Potential Cost Savings in 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 Reducing Demand and Energy (All MISO)

Demand Reduction Only Demand and Energy Reduction

Scenario Demand Growth Rate Energy Growth Rate 2027 Coincident Peak 2027 Total Energy Demand Reduction Energy Reduction 20 Year Demand Reduction 20 Year Energy Reduction Average Demand Reduction

REF*

D1 D2 D3 D4

D5

%

1.28%

1.18% 1.08% 0.98% 0.88% %

1.27%

1.27% 1.27% 1.27% 1.27% MW

140,588

138,543 136,534 134,560 132,621 GWH

745,187

745,187 745,187 745,187 745,187

0.78% 1.27% 130,683 745,187

MW 2,045 4,055 6,029 7,968

9,906

GWH 0 0 0 0

0

% 1.45% 2.88% 4.29% 5.67%

7.05%

% 0.00% 1,981 MW 0.00% per .1% 0.00% Demand Growth 0.00%

0.00%

Rate Decrease DE1 DE2 DE3 DE4 1.18% 1.08% 0.98% 0.88% 1.17% 1.07% 0.97% 0.87% 137,975 135,408 132,886 130,409 731,335 717,726 704,357 691,225 2,613 5,180 7,702 10,179 13,853 27,461 40,830 53,962 1.86% 3.68% 5.48% 7.24% 1.86% 2,523 MW per .1% 3.69% Demand 5.48% 7.24%

8.97%

& Energy Growth Rate Decrease

DE5 0.78% 0.77% 127,976 678,325 12,613 66,862 8.97%

*REF – Reference Case Demand & Energy are from 2007 Module E forecasts by each company Demand Reduction – Difference in Demand from Reference Case Energy Reduction (Cases DE1-DE5 Only) – Difference in Energy from Reference Case 20 Year Demand Reduction – Percent decrease in Demand = Demand Reduction / Reference Demand 20 Year Energy Reduction - Percent decrease in Demand = Energy Reduction / Reference Energy

Demand Reductions from Base Case (All MISO)

Demand Reductions from Base Case

9,906 12,613

Generation Expansion (All MISO)

Scenario

REF

D1 D2 D3 D4

D5

DE1 DE2 DE3 DE4

DE5

Queue*

6,326

20 Year Generation Additions (In MW) Coal CC CT Wind**

21,600 6,000 3,520 12,600

6,326 6,326 6,326 22,800 19,200 20,400 3,600 2,240 3,600 3,520 0 3,200 12,600 12,600 12,600 6,326

6,326

6,326 6,326 6,326 6,326

6,326

19,200

16,800

20,400 18,000 16,800 14,400

13,200

1,200 1,280

1,200 640

4,800 1,920 3,600 2,560 1,200 3,200 1,200 2,560

1,200 1,920

12,600

12,600

12,600 12,600 12,600 12,600

12,600

Total

50,028

47,548 45,228 42,508 40,588

37,548

46,028 43,068 40,108 37,068

35,228

Generation Reduction from Reference MW 2,480 4,800 7,520 9,440

12,480

4,000 6,960 9,920 12,960

14,800

Average Generation Reduction MW 2,448 per .1% Demand Growth Rate Decrease 3,397 per .1% Demand & Energy Growth Rate Decrease * 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

Wind 490 8% CT 550 9% CC 2236 35% Coal 3050 48% Coal CC CT Wind Total 3,050 2,236 550 490 6,326

Reductions in Emissions from Reducing Demand,Energy (

All MISO

)

Scenario Change in Emissions from Reference Case (In Tons) Percent Change in Emissions (in %) Average Emission Reduction for each 0.10% Reduction (In Tons) SO2 CO2 Nox SO2 Hg CO2 Nox SO2 Hg CO2 Nox Negative (values in red) indicate an increase in emissions from Reference Case REF D1 D2 D3 D4

D5

DE1 DE2 DE3 DE4

DE5

10,873,595,440 30,168,123 28,347,730 -2,128,352 264,281 435,935 -5,826,256 -6,618,848 -344,156 -104,014 -334,746 50,757 -4,260,400

-10,252,512

109,569,552 228,896,080 -367,718

-705,575

505,970 617,703 -371,222 683,996 684,057 125 0.23

1.23

1.77

-0.02

1.01

2.11

0.88

1.54 0.18

-0.25 -0.05 -1.14 -1.18 -0.20

-0.08 -0.06 -0.34

0.18

-0.06

-0.34 -0.04 -1.22 -1.31 -0.27

-852,074 -0.60 -0.09 -2.34 -3.01 -0.48

1.68

2.05

2.41 0.98

2.41 1.41

330,775,040 437,102,176

543,499,328

693,041 714,144

901,581

742,165 762,032

951,172

2.65

3.46

4.43

3.04

4.02

2.30

2.37

2.62 2.11

2.69 2.76

5.00 2.99 3.36 3.53

-2,128,352 -2,913,128 -2,206,283 -1,065,100

-2,050,502

109,569,552 114,448,040 110,258,347 109,275,544

108,699,866

Change in Emissions from Reference Case = Reference Case Emissions – Scenario Emissions 264,281 -172,078 -34,671 -91,930

-141,115

505,970 308,851 231,014 178,536

180,316

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) Hg 435,935 0.23

-167,373 -0.13

16,919 -0.03

-92,806 -0.08

-170,415 -0.12

683,996 342,028 1.23

0.89

247,388 190,508

190,234

0.88

0.87

0.89

Capital & Production Costs (All MISO)

Scenario Accumulated Present Value Capital Cost REF D1 D2 D3 D4

D5

DE1 DE2 DE3 DE4

DE5

($Million)

48,519

48,362 44,270 43,637 41,761

39,084

47,614 44,306 41,196 38,051

36,311

Accumulated Present Value Production Cost ($Million)

241,342

239,808 241,783 240,541 241,590

242,370

237,271 235,715 233,118 231,190

228,687

Accumulated Present Value Total Cost Accumulated Present Value Capital Cost Savings Accumulated Present Value Production Cost Savings Accumulated Present Value Total Cost Savings ($Million) ($Million) ($Million) ($Million)

289,861

288,170 286,053 284,178 283,351

281,454

284,885 280,020 274,314 269,241

264,998

158 4,250 4,882 6,759

9,436

905 4,214 7,324 10,468

12,208

1,534 -441 801 -248

-1,028

4,071 5,627 8,224 10,152

12,655

1,692 3,809 5,683 6,511

8,408

4,977 9,841 15,548 20,620

24,863

Average Cost Savings for each 0.10% Reduction ($Million) 1,692 1,904 1,894 1,628

1,682

4,977 4,920 5,183 5,155

4,973

Maximum Demand Response Value $/KW 827 939 943 817

849

1,904 1,900 2,019 2,026

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) Coal (Pulverized) CT (25MW) CT (50MW) CTCC Fuel Cell IGCC Nuclear Solar Wind 2426 1936 662 524 730 5820 2058 2633 6040 2059 Maximum Demand Reduction Value/kW: Case D5 $849 Case DE5 $1971 Source: Vermont Deliberative Polling Reference Document

Reference Cost 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 Represent Demand 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 D1 D2 D3 D4 D5 DE1 DE2 DE3 DE4

DE5 MN

$Million 118.6

207.7

303.5

403.8

488.2

597.3

1,214.3

1,745.0

2,334.5

2,815.4

WI

$Million 134.9

236.3

345.2

459.3

555.3

679.3

1,381.1

1,984.8

2,655.3

3,202.2

IA

$Million 31.4

55.0

80.4

107.0

129.3

158.2

321.6

462.2

618.4

745.7

20 Year Accumulated Present Value of Cost Savings

ND

$Million

SD MT

$Million $Million

IL

$Million

MO

$Million 11.5

20.1

29.3

39.0

47.1

57.7

117.3

168.5

225.5

271.9

4.6

8.0

11.7

15.6

18.8

23.0

46.9

67.3

90.1

108.7

1.3

2.2

3.2

4.3

5.2

6.4

12.9

18.6

24.8

29.9

158.3

540.7

608.4

840.8

1,130.7

579.4

845.5

1,437.8

2,025.3

2,539.2

133.2

455.0

512.0

707.6

951.5

487.6

711.5

1,209.9

1,704.3

2,136.7

IN

$Million 262.8

768.2

972.2

1,228.3

1,633.4

713.0

1,344.3

2,253.2

3,088.4

3,809.8

OH

$Million 367.8

751.3

1,265.0

1,299.7

1,676.2

867.4

1,731.9

2,817.1

3,635.9

4,315.9

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

MI

$Million 467.6

764.3

1,551.9

1,405.3

1,771.8

1,025.8

2,113.7

3,383.2

4,217.9

4,888.2

Accumulated Present Value Savings Allocated to States from Scenario DE5 in 2027

MI, $4,888 OH, $4,316 IN, $3,810 MN, $2,815 WI , $3,202 IA, $746 ND, $272 MT, $30 SD, $109 IL, $2,539 MO, $2,137 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 D1 D2 D3 D4 D5 DE1 DE2 DE3 DE4

DE5

MISO $/KW 1,046 965 1,017 885 894 2,113 1,941 2,077 2,070

2,007 MN WI

West Region

IA

$/KW 609 538 528 532 512 1,807 1,853 1,791 1,813

1,764 ND SD MT

Central Region

IL

$/KW 665 1,146 867 907 984 2,254 1,659 1,898 2,023

2,047 MO

Central & East Region

IN

$/KW 911

OH

$/KW 1,479 1,125 1,012 950 1,000 2,256 1,802 2,037 2,097

2,080

1,078 1,346 1,050 1,037 2,260 2,132 2,358 2,270

2,157

East Region

MI

$/KW 1,822 1,049 1,547 1,111 1,060 2,263 2,331 2,552 2,374

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

20 19 16 15 18 17 14 20 08 20 09 20 10 20 11 20 12 20 13 20 14 20 15 20 16 20 17 20 18 20 19 20 20 20 21 20 22 20 23 20 24 20 25 20 26 20 27 Note: No Firm Transmission is included in the Central Region Reserve Margins After Expansion REF CD5 CDE5

East Region Reserve Margins After Expansion

East Region Reserve Margins After Expansion

20 19 18 17 16 15 14 13 12 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 REF CD5 CDE5

West Region Reserve Margins After Expansion

West Region Reserve Margins After Expansion

32 30 28 26 24 22 20 18 16 14 20 08 20 09 20 10 20 11 20 12 20 13 20 14 20 15 20 16 20 17 20 18 20 19 20 20 20 21 20 22 20 23 20 24 20 25 20 26 20 27 REF CD5 CDE5

Regional Background Information on Demand Response, Reserve Margins and Allocation to States

2007 Demand Response Levels

2007 Interruptible Demand & Direct Control Load Management 6,000 5,000 1,016 4,000 1,000 506 1,600 3,000 2,000 1,000 4,686 1,112 2,186 370 2,800 3,169 2,585 868 1,555 1,942 15 746 ERCOT* FRCC* MRO* NPCC* Interruptible Demand RFC* SERC* SPP* WECC* MISO** Direct Control Load Management

2007 Demand Response Levels

2007 Interruptible Demand & Direct Control Load Management 8.0% 7.0% 6.0% 5.0% 4.0% 3.0% 2.0% 1.0% 0.0% 0.0% 1.8% 4.8% 1.9% 0.8% 3.2% 0.0% 1.7% 0.5% 1.5% 0.5% 2.3% 0.0% 1.8% 0.3% 2.0% 1.4% 2.3% 0.6% 2.0% ERCOT* FRCC* MRO* NPCC* Interruptible Demand RFC* SERC* SPP* WECC* MISO** NERC* 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 8.0% 7.0% 6.0% 5.0% 4.0% 3.0% 2.0% 1.0% 0.0% 0.0% 1.8% ER C O T* 4.8% 1.9% FR C C * 0.8% 3.2% MR O * 0.0% 1.7% N PC C * 0.5% 1.5% R FC * 0.5% 2.3% SER C * 0.0% 1.8% SPP* 0.3% 2.0% W EC C * 1.4% 2.3% MI SO ** 0.6% 2.0% N ER C * Interruptible Demand Direct Control Load Management

Central Region Generation Reductions

Scenario Central Region

REF

D1 D2 D3 D4 D5 DE1 DE2 DE3 DE4

DE5

Queue Generation Additions MW

1,700

1,700 1,700 1,700 1,700 1,700 1,700 1,700 1,700 1,700

1,700

Expansion Generation Additions MW

12,360

11,160 10,280 9,320 8,120 7,240 11,160 9,960 9,080 7,880

7,000

Total New Generation Additions MW

14,060

12,860 11,980 11,020 9,820 8,940 12,860 11,660 10,780 9,580

8,700

Generation Expansion Reduction MW Average Generation Reduction Per each 0.10% Reduction MW 1,200 2,080 3,040 4,240 5,120 1,200 2,400 3,280 4,480

5,360

1,200 1,040 1,013 1,060 1,024 1,200 1,200 1,093 1,120

1,072

Scenario East Region

REF

D1 D2 D3 D4 D5 DE1 DE2 DE3 DE4

DE5

East Region Generation Reductions

Queue Generation Additions MW

0

0 0 0 0 0 0 0 0 0

0

Expansion Generation Additions MW

10,560

9,920 9,040 7,920 7,840 7,200 9,920 9,040 7,600 6,640

6,320

Total New Generation Additions MW

10,560

9,920 9,040 7,920 7,840 7,200 9,920 9,040 7,600 6,640

6,320

Generation Expansion Reduction MW 640 1,520 2,640 2,720 3,360 640 1,520 2,960 3,920

4,240

Average Generation Reduction Per each 0.10% Reduction MW 640 760 880 680 672 640 760 987 980

848

Scenario West Region

REF

D1 D2 D3 D4 D5 DE1 DE2 DE3 DE4

DE5

West Region Generation Reductions

Queue Generation Additions MW

4,626

4,626 4,626 4,626 4,626 4,626 4,626 4,626 4,626 4,626

4,626

Expansion Generation Additions MW

20,782

20,142 19,582 18,942 18,302 16,782 18,622 17,742 17,102 16,222

15,582

Total New Generation Additions MW

25,408

24,768 24,208 23,568 22,928 21,408 23,248 22,368 21,728 20,848

20,208

Generation Expansion Reduction MW 640 1,200 1,840 2,480 4,000 2,160 3,040 3,680 4,560

5,200

Average Generation Reduction Per each 0.10% Reduction MW 640 600 613 620 800 2,160 1,520 1,227 1,140

1,040

Company Demand Distribution by State (In Percent)

% Demand by State Alliant East Alliant West AmerenCILCO AmerenCIPS AmerenIP AmerenUE Cincinnati Gas & Electric Co.

City Water, Light & Power (Springfield, IL) Consumers Energy Co.

Detroit Edison Co.

FirstEnergy Ohio Great River Energy Hoosier Energy Rural Electric Coop, Inc.

Hutchinson Utilities Commission Indianapolis Power & Light Co.

Lansing Board of Water & Light Madison Gas & Electric Co.

Minnesota Power, Inc.

Montana Dakota Utilities Co.

Northern Indiana Public Service Co.

Northern States Power Co.

Otter Tail Power Co.

PSI Energy, Inc.

Southern Illinois Power Coop Southern Minnesota Municipal Power Agency Vectren (SIGE) Region W W W E W W C C W W C C C C C C E E E W C W C E n n y n y y n n Multi State n y n n n n n n n n n y n n n n MN 0.10

0.98

1.00

1.00

0.75

0.46

WI 1.00

0.02

1.00

0.16

W C n n 1.00

IA 0.90

ND SD MT 0.70

0.05 0.04

0.45 0.09

0.30

IL MO IN 1.00

1.00

1.00

1.00

1.00

1.00

1.00

1.00

1.00

1.00

1.00

1.00

MI OH 1.00

1.00

1.00

1.00

Calculation of Load Based

TOTAL 2008 MISO PEAK DEMNAD = 115,154 Alliant East Alliant West AmerenCILCO AmerenCIPS AmerenIP AmerenUE Cincinnati Gas & Electric Co.

City Water, Light & Power (Springfield, IL) Consumers Energy Co.

Detroit Edison Co.

FirstEnergy Ohio Great River Energy Hoosier Energy Rural Electric Coop, Inc.

Hutchinson Utilities Commission Indianapolis Power & Light Co.

Lansing Board of Water & Light Madison Gas & Electric Co.

Minnesota Power, Inc.

Montana Dakota Utilities Co.

Northern Indiana Public Service Co.

Northern States Power Co.

Otter Tail Power Co.

PSI Energy, Inc.

Southern Illinois Power Coop Southern Minnesota Municipal Power Agency Vectren (SIGE) We Energies Wisconsin Public Power, Inc. System Wisconsin Public Service Corp.

Wolverine Power Supply Coop, Inc.

TOTAL MISO DEMAND IN STATE

Load Based Multiplier* (State to MISO)

Multiplier

Region W W C C C C C C E E E W C W C E W W W E W W C C W C W W W E Multi State n y n n n n n n n n n y n n n n n n y n y y n n n n n n n n MN 0 404 0 0 0 0 0 0 0 0 0 2,609 0 64 0 0 0 1,787 0 0 7,699 503 0 0 655 0 0 0 0 0 13,721

.1191

WI 2,861 0 0 0 0 0 0 0 0 0 0 53 0 0 0 0 759 0 0 0 1,642 0 0 0 0 0 6,596 983 2,711 0 15,606

.1355

IA 0 3,634 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3,634

.0316

ND 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 340 0 493 492 0 0 0 0 0 0 0 0 1,325

.0115

SD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 MT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 IL 0 0 2,066 3,946 4,128 0 0 477 0 0 0 0 0 0 0 MO 0 0 0 0 0 9,317 0 0 0 0 0 0 0 0 0 IN 0 0 0 0 0 0 0 0 0 0 0 0 1,422 0 3,242 MI 0 0 0 0 0 0 0 0 9,552 12,385 0 0 0 0 0 0 0 0 0 0 431 98 0 0 0 0 146 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3,591 0 0 7,267 464 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 454 0 0 0 0 0 0 0 0 0 1,359 0 0 0 0 0 0 0 0 0 0 0 0 530 0 0 0 0 0 0 0 0 0 0 0 0 0 0 650

.0046 .0013 .0961 .0809 .1466 .2002

0 0 0 146 11,072 9,317 16,882 23,050 19,872

.1726

0 0 0 0 0 0 0 0 OH 0 0 0 0 0 0 5,889 0 0 0 13,982 0 0 0 0 Load Based Multiplier = Total MISO Demand in State / Total 2008 MISO Peak Demand