energy business solutions michigan irp working group meeting july 25, 2005

Energy Business Solutions

Michigan IRP Working Group Meeting

July 25, 2005

Energy Business SolutionsProprietary and Confidential

Agenda

Introduction (Proudfoot) Suggested Time Mgt. External Market Modeling (Adkins) 20 Minutes

Energy Equilibrium Methodology Preliminary Results

Michigan Model Representation (Gaskill) 30 Minutes 2006 System Summary External Market Flows

Preliminary Expansion Plan (Hughes) 45 Minutes Proview Methodology Review Options Bridge for study reserve margins Preliminary Plan review External Market influence

LOL Analysis for the UP (Konidena) 25 Minutes


External Market Modeling

MAPP

MAAC

Ontario

Upper Peninsula

ITC

METC

MAIN

TVA VACAR

TN

TN

TN

3000 MW

600 MW3350 MW

2850 MW0** MW

O*MW

350 MW350 MW

350 MW

3200 MW3050 MW

2900 MW

2800 MW


External Energy Modeling

NY/NE

IMO

PJMEPJM

W

MI

PJMS

SERC

FRCC

SPP

MISOECAR

MISOMAIN

PJMCOM

MISOMAPP

NONMISOMAPP


2006 Price Curve for Michigan

On-Peak average price 43.15 $/Mwh (55.19 $/MWh in July)

Off-Peak average price is 31.38 $/MWh

Approximate escalation 2006 to 2024 is 5.5%


Base Case Representation

Simplified External Market Model Current Resource Mix 2006 Base Case Results

Unit Capacity Factors Economy Imports/Exports Seasonal Summary Report

Current Load and Resources


Base Case Transfer Capability

MAPP

MAAC

Ontario

Upper Peninsula

ITC

METC

MAIN

TVA VACAR

TN

TN

TN

3000 MW

600 MW3350 MW

2850 MW0** MW

O*MW

350 MW350 MW

350 MW

3200 MW3050 MW

2900 MW

2800 MW


“Simplified” External Market Model

Ontario

Upper Peninsula

ITC

METCMarket Price West

Market Price South

TN

3000 MW

600 MW3350 MW

2850 MW0** MW

O*MW

350 MW


Resource Mix by Region

0%

10%

20%

30%

40%

50%

60%

70%

80%

METC ITC U.P.

Base Load

Midrange

Peaking


2006 Unit Capacity Factors: METC

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecCombined Cycle 18% 17% 16% 20% 22% 27% 33% 30% 23% 17% 16% 16%

CT Gas 0% 0% 0% 0% 0% 0% 1% 1% 0% 0% 0% 0%

CT Oil 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Interruptible 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Landfill 70% 70% 69% 69% 69% 71% 72% 71% 70% 69% 69% 70%

Nuclear 90% 90% 90% 90% 90% 90% 90% 90% 90% 90% 90% 90%

Coal 82% 80% 77% 77% 79% 84% 88% 87% 82% 78% 78% 80%

St Gas 0% 0% 0% 0% 0% 0% 1% 1% 0% 0% 0% 0%

St Oil 0% 0% 0% 0% 0% 2% 5% 4% 1% 0% 0% 0%

Other 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Hydro 34% 35% 45% 54% 47% 40% 33% 31% 34% 34% 36% 37%Pumped Storage 3% 1% 1% 2% 6% 5% 8% 5% 7% 1% 2% 2%

Alt. Generation 99% 99% 99% 99% 99% 99% 100% 100% 100% 100% 100% 100%

Avg CF 33% 32% 31% 32% 34% 36% 40% 38% 35% 32% 31% 32%


2006 Unit Capacity Factors: ITC


CT Gas 0% 0% 0% 1% 1% 2% 3% 3% 1% 1% 1% 1%

CT Oil 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Interruptible 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Landfill 91% 90% 90% 89% 90% 93% 94% 94% 92% 90% 90% 91%

Nuclear 90% 90% 44% 0% 17% 90% 90% 90% 90% 90% 90% 90%

Coal 81% 79% 78% 77% 76% 81% 85% 83% 78% 77% 77% 79%

St Gas 2% 2% 1% 3% 3% 6% 11% 10% 4% 4% 2% 2%

St Oil 6% 5% 1% 1% 1% 2% 5% 4% 1% 1% 1% 2%

Other 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%


Alt Generation 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Avg CF 56% 54% 49% 45% 47% 57% 60% 59% 55% 54% 53% 54%


2006 Unit Capacity Factors: Upper Peninsula


CT Gas 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

CT Oil 4% 4% 2% 1% 2% 4% 6% 5% 3% 2% 2% 3%

Interruptible 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Landfill 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Nuclear 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Coal 71% 70% 65% 60% 66% 71% 78% 79% 71% 67% 67% 70%

St Gas 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

St Oil 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Other 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%


Alt Generation 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Avg CF 50% 49% 46% 45% 48% 51% 54% 54% 49% 47% 47% 50%


System Economy Transfer

-

200

400

600

800

1,000

1,200

1,400

1,600

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

GW

h Economy Purchase

Economy Sales


2006 Seasonal Summary

ANNUAL Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecENERGY REQUIREMENTS GWH 116,622 10,215 8,986 9,525 8,950 9,240 10,129 11,370 10,766 9,568 9,416 8,939 9,518 THERMAL GENERATION GWH 100,891 8,825 7,733 7,926 7,356 7,818 8,757 9,687 9,437 8,383 8,347 8,034 8,589 HYDRO ENERGY GWH 1,361 115 104 129 140 132 112 100 95 95 105 114 120 PUMPED STORAGE GENERATION GWH 568 37 10 17 20 80 61 112 73 88 18 26 26 PUMPED STORAGE PUMPING GWH -812 -53 -15 -25 -29 -115 -87 -160 -104 -126 -25 -36 -37NET TRANSACTION ENERGY GWH 14,613 1,292 1,152 1,477 1,463 1,324 1,286 1,632 1,265 1,129 972 802 821 EMERGENCY ENERGY GWH 0 0 0 - 0 0 0 0 0 - 0 0 0

PEAK DEMAND MW 24,188 18,575 16,900 16,230 15,796 17,688 23,384 22,694 24,188 22,061 17,122 17,028 17,850 INSTALLED CAPACITY MW 27,185 27,847 27,847 27,685 27,360 27,032 27,197 27,185 27,185 27,024 27,347 27,672 27,833 RESERVE MARGIN PERCENT % 12.39 49.91 64.77 70.58 73.21 52.83 16.31 19.79 12.39 22.49 59.72 62.51 55.93

ECONOMY PURCHASE ENERGY GWH 14,524 1,265 1,112 1,406 1,369 1,264 1,243 1,538 1,300 1,090 1,113 911 914 ECONOMY PURCHASE COST $000 626,835 60,055 48,885 52,346 56,143 56,556 54,196 71,519 62,507 48,200 44,073 34,289 38,066 ECONOMY SALES ENERGY GWH 1,086 76 52 31 2 38 51 4 132 55 241 208 196 ECONOMY SALES COST $000 34,507 2,352 1,602 890 67 1,203 2,336 344 4,705 1,749 7,175 6,150 5,935

TOTAL THERMAL COST $000 2,612,997 226,683 199,325 206,777 199,121 208,983 227,179 257,124 248,230 213,313 208,913 201,549 215,800 TOTAL HYDRO COST $000 16,361 1,447 1,252 1,409 1,390 1,409 1,338 1,357 1,350 1,311 1,367 1,342 1,390 NET TRANSACTION COST $000 596,190 58,041 47,611 51,795 56,397 55,663 52,167 71,483 58,109 46,756 37,222 28,475 32,472 TOTAL EMISSIONS COST $000 365,160 22,142 19,357 20,867 19,917 41,950 43,026 47,676 46,388 41,348 20,829 20,096 21,564 TOTAL SYSTEM COST $000 3,591,432 308,312 267,592 280,904 276,880 308,081 323,780 377,731 354,155 302,806 268,387 251,518 271,285

AVERAGE ENERGY COST $/MWH 30.10 30.18 29.78 29.49 30.94 33.34 31.97 33.22 32.90 31.65 28.50 28.14 28.50AVERAGE MARGINAL COST $/MWH 36.23 39.14 37.11 31.82 35.86 38.73 41.42 46.50 44.87 38.64 33.04 31.37 33.31


Existing Loads & Resources

Units' 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014PEAK DEMAND "MW" 23,541 24,188 24,777 25,352 25,923 26,503 27,084 27,678 28,298 28,936 INSTALLED CAPACITY "MW" 27,197 27,185 27,185 27,185 27,185 27,185 27,185 27,185 27,185 27,185 RESERVE MARGIN PERCENT "%" 15.53 12.39 9.72 7.23 4.87 2.57 0.37 -1.78 -3.93 -6.05

Forecasted 15% RM Level "MW" 27,072 27,816 28,494 29,155 29,811 30,478 31,146 31,830 32,542 33,277 Capacity Needed to 15% RM "MW" (125) 631 1,309 1,970 2,626 3,293 3,961 4,645 5,357 6,092

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023

MW

PEAK DEMANDINSTALLED CAPACITYCapacity Needed to 15% RMForecasted 15% RM Level


Expansion Plan


Screening Curves

Technology Screening CurvesBase Case

$0

$50

$100

$150

$200

$250

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Capacity Factor

$/m

Wh

PC - SubPC - SuperFluid BedIGCCPC - SubNuclearCCCT


PROVIEW Methodology

For each year of the optimization PROVIEW generates all possible combinations of alternatives

Each combination is tested against the constraints for that year and only those combinations that meet all the constraints are passed; these are the feasible states

Cumulative Capital and operations costs are calculated for each feasible state

Feasible states from year X are the starting points for generating new combinations for year X+1

Repeat to end of Optimization Horizon


PROVIEW Methodology

The State Space Problem 9 Alternatives:

3 available in 2007 (the CT’s) 3 more in 2008 (the CC’s) 3 more in 2011 (coal)

Resultant potential states:

Problem: only have a limitedavailable State Space!

=2 ^ n ^ # of years2007 8 2008 72 2009 576 2010 4,608 2011 36,872 2012 294,976 2013 2,359,808 2014 18,878,464 2015 151,027,712 2016 1,208,221,696 2017 9,665,773,568 2018 77,326,188,544 2019 618,609,508,352 2020 4,948,876,066,816 2021 39,591,008,534,528 2022 316,728,068,276,224 2023 2,533,824,546,209,790 2024 20,270,596,369,678,300


Limiting the Solution State Space

Constrain the problem such that the resulting set of solution states will fit in the available State Space, but not unduly limit those solutions

Reserve Margins: Company and System Wide

Do not allow “extra” units not needed to meet Reserve Margin minimums Split off the Upper Peninsula since it is not directly connected with the

Lower Peninsula, AND it has a capacity surplus through 2018 (i.e. – greater that 15% reserves)

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015System 14.9% 11.7% 9.5% 9.8% 10.3% 11.0% 12.0% 13.0% 14.0% 15.0% 15.0%METC 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0%ITC 0.0% -2.0% -1.0% 0.0% 1.0% 2.5% 4.0% 6.0% 8.0% 10.0% 10.0%UP 15.0% 15.0% 15.0% 15.0% 15.0% 15.0% 15.0% 15.0% 15.0% 15.0% 15.0%

Minimum Reserve Margin (%)

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015System 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0%METC 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0% 25.0%ITC 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0%UP 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Maximum Reserve Margin (%)


Iterative Solution

“Fix” the solution for the UP: 1 CT in 2019 Require that LP meet the “system” minimum reserve margin of 15% from

2014 on Only CT’s and CC’s are available from 2007/2008 through 2010, so “lock

in” a plan from 2007 through 2010: 2007 – 2 CT’s in ITC 2008 – 1 CT and 1 CC in ITC 2009 – 1 CC in METC and 1 in ITC 2010 – 1 CT in METC, 1 CT and 1 CC in ITC

Re-optimize through 2019 and temporarily “lock in” the best plan from this run

Next, optimize for 2020 to 2024 to find a “back fill” plan for capacity needs at the end of the time horizon, “lock in” this plan for 2020 to 2024

Re-open the constraints for 2011 through 2019 and run full optimization for this period


Preliminary Base Case Plan – Lower Peninsula

PV (k$ 2005) = $ 58,754,232

METC CT ITC CT METC CC ITC CC METC COAL ITC COAL2007 22008 1 12009 1 1 12010 1 12011 1 1 12012 1 1 12013 1 12014 1 1 12015 1 1 12016 1 1 12017 1 12018 1 1 12019 1 12020 12021 1 12022 12023 1 1 12024 1 1 1


Preliminary Base Case Plan

Annual System Reserve Margins

-5

0

5

10

15

20

25

3020

05

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

Perc

ent (

%) Prelim Plan

15% Target

METC

ITC


External Market influence

Economy Interchange

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

GW

H

ECON ENERGY PURCH ECON ENERGY SALES


Headings Arial Bold 20 ptContent Text Arial 18 pt

Yellow

Orange

RGB 255/208/0RGB 255/227/66RGB 255/239/98RGB 255/247/129RGB 255/249/163

RGB 246/96/20RGB 251/114/46RGB 254/134/78RGB 254/156/105RGB 255/183/144

Blue

GreyRGB 24/21/18RGB 90/87/87

RGB 168/166/166RGB 207/207/207

RGB 139/137/137

RGB 0/59/127RGB 0/58/154

RGB 88/170/218RGB 172/210/237

RGB 27/136/195

Green

RedRGB 212/13/22RGB 230/38/39

RGB 242/115/119RGB 249/170/178

RGB 237/79/77

RGB 0/129/49RGB 3/141/71

RGB 94/179/135RGB 151/205/174

RGB 41/159/101

energy business solutions michigan irp working group meeting july 25, 2005

Documents