potential cost savings in miso from demand response mwdri steering committee september 24, 2007
TRANSCRIPT
Potential Cost Savingsin MISO
from Demand Response
MWDRI Steering Committee
September 24, 2007
Purpose of study: It’s Helpful to Quantify DR Benefits
• Identify the Potential Capacity and Energy Cost Savings and Avoided Generation due to demand and energy reductions at various participation levels
• Identify impacts on Emissions from demand and energy reductions
• Allocate benefits of demand reductions to states and regions and demonstrate merits of regional cooperation
Methodology
• Use the MTEP 2008 Assumptions and apply demand and energy reductions to the 20 year study period
• Run “Base Case” and Benchmark against– All modeled cases include “Legacy” Demand
Response• MW values reported in the 2007 Module E as interruptible and
Direct Load Control are applied each year of the study period.
• Reduce the growth rate of demand only, then both demand and energy (10 cases)– Reductions are from .1 to .5% from base growth rates
• Run models on a regional level and present results on MISO as a whole and at the state level using a load based multiplier
Limitations of Study• Does not include the Cost of demand response in the model
– Results identify potential cost savings– The outer limit of “What would you be willing to pay?”
• Models given reductions in demand and energy growth rates. Does not identify the potential for demand response.
• No specific type (DLC, Demand Bid etc.) of demand response is modeled, only demand and energy reductions
• Production costs are based on an economic dispatch without transmission system constraints– However, benefits are benchmarked from the reference case,
which identify the impact of demand and energy reductions• Models and Results only represent MISO companies
– Potential benefits for Demand Response to load served outside the MISO market are not captured
Presentation of Results
• The Study Results are data intensive. In consideration of various audiences interested at different levels of interest the results are presented in 2 sections– By MISO Footprint– By State
• Focus on case “DE5” with 0.5% demand reduction and 0.5% energy reduction from reference case growth rates
Results for the MISO Footprint
Results from ReducingDemand and Energy (All MISO)
Scenario
Demand Growth
Rate
Energy Growth
Rate
2027 Coincident
Peak2027 Total
EnergyDemand
ReductionEnergy
Reduction
20 Year Demand
Reduction
20 Year Energy
Reduction
Average Demand
Reduction
% % MW GWH MW GWH % %
REF* 1.28% 1.27% 140,588 745,187
D1 1.18% 1.27% 138,543 745,187 2,045 0 1.45% 0.00% 1,981 MW per .1% Demand Growth
Rate Decrease
D2 1.08% 1.27% 136,534 745,187 4,055 0 2.88% 0.00%
D3 0.98% 1.27% 134,560 745,187 6,029 0 4.29% 0.00%
D4 0.88% 1.27% 132,621 745,187 7,968 0 5.67% 0.00%
D5 0.78% 1.27% 130,683 745,187 9,906 0 7.05% 0.00%DE1 1.18% 1.17% 137,975 731,335 2,613 13,853 1.86% 1.86% 2,523 MW
per .1% Demand & Energy Growth
Rate Decrease
DE2 1.08% 1.07% 135,408 717,726 5,180 27,461 3.68% 3.69%
DE3 0.98% 0.97% 132,886 704,357 7,702 40,830 5.48% 5.48%
DE4 0.88% 0.87% 130,409 691,225 10,179 53,962 7.24% 7.24%
DE5 0.78% 0.77% 127,976 678,325 12,613 66,862 8.97% 8.97%*REF – Reference Case Demand & Energy are from 2007 Module E forecasts by each company Demand Reduction – Difference in Demand from Reference CaseEnergy Reduction (Cases DE1-DE5 Only) – Difference in Energy from Reference Case20 Year Demand Reduction – Percent decrease in Demand = Demand Reduction / Reference Demand20 Year Energy Reduction - Percent decrease in Demand = Energy Reduction / Reference Energy
Demand Reduction
Only
Demand and
Energy Reduction
Demand Reductionsfrom Base Case (All MISO)
Demand Reductions from Base Case
9,906
12,613
Generation Expansion (All MISO)
Scenario 20 Year Generation Additions (In MW)
GenerationReduction from
Reference
AverageGenerationReduction
Queue* Coal CC CT Wind** Total MW MW
REF 6,326 21,600 6,0003,52
0 12,600 50,028
D1 6,326 22,800 3,6002,24
0 12,600 47,548 2,4802,448
per .1%Demand
Growth RateDecrease
D2 6,326 19,200 3,6003,52
0 12,600 45,228 4,800
D3 6,326 20,400 03,20
0 12,600 42,508 7,520
D4 6,326 19,200 1,2001,28
0 12,600 40,588 9,440D5 6,326 16,800 1,200 640 12,600 37,548 12,480
DE1 6,326 20,400 4,8001,92
0 12,600 46,028 4,0003,397
per .1%Demand &
EnergyGrowth Rate
Decrease
DE2 6,326 18,000 3,6002,56
0 12,600 43,068 6,960
DE3 6,326 16,800 1,2003,20
0 12,600 40,108 9,920
DE4 6,326 14,400 1,2002,56
0 12,600 37,068 12,960
DE5 6,326 13,200 1,2001,92
0 12,600 35,228 14,800
* Queue Generation includes only generation in the Midwest ISO Queue with a signed Interconnection Agr.
** Wind Additions were fixed at 12,600 MW to meet state mandates (Wind contributes 15% to Reserve Margin Requirements and Runs at a 40% Capacity Factor for new Wind units and 33% Capacity Factor for existing Wind Units)
MISO Queue with Signed IA
Generators in the MISO Queue with a Signed Interconnection Agreement as of March 14, 2007
Coal305048%
CC223635%
CT5509%
Wind4908%
Coal 3,050
CC 2,236
CT 550
Wind 490
Total 6,326
Reductions in Emissions from Reducing Demand,Energy (All MISO)
Change in Emissions from Reference Case = Reference Case Emissions – Scenario Emissions
Percent Emission Reduction = 100 x Change in Emissions / Reference Case Emissions
Average Emission Reduction = Change in Emissions / (1, 2, 3, 4 or 5 Respective of the scenario modeled)
ScenarioChange in Emissions from Reference Case
(In Tons)
Percent Change in Emissions
(in %)
Average Emission Reductionfor each 0.10% Reduction
(In Tons)
CO2 Nox SO2 Hg CO2 Nox SO2 Hg CO2 Nox SO2 Hg
Negative (values in red) indicate an increase in emissions from Reference Case
REF 10,873,595,440 30,168,123 28,347,730 125
D1 -2,128,352 264,281 435,935 0.23 -0.02 0.88 1.54 0.18 -2,128,352 264,281 435,935 0.23
D2 -5,826,256 -344,156 -334,746 -0.25 -0.05 -1.14 -1.18 -0.20 -2,913,128 -172,078 -167,373 -0.13
D3 -6,618,848 -104,014 50,757 -0.08 -0.06 -0.34 0.18 -0.06 -2,206,283 -34,671 16,919 -0.03
D4 -4,260,400 -367,718 -371,222 -0.34 -0.04 -1.22 -1.31 -0.27 -1,065,100 -91,930 -92,806 -0.08
D5 -10,252,512 -705,575 -852,074 -0.60 -0.09 -2.34 -3.01 -0.48 -2,050,502 -141,115 -170,415 -0.12
DE1 109,569,552 505,970 683,996 1.23 1.01 1.68 2.41 0.98 109,569,552 505,970 683,996 1.23
DE2 228,896,080 617,703 684,057 1.77 2.11 2.05 2.41 1.41 114,448,040 308,851 342,028 0.89
DE3 330,775,040 693,041 742,165 2.65 3.04 2.30 2.62 2.11 110,258,347 231,014 247,388 0.88
DE4 437,102,176 714,144 762,032 3.46 4.02 2.37 2.69 2.76 109,275,544 178,536 190,508 0.87
DE5 543,499,328 901,581 951,172 4.43 5.00 2.99 3.36 3.53 108,699,866 180,316 190,234 0.89
Capital & Production Costs(All MISO)
Scenario
AccumulatedPresentValue
Capital Cost
AccumulatedPresentValue
ProductionCost
AccumulatedPresentValue
Total Cost
AccumulatedPresentValue
Capital CostSavings
AccumulatedPresentValue
ProductionCost Savings
AccumulatedPresentValueTotal
Cost Savings
Average CostSavings foreach 0.10%Reduction
MaximumDemand
ResponseValue
($Million) ($Million) ($Million) ($Million) ($Million) ($Million) ($Million) $/KW
REF 48,519 241,342 289,861
D1 48,362 239,808 288,170 158 1,534 1,692 1,692 827
D2 44,270 241,783 286,053 4,250 -441 3,809 1,904 939
D3 43,637 240,541 284,178 4,882 801 5,683 1,894 943
D4 41,761 241,590 283,351 6,759 -248 6,511 1,628 817
D5 39,084 242,370 281,454 9,436 -1,028 8,408 1,682 849
DE1 47,614 237,271 284,885 905 4,071 4,977 4,977 1,904
DE2 44,306 235,715 280,020 4,214 5,627 9,841 4,920 1,900
DE3 41,196 233,118 274,314 7,324 8,224 15,548 5,183 2,019
DE4 38,051 231,190 269,241 10,468 10,152 20,620 5,155 2,026
DE5 36,311 228,687 264,998 12,208 12,655 24,863 4,973 1,971
Note: Production Costs Include costs for all emissions except CO2. Production costs with a CO2 tax are on the next slide.
Average Cost Savings = Total Cost Savings / (1, 2, 3, 4 or 5 Respective of the Scenario Modeled)
Maximum Demand Response Value = 1000 x Total Cost Savings / Demand Reduction in the Scenario
Reference Installed Capacity Cost Data
No AFUDC ($/kW) - 2007$s
Coal (CFB) 2426
Coal (Pulverized) 1936
CT (25MW) 662
CT (50MW) 524
CTCC 730
Fuel Cell 5820
IGCC 2058
Nuclear 2633
Solar 6040
Wind 2059
Maximum Demand Reduction Value/kW:
Case D5 $849
Case DE5 $1971
Source: Vermont Deliberative Polling Reference Document
ReferenceCost of Demand Response v.
Peaking Capacity
• Peakers cost roughly $75/kW-yr (50-110)– Capacity in excess markets can be cheaper
• Typical Demand Response Program Costs– Direct Load Control: $55/kW/yr– Demand Bid/Buyback: $25/kW-yr or less– Interruptible rates: $50/kW-yr– Source: Quantec, Demand Response Proxy
Supply Curves 2006
• Energy Efficiency also cheap
Case DE5 Summary
• Compared with REF case in 2027– Peak is 12,600 MW lower, -9%– 66,000 fewer GWh used, -9%– 14,800 MW of new generation avoided– Additional 35,200 MW still needed– Significant emissions savings from energy
reductions– PV savings from production cost reductions
and capital cost reductions equal to $24.9 B
Conclusions
• Reducing the energy growth in addition to demand growth adds to effective demand reduction
• Capacity Value of Load Reduction >> Cost of DR/EE• Demand-only reductions result in more emissions
produced because older less efficient units are running more and more energy is needed, requiring more combustion.
• There are regional differences in the benefits of demand response. Regions with a higher reserve margin benefit less with demand only reductions because the demand reductions do not defer capacity build until later years. With Energy reductions, the benefits are more uniform.
Results by State
Methodology to RepresentDemand Response By State
• State Representations are derived from regional results using the following methods:– Regional Averages – represented at state level– Load Based Multiplier
• This is a representation of the load in each state as compared to MISO as a whole.
• The load participation of a company by state was developed from company websites and from company representatives and is summarized in the following two tables
– Data is in supplemental slides
Potential Cost Savings By State (Calculated using Load Based
Multiplier)
Scenario
20 Year Accumulated Present Value of Cost Savings
MN WI IA ND SD MT IL MO IN OH MI
$Million $Million $Million $Million $Million $Million $Million $Million $Million $Million $Million
D1 118.6 134.9 31.4 11.5 4.6 1.3 158.3 133.2 262.8 367.8 467.6
D2 207.7 236.3 55.0 20.1 8.0 2.2 540.7 455.0 768.2 751.3 764.3
D3 303.5 345.2 80.4 29.3 11.7 3.2 608.4 512.0 972.2 1,265.0 1,551.9
D4 403.8 459.3 107.0 39.0 15.6 4.3 840.8 707.6 1,228.3 1,299.7 1,405.3
D5 488.2 555.3 129.3 47.1 18.8 5.2 1,130.7 951.5 1,633.4 1,676.2 1,771.8
DE1 597.3 679.3 158.2 57.7 23.0 6.4 579.4 487.6 713.0 867.4 1,025.8
DE2 1,214.3 1,381.1 321.6 117.3 46.9 12.9 845.5 711.5 1,344.3 1,731.9 2,113.7
DE3 1,745.0 1,984.8 462.2 168.5 67.3 18.6 1,437.8 1,209.9 2,253.2 2,817.1 3,383.2
DE4 2,334.5 2,655.3 618.4 225.5 90.1 24.8 2,025.3 1,704.3 3,088.4 3,635.9 4,217.9
DE5 2,815.4 3,202.2 745.7 271.9 108.7 29.9 2,539.2 2,136.7 3,809.8 4,315.9 4,888.2
Cost Savings does not include a Cost for Demand Response Program or a Tax on CO2 Emissions
Savings are based on load served by MISO within each state – additional savings could be gained by other load serving entities
Accumulated Present Value Savings Allocated to States from Scenario DE5 in 2027
MN, $2,815
WI , $3,202
IL, $2,539
MO, $2,137IN, $3,810
OH, $4,316
MI, $4,888
IA, $746ND, $272
SD, $109
MT, $30
MN
WI
IA
ND
SD
MT
IL
MO
IN
OH
MI
Total sums approximately to the $24.9 billion from slide 12
Maximum DR Value By State(Calculated From Regional
Average)Scenario MISO West Region Central Region
Central & East Region
EastRegion
MN WI IA ND SD MT IL MO IN OH MI
$/KW $/KW $/KW $/KW $/KW $/KW
D1 1,046 609 665 911 1,479 1,822
D2 965 538 1,146 1,125 1,078 1,049
D3 1,017 528 867 1,012 1,346 1,547
D4 885 532 907 950 1,050 1,111
D5 894 512 984 1,000 1,037 1,060
DE1 2,113 1,807 2,254 2,256 2,260 2,263
DE2 1,941 1,853 1,659 1,802 2,132 2,331
DE3 2,077 1,791 1,898 2,037 2,358 2,552
DE4 2,070 1,813 2,023 2,097 2,270 2,374
DE5 2,007 1,764 2,047 2,080 2,157 2,203
Source: From Regional Expansion with values applied to the state level. IN & OH have a load weighted calculation since they are in multiple study regions.
Note: Values do not include a Cost for the Demand Response Program or a Tax on CO2 Emissions
On Mutual Benefit of Reductions among All States
• States are within MISO and three sub-MISO regional markets
• Individual state actions affect regional markets, are diluted from state perspective
• States get full benefit of their demand resources if all states are producing demand resources
• Brattle Report for MADRI illustrates this – possible further work for MISO
Central Region Reserve Margins After Expansion
Central Region Reserve Margins After Expansion
14
15
16
17
18
19
20
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
Re
se
rve
Ma
rgin
(%
)
REF
CD5
CDE5
Note: No Firm Transmission is included in the Central Region Reserve Margins After Expansion
East Region Reserve Margins After Expansion
East Region Reserve Margins After Expansion
12
13
14
15
16
17
18
19
20
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
Re
se
rve
Ma
rgin
(%
)
REF
CD5
CDE5
West Region Reserve Margins After Expansion
West Region Reserve Margins After Expansion
14
16
18
20
22
24
26
28
30
32
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
Res
erve
Mar
gin
(%
)
REF
CD5
CDE5
Regional Background Information on Demand Response, Reserve Margins andAllocation to States
2007 Demand Response Levels
2007 Interruptible Demand & Direct Control Load Management
1,112 8681,555 1,942
2,800
4,686
746
3,1692,585-
2,186370 -
1,000
1,016
506 1,600
15
-
1,000
2,000
3,000
4,000
5,000
6,000
ERCOT* FRCC* MRO* NPCC* RFC* SERC* SPP* WECC* MISO**
MW
Interruptible Demand Direct Control Load Management
2007 Demand Response Levels
2007 Interruptible Demand & Direct Control Load Management
1.8% 1.9%3.2%
1.7% 1.5%2.3%
1.8% 2.0% 2.3% 2.0%
4.8%
0.5%
0.5%0.3%
1.4%0.6%0.0%0.0%0.0%
0.8%
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
ERCOT* FRCC* MRO* NPCC* RFC* SERC* SPP* WECC* MISO** NERC*
Per
cen
tag
e o
f T
ota
l In
tern
al D
eman
d
Interruptible Demand Direct Control Load Management
*Source: 2007 NERC Reliability Assessment
**Source: 2007 MISO Module E
2007 Demand Response Levels
2007 Interruptible Demand & Direct Control Load Management
1.8% 1.9%3.2%
1.7% 1.5%2.3% 1.8% 2.0% 2.3% 2.0%
4.8%
0.5%0.5%
0.3%1.4%
0.6%0.0%0.0%0.0%
0.8%
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
ERCOT*
FRCC*
MRO*
NPCC*
RFC*
SERC*
SPP*
WECC*
MIS
O**
NERC*Pe
rce
nta
ge
of
To
tal
Inte
rna
l D
em
an
d
Interruptible Demand Direct Control Load Management
Central RegionGeneration Reductions
Scenario
QueueGenerationAdditions
ExpansionGenerationAdditions
TotalNew
GenerationAdditions
GenerationExpansionReduction
AverageGenerationReduction
Per each 0.10%Reduction
Central Region MW MW MW MW MW
REF 1,700 12,360 14,060
D1 1,700 11,160 12,860 1,200 1,200
D2 1,700 10,280 11,980 2,080 1,040
D3 1,700 9,320 11,020 3,040 1,013
D4 1,700 8,120 9,820 4,240 1,060
D5 1,700 7,240 8,940 5,120 1,024
DE1 1,700 11,160 12,860 1,200 1,200
DE2 1,700 9,960 11,660 2,400 1,200
DE3 1,700 9,080 10,780 3,280 1,093
DE4 1,700 7,880 9,580 4,480 1,120
DE5 1,700 7,000 8,700 5,360 1,072
East RegionGeneration Reductions
Scenario
QueueGenerationAdditions
ExpansionGenerationAdditions
TotalNew
GenerationAdditions
GenerationExpansionReduction
AverageGenerationReductionPer each
0.10%Reduction
East Region MW MW MW MW MW
REF 0 10,560 10,560
D1 0 9,920 9,920 640 640
D2 0 9,040 9,040 1,520 760
D3 0 7,920 7,920 2,640 880
D4 0 7,840 7,840 2,720 680
D5 0 7,200 7,200 3,360 672
DE1 0 9,920 9,920 640 640
DE2 0 9,040 9,040 1,520 760
DE3 0 7,600 7,600 2,960 987
DE4 0 6,640 6,640 3,920 980
DE5 0 6,320 6,320 4,240 848
West RegionGeneration Reductions
Scenario
QueueGenerationAdditions
ExpansionGenerationAdditions
TotalNew
GenerationAdditions
GenerationExpansionReduction
AverageGenerationReductionPer each
0.10%Reduction
West Region MW MW MW MW MW
REF 4,626 20,782 25,408
D1 4,626 20,142 24,768 640 640
D2 4,626 19,582 24,208 1,200 600
D3 4,626 18,942 23,568 1,840 613
D4 4,626 18,302 22,928 2,480 620
D5 4,626 16,782 21,408 4,000 800
DE1 4,626 18,622 23,248 2,160 2,160
DE2 4,626 17,742 22,368 3,040 1,520
DE3 4,626 17,102 21,728 3,680 1,227
DE4 4,626 16,222 20,848 4,560 1,140
DE5 4,626 15,582 20,208 5,200 1,040
Company Demand Distributionby State (In Percent)
% Demand by State RegionMultiState
MN WI IA ND SD MT IL MO IN MI OH
Alliant East W n 1.00 Alliant West W y 0.10 0.90 AmerenCILCO C n 1.00 AmerenCIPS C n 1.00 AmerenIP C n 1.00 AmerenUE C n 1.00 Cincinnati Gas & Electric Co. C n 1.00City Water, Light & Power (Springfield, IL) C n 1.00 Consumers Energy Co. E n 1.00 Detroit Edison Co. E n 1.00 FirstEnergy Ohio E n 1.00Great River Energy W y 0.98 0.02 Hoosier Energy Rural Electric Coop, Inc. C n 1.00 Hutchinson Utilities Commission W n 1.00 Indianapolis Power & Light Co. C n 1.00 Lansing Board of Water & Light E n 1.00 Madison Gas & Electric Co. W n 1.00 Minnesota Power, Inc. W n 1.00 Montana Dakota Utilities Co. W y 0.70 0.30 Northern Indiana Public Service Co. E n 1.00 Northern States Power Co. W y 0.75 0.16 0.05 0.04 Otter Tail Power Co. W y 0.46 0.45 0.09 PSI Energy, Inc. C n 1.00 Southern Illinois Power Coop C n 1.00 Southern Minnesota Municipal Power
Agency W n 1.00 Vectren (SIGE) C n 1.00 We Energies W n 1.00 Wisconsin Public Power, Inc. System W n 1.00 Wisconsin Public Service Corp. W n 1.00 Wolverine Power Supply Coop, Inc. E n 1.00
Source: Midwest ISO
TOTAL 2008 MISO PEAK DEMNAD = 115,154 Region
MultiState MN WI IA ND SD MT IL MO IN MI OH
Alliant East W n 0 2,861 0 0 0 0 0 0 0 0 0Alliant West W y 404 0 3,634 0 0 0 0 0 0 0 0AmerenCILCO C n 0 0 0 0 0 0 2,066 0 0 0 0AmerenCIPS C n 0 0 0 0 0 0 3,946 0 0 0 0AmerenIP C n 0 0 0 0 0 0 4,128 0 0 0 0AmerenUE C n 0 0 0 0 0 0 0 9,317 0 0 0Cincinnati Gas & Electric Co. C n 0 0 0 0 0 0 0 0 0 0 5,889City Water, Light & Power (Springfield, IL) C n 0 0 0 0 0 0 477 0 0 0 0Consumers Energy Co. E n 0 0 0 0 0 0 0 0 0 9,552 0Detroit Edison Co. E n 0 0 0 0 0 0 0 0 0 12,385 0FirstEnergy Ohio E n 0 0 0 0 0 0 0 0 0 0 13,982Great River Energy W y 2,609 53 0 0 0 0 0 0 0 0 0Hoosier Energy Rural Electric Coop, Inc. C n 0 0 0 0 0 0 0 0 1,422 0 0Hutchinson Utilities Commission W n 64 0 0 0 0 0 0 0 0 0 0Indianapolis Power & Light Co. C n 0 0 0 0 0 0 0 0 3,242 0 0Lansing Board of Water & Light E n 0 0 0 0 0 0 0 0 0 464 0Madison Gas & Electric Co. W n 0 759 0 0 0 0 0 0 0 0 0Minnesota Power, Inc. W n 1,787 0 0 0 0 0 0 0 0 0 0Montana Dakota Utilities Co. W y 0 0 0 340 0 146 0 0 0 0 0Northern Indiana Public Service Co. E n 0 0 0 0 0 0 0 0 3,591 0 0Northern States Power Co. W y 7,699 1,642 0 493 431 0 0 0 0 0 0Otter Tail Power Co. W y 503 0 0 492 98 0 0 0 0 0 0PSI Energy, Inc. C n 0 0 0 0 0 0 0 0 7,267 0 0Southern Illinois Power Coop C n 0 0 0 0 0 0 454 0 0 0 0Southern Minnesota Municipal Power Agency W n 655 0 0 0 0 0 0 0 0 0 0Vectren (SIGE) C n 0 0 0 0 0 0 0 0 1,359 0 0We Energies W n 0 6,596 0 0 0 0 0 0 0 0 0Wisconsin Public Power, Inc. System W n 0 983 0 0 0 0 0 0 0 0 0Wisconsin Public Service Corp. W n 0 2,711 0 0 0 0 0 0 0 0 0Wolverine Power Supply Coop, Inc. E n 0 0 0 0 0 0 0 0 0 650 0TOTAL MISO DEMAND IN STATE 13,721 15,606 3,634 1,325 530 146 11,072 9,317 16,88223,050 19,872
Load Based Multiplier* (State to MISO) .1191 .1355 .0316 .0115 .0046 .0013 .0961 .0809 .1466 .2002 .1726
Calculation of Load Based Multiplier
Load Based Multiplier = Total MISO Demand in State / Total 2008 MISO Peak Demand