
6 $ 5.49 $ 5.58 $ 5.49 $ 5.67 $ 5.82 $ 6.05 $ 5.25 $ 5.28
7 $ 5.55 $ 5.63 $ 5.55 $ 5.72 $ 5.88 $ 6.11 $ 5.31 $ 5.34
8 $ 5.59 $ 5.68 $ 5.59 $ 5.77 $ 5.93 $ 6.16 $ 5.35 $ 5.38
9 $ 5.62 $ 5.70 $ 5.61 $ 5.79 $ 5.95 $ 6.18 $ 5.37 $ 5.40
10 $ 5.70 $ 5.79 $ 5.70 $ 5.88 $ 6.05 $ 6.27 $ 5.46 $ 5.49
11 $ 5.92 $ 6.01 $ 5.92 $ 6.09 $ 6.28 $ 6.50 $ 5.62 $ 5.65
12 $ 6.16 $ 6.25 $ 6.16 $ 6.34 $ 6.53 $ 6.76 $ 5.86 $ 5.89
1 $ 7.50 $ 7.57 $ 7.49 $ 7.64 $ 7.95 $ 8.14 $ 7.11 $ 7.13
2 $ 7.45 $ 7.52 $ 7.45 $ 7.60 $ 7.90 $ 8.09 $ 7.07 $ 7.09
3 $ 7.26 $ 7.34 $ 7.26 $ 7.41 $ 7.70 $ 7.89 $ 6.88 $ 6.90
4 $ 6.71 $ 6.78 $ 6.70 $ 6.85 $ 7.11 $ 7.30 $ 6.41 $ 6.44
5 $ 6.66 $ 6.73 $ 6.65 $ 6.80 $ 7.06 $ 7.26 $ 6.37 $ 6.39
2022
6 $ 6.72 $ 6.79 $ 6.71 $ 6.86 $ 7.13 $ 7.32 $ 6.43 $ 6.45
7 $ 6.79 $ 6.86 $ 6.78 $ 6.93 $ 7.20 $ 7.39 $ 6.49 $ 6.52
8 $ 6.84 $ 6.91 $ 6.83 $ 6.98 $ 7.25 $ 7.44 $ 6.54 $ 6.56
9 $ 6.85 $ 6.92 $ 6.84 $ 6.99 $ 7.26 $ 7.45 $ 6.55 $ 6.58
10 $ 6.91 $ 6.98 $ 6.91 $ 7.05 $ 7.33 $ 7.52 $ 6.62 $ 6.64
11 $ 7.15 $ 7.22 $ 7.14 $ 7.29 $ 7.58 $ 7.77 $ 6.78 $ 6.80
12 $ 7.40 $ 7.47 $ 7.40 $ 7.55 $ 7.85 $ 8.04 $ 7.04 $ 7.06
ABBTable 1.7: Oil Price Forecast Summary ($/MMBtu)
Louisiana Mississippi Arkansas Texas_W
Year Month
FO2 FO6 FO2 FO6 FO2 FO6 FO2 FO6
1 $18.95 $10.41 $19.23 $7.70 $18.95 $10.41 $18.95 $10.41
2 $18.95 $10.42 $19.23 $7.70 $18.95 $10.42 $18.95 $10.42
3 $18.11 $10.42 $18.38 $7.71 $18.11 $10.42 $18.11 $10.42
4 $18.01 $10.43 $18.28 $7.71 $18.01 $10.43 $18.01 $10.43
5 $17.19 $10.43 $17.45 $7.72 $17.19 $10.43 $17.19 $10.43
2013
6 $16.99 $10.44 $17.24 $7.72 $16.99 $10.44 $16.99 $10.44
7 $17.03 $10.44 $17.28 $7.72 $17.03 $10.44 $17.03 $10.44
8 $17.33 $10.45 $17.59 $7.73 $17.33 $10.45 $17.33 $10.45
9 $17.81 $10.45 $18.08 $7.73 $17.81 $10.45 $17.81 $10.45
10 $18.03 $10.46 $18.30 $7.73 $18.03 $10.46 $18.03 $10.46
11 $18.23 $10.46 $18.50 $7.74 $18.23 $10.46 $18.23 $10.46
12 $18.51 $10.47 $18.79 $7.74 $18.51 $10.47 $18.51 $10.47
1 $24.81 $13.75 $25.18 $10.17 $24.81 $13.75 $24.81 $13.75
2 $24.80 $13.76 $25.18 $10.17 $24.80 $13.76 $24.80 $13.76
3 $23.72 $13.76 $24.08 $10.18 $23.72 $13.76 $23.72 $13.76
4 $23.59 $13.77 $23.95 $10.18 $23.59 $13.77 $23.59 $13.77
5 $22.53 $13.77 $22.87 $10.19 $22.53 $13.77 $22.53 $13.77
2022
6 $22.27 $13.78 $22.60 $10.19 $22.27 $13.78 $22.27 $13.78
7 $22.32 $13.79 $22.65 $10.20 $22.32 $13.79 $22.32 $13.79
8 $22.70 $13.79 $23.04 $10.20 $22.70 $13.79 $22.70 $13.79
9 $23.33 $13.80 $23.68 $10.21 $23.33 $13.80 $23.33 $13.80
10 $23.61 $13.81 $23.97 $10.21 $23.61 $13.81 $23.61 $13.81
11 $23.86 $13.81 $24.22 $10.21 $23.86 $13.81 $23.86 $13.81
12 $24.23 $13.82 $24.59 $10.22 $24.23 $13.82 $24.23 $13.82
ABBTable 1.8: Coal Price Forecast Summary ($/MMBtu)
Complex Capacity State 2013 2022
AES Shady Point 1 & 2 320 OK 1.85 1.84
Dolet Hills 650 LA 2 2.09
Flint Creek 528 AR 2.18 2.14
Gentleman 1 & 2 1,295 NE 1.26 1.26
GRDA 1 490 OK 2.27 2.24
GRDA 2 520 OK 2.27 2.24
Harrington 1 - 3 1,021 TX 2.19 2.19
Hawthorn 5 545 MO 1.7 1.69
Holcomb 362 KS 1.94 1.91
Hugo 440 OK 2.04 2.01
Iatan 1 & 2 1,556 MO 1.94 1.94
Independence 1 & 2 1,678 AR 2.67 2.67
Jeffrey EC 1 - 3 2,164 KS 1.81 1.79
Lacygne 2 682 KS 1.71 1.67
Lawrence EC 5 373 KS 2.06 2.05
Montrose 1 - 3 505 MO 1.69 1.69
Muskogee 4 - 6 1,496 OK 2.25 2.25
Nearman Creek 200 KS 1.98 1.94
Nebraska City 1 & 2 1,316 NE 1.49 1.45
North Omaha 2 - 5 478 NE 1.45 1.42
Pirkey 675 TX 2 2.09
Plum Point 665 AR 2.67 2.67
Roademacher 2 & 3 1,172 LA 2.79 2.71
Roy L. Nelson (1, 2, 6) 550 LA 2.55 2.55
Sheldon 1 & 2 225 NE 1.45 1.42
Sikeston 235 MO 2.04 2.02
Sooner 1 & 2 1,046 OK 2.43 2.42
Southwest Power St. 2 275 MO 2.11 2.09
Tolk 1 & 2 1,060 TX 2.02 2.02
Welsh 1 - 3 1,584 TX 2.43 2.41
White 1 & 2 1,640 AR 2.68 2.64
ABB2 Transmission Modeling Assumptions
2.1. Introduction
SPP provided the following power flow cases for study years 2013 and 2022. These cases represent the
Entergy and SPP transmission systems as well as the rest of the Eastern Interconnection. These cases are
in PSS/E 30 format.
2013 Summer Peak Case:
Entergy_CBA_2013S_FINAL_V30+TVA+STEP_Zones_R1_MBPC_R6+Ratings.sav
2022 Summer Peak Case:
Entergy_CBA_2022S_FINAL_V30+STEP+TVA+SOCO+WIND_Zones_R1_MBPC_R3+Ratings.sav
See Appendix A for a summary of the modeling assumptions used in the development of these cases.
2.2. Generation and Load Levels in the Entergy Footprint
Total demand (load + losses) in the Entergy footprint in the 2013 summer peak case is 33,874 MW; the
corresponding demand for 2022 summer peak conditions is 37,972 MW. Tables 2.1(a) and (b) summarize
Entergy and other co-op/municipal load and losses for the given summer peak load conditions.
Table 2.1(a): Power Flow Case Summary -2013 Summer Peak
(Entergy_CBA_2013S_FINAL_V30+TVA+STEP_Zones_R1_MBPC_R3+Ratings.sav)
GENERATION LOSSES INTERCHANGE EXPORT
AREA DESCRIPTION LOAD (MW)
(MW) (MW) (MW) /IMPORT
328 PLUM 929.1 0 1.1 928 EXPORT
329 OMLP 0 53.7 0.5 54.2 IMPORT
331 BCA 14.1 14 0.1 0 NONE
332 LAGN 2866.7 2310.5 26.1 530.1 EXPORT
334 WESTMEMP 0 97 0.8 97.8 IMPORT
335 CONWAY 0 240 0.6 240.6 IMPORT
336 BUBA 0 73.2 0.1 73.3 IMPORT
337 PUPP 0 0 0 0 NONE
338 DERS 0 74 0 74 IMPORT
339 DENL 38 311.9 2.1 276 IMPORT
351 EES 27822.2 26846.4 542.6 432.8 EXPORT
502 CELE 3158.6 2490.5 60.9 607.2 EXPORT
503 LAFA 230.4 495 5.4 270 IMPORT
504 LEPA 163.1 227 0.1 64 IMPORT
SYSTEM TOTALS 35222.2 33233.2 640.4 1348.2 EXPORT
ABBTable 2.1(b): Power Flow Case Summary -2022 Summer Peak
(Entergy_CBA_2022S_FINAL_V30+STEP+TVA+SOCO+WIND_Zones_R1_MBPC_R3+Ratings.sav)
GENERATION LOSSES INTERCHANGE EXPORT
AREA DESCRIPTION LOAD (MW)
(MW) (MW) (MW) /IMPORT
328 PLUM 929.1 0 1.1 928 EXPORT
329 OMLP 0 60.4 0.3 60.7 IMPORT
331 BCA 14.2 14 0.1 0.1 EXPORT
332 LAGN 3446.7 2873.8 37.3 535.6 EXPORT
334 WESTMEMP 0 106.1 0.3 106.3 IMPORT
335 CONWAY 0 317.9 1.2 319.1 IMPORT
336 BUBA 0 89.9 0.2 90.1 IMPORT
337 PUPP 0.3 0 0 0.3 EXPORT
338 DERS 0 82.1 0 82.1 IMPORT
339 DENL 52.3 356 2.9 306.6 IMPORT
351 EES 30924.9 29789 662.5 472.8 EXPORT
502 CELE 3400.6 2698.9 80.2 621.4 EXPORT
503 LAFA 190.3 550.1 10.1 370 IMPORT
504 LEPA 173.5 237.4 0.1 64 IMPORT
SYSTEM TOTALS 39131.9 37175.6 796.3 1159.3 EXPORT
ABB2.3. Power Flow Analysis Criteria
This section describes the criteria that will be used in the power flow analysis part of the study.
Power flow analysis will be performed on the power flow cases described in Section 2.1. For the purposes
of this analysis, transmission facilities rated 69 kV and above within Entergy and other embedded areas
(and tie-lines out of Entergy) will be monitored. Facilities rated 345 kV and above in the Tier 1 facilities 1
will also be monitored.
For thermal overloads, each branch element (transformer, transmission line, or feeder) in the monitored
system will be monitored and electrical flows above the applicable branch rating (normal continuous
rating (Rate A) under system intact conditions and contingency conditions) will be flagged.
N-1 G-1 contingencies and selected N-2 contingencies are performed in WOTAB and Amite South. For
bus voltage violations, the following range limits and pre-to-post-contingency voltage change criteria will
be applied:
• 0.95 -1.05 pu for system intact conditions
• 0.92 -1.05 pu for contingency conditions (buses rated 69 kV – 345 kV)
• 0.95 - 1.05 pu for contingency conditions (buses rated 500 kV)
• Voltage change criteria of 0.01 pu
The following types of contingencies will be simulated in Entergy footprint: transmission line outages and
transformer outages. These outages will be based on “automatic” N-1 contingency specification and will
include branches connected between buses with a base voltage of 69 kV and above. It is understood that
for the evaluations in the individual load pockets / study regions, Entergy has been studying the impacts
of simultaneous outage of a transmission element and a generating unit (G1N1). For the major study
regions (WOTAB and Amite South), Entergy provided the respective G1N1 contingency descriptions.
G1N1 analysis will be run for these study regions (in addition to the general N-1 analysis that will be
performed for the entire study area). As in the N-1 analysis, transmission facilities rated 69 kV and above
within Entergy and other embedded areas (and tie-lines out of Entergy) will be monitored. A similar
analysis will be performed for Amite South.
1
Tier 1 Areas: Area 330 (AECI), Area 346 (SOCO), Area 347 (TVA), Area 349 (SMEPA), Area 356 (AMRN), Area 520
(AEPW), Area 544 (EMDE), Area 524 (OKGE) and Area 515 (SWPA).
ABB3 Appendixes
Appendix A - Modeling Assumptions for Entergy Regional State Committee
Minimizing Bulk Power Cost Study
•Eastern Interconnect
•Topology
ERAG MMWG models •Generation
•Load
•SPP
•Topology
SPP MOD® projects •Generation
•Load
•Entergy & Embedded
•Topology
Entergy models •Generation
•Load
•Interchange & Transactions
•SPP
•Interchange & Transactions
SPP transaction •Assume Entergy Transaction to/from SPP
spreadsheet
•Entergy
Entergy •2010‐2012 final construction plan
Construction
Plan
•SPP & Entergy
•Topology (with Construction Plan)
CBA •Generation
models •Load
•Interchange & Transactions
MBPC
models
ABBFoundational Cases
Base Model
MMWG 2009 Series (2011S & 2020S)
SPP RTO Areas
MDWG 2010 Series model with projects according to in-service dates (2012S & 2021S)
Entergy Areas
Entergy 2009 Series model with 2010-2012 Construction Plan (2013S & 2019S)
Projects
SPP MOD Projects with an Effective Date on or before 7/1/2013
SPP MOD Projects with an Effective Date on or before 6/1/2022
Entergy 2010-2012 Construction Plan Projects (Approved and Proposed) posted on Entergy’s OASIS
http://www.oatioasis.com/EES/EESDocs/ICT_PlanningStudiesAndRelatedDocuments.htm
Transactions
Entergy ICT Transactions used to build the 2009 Series Models
SPP Transactions used to build the 2009 Series ERAG MMWG Models
Load Levels
Interpolation of load levels between 2011S and 2015S to achieve 2013S for loading of SPP footprint
Extrapolation of load levels from 2015S and 2020S to achieve 2022S loading for loading of SPP footprint
Entergy Forecasted Load levels for 2013S for Entergy footprint
Entergy Forecasted Load levels for 2022S for Entergy footprint
Generation Dispatch
Entergy Generation Dispatched in accordance with Entergy OATT Attachment D
SPP Generation Dispatched in accordance with SPP MDWG processes
Model Building Process
1. SPPs Model On Demand (MOD) was used to develop the SPP RTO MDWG model
The parameters used when extracting the case information:
a) Profiles
i. MDWG 2010 B1r3 2012_Summer used for all seasonal profiles
ii. MDWG 2010 B1r3 2021_Summer used for all seasonal profiles
b) Ratings
i. Summer
ii. Normal, Long Term Emergency and Short Term Emergency
c) Projects
i. Review Status = Pending Acceptance and Acceptance
ii. Effective date greater than 8-1-2009 and less than 8-1-2013
iii. Effective date greater than 8-1-2009 and less than 8-1-2020
d) Case Definitions
i. Entergy CBA 2013S (12-14-09)
ii. Entergy CBA 2022S (12-14-09)
ABB2. The raw files that were extracted from MOD had a few errors and were corrected
3. All SPP areas were extracted from the MOD output and inserted into the 2009 Series MMWG base
cases for 2011S & 2020S; we will call this new model the Entergy CBA model
a) SPP Areas 502, 503, 504, 515, 520, 523, 524, 525, 526, 527, 531, 534, 536, 539, 540, 541,
542, 544, 545, 546, 640, 645, 650 (all SPP areas, including Nebraska entities)
4. Since we are developing a 2013 and 2022 case and the loads in the extracted MOD areas for SPP are
2012 and 2020 values we need to scale the loads accordingly
Process to scale loads
a) 2013S
i. The loads were scaled by interpolation
1. Loads in the 2011S and 2015S MMWG models were compared and a linear
slope was developed
2. The slope value was then used to create a 2013S load value
b) 2022S
i. The loads were scaled by extrapolation
1. Loads in the 2015S and 2020S MMWG models were compared and a linear
slope was developed
2. The slope value was then used to create a 2022S load value
5. Generation was scaled in each control area pro-rata to make up the difference in generation and load
from scaling the loads in step 4
6. Entergy areas were then integrated in the Entergy CBA model using Entergy’s 2009 series 2013S and
2022S models
Process to create Entergy 2022S model for integration into MMWG model
a) The 2019S Entergy 2009 series model loads were scaled using Entergy’s process for load
growth
b) Entergy units were dispatched economically to accommodate the load adjustment
Areas that were extracted from the Entergy model and integrated into the MMWG model are:
a) Entergy Areas 351,332,334,335,336,337,338,339,328,329
7. Area interchanges were synchronized in the Entergy CBA model
Transactions and interchanges from SPP MDWG 2010 series transaction book were used
a) The SPP 2012S and 2021S transactions were fed into the MMWG cases since they were the
closest to the Entergy CBA model year that was available in the workbook
b) The Entergy transactions that were in the transaction workbook were excluded and assumed
that Entergy transactions to/from SPP were maintained from Entergy Model
The Entergy transactions and interchanges that were extracted and integrated in the Entergy CBA
model during step 6 were not changed
8. The interchange mismatch for the Entergy CBA model was balanced using the PJM control area
9. Addition of the Entergy Construction plan into the Entergy CBA model
Projects that were included
a) Entergy’s 2010-2012 Construction Plan approved and proposed projects according to in-
service dates
10. Areas in SPP were re-dispatched according to SPP RTO MDWG processes to fix swing bus values
Reliability Assessment Performed
1. A reliability assessment was performed on all SPP and Entergy areas using the following criteria
ABBa) Contingency Analysis on all elements 230kV and above
2. Projects were developed to alleviate thermal and voltage violations 230kV and above
Entergy Transmission Planning Model Assessment and Recommended Changes
1. 2022 Model recommendations
a) Entergy recommended that the model include “Identified Target Areas [Beyond 2012]” from
the Entergy 2010-2012 Construction Plan to address some long term issues present in the 2022
model.
i. The projects were added to the final 2022 model only
SPP Wind generation increased to 8GW to 2022 case
1. 2022 Model additions
a) Added SPP RTO wind generation to model
b) Added Upgrades that were needed for the WITF 10% study to make wind deliverable without
overloads.
c) Fixed the Zones outside Entergy and SPP to not overlap Entergy Range.
Corrected Bus names
1. ABB noticed that some bus names had been changed to an incorrect name when updating zones.
Names were fixed
Model Name: (Entergy_CBA_2013S_FINAL_V30+TVA+STEP_Zones_R1_MBPC_R2.sav)
Powerflow model benchmarking
Analysis on initial powerflow model benchmarking results indicated the need to include some approved
Entergy 2011-2013 Construction Plan Projects. The projects below were added to the 2013 powerflow
model base case and the GridView model topology for the Entergy area.
Entergy 2011-2013 Construction Plan Projects (Approved) posted on Entergy’s OASIS:
Entergy Arkansas (EAI)
1. Pine Bluff Voltage Support Project - Phase 1 Poyen 115 kV Substation: Add 21.6 MVAR Capacitor
Bank
2. Sheridan South 500 kV FG Upgrade: Mabelvale 500 kV Substation replace 3 breakers, 13 switches,
3. and 2 line traps
4. Sheridan South 500 kV FG Upgrade: Sheridan 500 kV Substation replace 11 switches, and 6 line traps
5. Sheridan South 500 kV FG Upgrade: White Bluff 500 kV Substation replace 5 switches, and 2 line
6. Traps
7. Sheridan South 500 kV FG Upgrade: Eldorado 500 kV Substation replace 1 switch and 2 line traps
Entergy Louisiana (ELL)
1. Golden Meadow to Leeville 115 kV - Rebuild/relocate 115 kV transmission line
2. Bayou Verrett - Add 40.7 MVAR Capacitor Bank
ABBEntergy Texas (ETI)
1. Deweyville (JNEC) - Add 69 kV capacitor bank
2. Elizabeth to Gallier - Uprate 69 kV line 2.5 miles
3. Kolbs 230 kV - Add capacitor bank
4. Hearne to Calvert - Uprate 69 kV line.
5. Caldwell 69 kV: Expand capacitor bank
Entergy Gulf States Louisiana (EGL)
1. Addis to Cajun 230 kV line - Upgrade Limiting Section With Double-Bundled 649.5 ACAR (654
MVA)
2. Jackson to Tejac: Upgrade 69 kV transmission line
3. Carlyss to Citcon West 138 kV: Upgrade station equipment
Entergy Mississippi (EMI)
1. Ray Braswell to Forest Hill 115 kV Line - Reconductor line
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