Potential Cost Savings in MISO from Demand Response MWDRI Steering Committee September 24, 2007

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


ProductionCost


Total Cost


Capital CostSavings


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



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


*Source: 2007 NERC Reliability Assessment

**Source: 2007 MISO Module E



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


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



TotalNew

GenerationAdditions


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



TotalNew

GenerationAdditions


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

Documents

Potential Cost Savings in MISO from Demand Response MWDRI Steering Committee September 24, 2007