Energy Business Solutions Michigan IRP Working Group Meeting July 25, 2005.
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Transcript of 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
Energy Business SolutionsProprietary and Confidential
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
Energy Business SolutionsProprietary and Confidential
External Energy Modeling
NY/NE
IMO
PJMEPJM
W
MI
PJMS
SERC
FRCC
SPP
MISOECAR
MISOMAIN
PJMCOM
MISOMAPP
NONMISOMAPP
Energy Business SolutionsProprietary and Confidential
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%
Energy Business SolutionsProprietary and Confidential
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
Energy Business SolutionsProprietary and Confidential
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
Energy Business SolutionsProprietary and Confidential
“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
Energy Business SolutionsProprietary and Confidential
Resource Mix by Region
0%
10%
20%
30%
40%
50%
60%
70%
80%
METC ITC U.P.
Base Load
Midrange
Peaking
Energy Business SolutionsProprietary and Confidential
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%
Energy Business SolutionsProprietary and Confidential
2006 Unit Capacity Factors: ITC
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecCombined Cycle 22% 20% 13% 19% 15% 20% 27% 26% 16% 17% 14% 16%
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%
Hydro 63% 65% 69% 68% 64% 59% 54% 52% 53% 56% 61% 64%Pumped Storage 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%
Energy Business SolutionsProprietary and Confidential
2006 Unit Capacity Factors: Upper Peninsula
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecCombined Cycle 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
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%
Hydro 67% 67% 68% 79% 80% 71% 63% 60% 60% 63% 69% 70%Pumped Storage 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%
Energy Business SolutionsProprietary and Confidential
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
Energy Business SolutionsProprietary and Confidential
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
Energy Business SolutionsProprietary and Confidential
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
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Expansion Plan
Energy Business SolutionsProprietary and Confidential
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
Energy Business SolutionsProprietary and Confidential
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
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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
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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 (%)
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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
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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
Energy Business SolutionsProprietary and Confidential
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
Energy Business SolutionsProprietary and Confidential
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
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