Economic Market Potential for Electric Utility Use of Distributed Generation
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Transcript of Economic Market Potential for Electric Utility Use of Distributed Generation
Distributed Utility Associates
Economic Market Potential for Electric Utility Use
of Distributed Generation
For
The Edison Electric Institute
June 20, 2001
By
Joe Iannucci(925) 447-0604 [email protected]
EEI_DG_2001_Results
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Agenda
• Introduction
• Methodology Overview
• Assumptions: Utility and DG
• DG Economic Market Potential
• Observations and Conclusions
• R&D Needs and Opportunities
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Utility Economics lower cost of servicebetter asset utilization improved operationSubstation and feeder locations
G, T, D,FUEL
g,fuel,
customer services
DUVal
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Utility Avoided Cost “Value Mountain” Illustration
Peak Load @ Feeder, 2002, Base Case Fuel Prices
0
5
10
15
20
25
30
61 71 81 91 101 111 121 131
Avoided Cost ($/kW-yr)
Fre
qu
ency
of
Occ
urr
ence
(of
a g
iven
co
st)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Eco
no
mic M
arket P
oten
tial (% o
f MW
)
Avoided Cost Frequency
Portion of MW (Market)DR Cost -> Economic Market Potential
Economic Economic Market Market
PotentialPotentialDR CostDR Cost
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Peak Load and Load Growth,Load “In-play”
• TECHNICAL Potential = Load Growth
• NERC Load GROWTH Projections
• Increase “Direct” Load Growth to account for Load Diversity multiply by 1.6, approximate ratio of end-of-line transformer capacity (kVA* power factor)
central load (kW)
• 2002: 21,822 MW 2010: 22,205 MW
EEI_DG_2001_Results
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DG Hours of Operation
• Peak Load: 200 Hours/year
• Base Load: 5,256 hours/year– load factor .6
EEI_DG_2001_Results
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DG Fuel Price Assumptions
• Base Case– relatively flat gas and coal prices
• High Fuel Cost Case– gas price based on futures price, Feb 2001– assume coal prices “track” gas prices
• Natural Gas Volume-based Prices@ Substation: Wholesale On-site: Retail
• Transportation Charges per EIA/NEMS, added to Commodity Prices
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Fuel Cost Case Location 2002 2010Base Case Industrial/Substation 3.515 3.613
Commercial/Feeder 5.691 5.749
High Price Industrial/Substation 6.565 7.096Commercial/Feeder 8.919 9.306
DG Natural Gas Prices Assumed
• DG Natural Gas Prices Assumed
• Forward Averaged
• Diesel Fuel: EIA Retail Price Forecast
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Peak Load Electricity Cost Assumptions
• “blend” of common peaking resources’ + capacity cost + O&M + fuel cost
Fuel Cost CaseBase High
Low 38.1 40.0Mean 44.3 48.1
Max 53.4 60.8
Peak Electricity Cost, 2002, Summary ($/kW-yr)
Fuel Cost CaseBase High
Low 38.4 40.0Mean 44.4 48.8
Max 53.7 62.0
Peak Electricity Cost, 2010, Summary ($/kW-yr)
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Baseload Electric Energy Cost Assumptions
• Base Case and High Case Fuel Cost Cases
• “Blend” of combined cycle gas and coal.
• Annual Cost $/kW-yrBase Case Scenario High Fuel Price Scenario
2002 2010 2002 2010CostElement CC Coal CC Coal CC Coal CC Coal
Capital 65.5 171.6 58.5 168.1 65.5 171.6 58.5 168.1
O&M 10.5 23.6 10.5 23.6 10.5 23.6 10.5 23.6
Fuel 153.9 43.3 139.1 36.1 287.4 80.8 273.1 71.0
Total 229.9 238.5 208.1 227.9 363.4 276.1 342.1 262.7
Mean 234.2 218.0 319.8 302.4
lowmean
high
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Utility T&D Capacity Cost Assumptions
• FERC Form 1 T&D Budgets
• Load Growth per NERC Forecasts
• Statistical Spread Derived Assuming Mean Values of:
$/kW-year
Transmission $12.1
Distribution $41.9
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Other Utility Assumptions• Value-of service & “Reliability Benefits”
– applies at feeder locations • assume cause for 99% of outages beyond substation
• outage losses “avoided”
– outage rate .029% * 8760 = 2.5 hours per year– Value of service (unserved energy) $3/kWh– TOTAL: 2.5 hours * $3/kWh = $7.50/kW-year
• T&D Losses – affects fuel use and grid capacity needs
average: 4% on-peak: 7%
~ 8% of total!
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Peaking Distributed Generators’ Cost and Performance
2002
Distributed Installed CostHeatRate
VariableO&M
Generator Type $/kW $/kW-yr* Btu/kWh $/kWh
Microturbine 400 60.00 12,000 .01
ATS 525 78.75 8,985 .006
Combustion Turbine 400 60.00 10,500 .01
Dual Fuel Engine 450 67.50 8,600 .02
Otto/Spark Engine 425 63.75 9,700 .025
Diesel Engine 410 61.50 7,800 .025
* Utility fixed charge rate of 0.15 is assumed.
2010
Distributed Installed CostHeatRate
VariableO&M
Generator Type $/kW $/kW-yr* Btu/kWh $/kWh
Microturbine 400 60.00 12,000 .01
ATS 525 78.75 8,985 .006
Combustion Turbine 400 60.00 10,500 .01
Dual Fuel Engine 450 67.50 8,600 .02
Otto/Spark Engine 425 63.75 9,700 .025
Diesel Engine 410 61.50 7,800 .025
* Utility fixed charge rate of 0.15 is assumed.
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Baseload Distributed Generators’ Cost and Performance
2010
2002
Distributed Installed CostHeatRate
VariableO&M
Generator Type $/kW $/kW-yr* Btu/kWh $/kWh
Microturbine 575 86.25 12,000 .01
ATS 550 82.50 8,985 .006
Combustion Turbine 540 81.00 11,450 .009
Dual Fuel Engine 525 78.75 8,700 .02
Conventional Fuel Cell 1,720 258.00 8,530 .015
Advanced Fuel Cell 1,000 150.00 9,500 .022
* Utility fixed charge rate of 0.15 is assumed.
Distributed Installed CostHeatRate
VariableO&M
Generator Type $/kW $/kW-yr* Btu/kWh $/kWh
Microturbine 475 71.25 11,500 .01
ATS 525 78.75 8,985 .006
Combustion Turbine 500 75.00 11,150 .008
Dual Fuel Engine 475 71.25 8,500 .018
Conventional Fuel Cell 1,100 165.00 8,000 .01
Advanced Fuel Cell 500 75.00 7,200 .008
* Utility fixed charge rate of 0.15 is assumed.
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Economic Market Potential Estimates, Peak 2002
Base Case Fuel Prices
High Fuel Prices
Peaking DG Economic Market Potential, Base Case Fuel Price, 2002
16,000
17,000
18,000
19,000
20,000
21,000
22,000
Mic
rotu
rbin
e
ATS
Con
vent
iona
l CT
Dua
l Fue
led
Otto
/Spa
rk
Die
sel
MW
Peaking DG Economic Market Potential, High Fuel Price, 2002
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
Mic
rotu
rbin
e
ATS
Con
vent
iona
l CT
Dua
l Fue
led
Otto
/Spa
rk
Die
sel
MW
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Economic Market Potential Estimates, Peak 2010
High Fuel Cost
Base Case Fuel CostPeaking DG Economic Market Potential,
Base Case Fuel Price, 2010
0
5,000
10,000
15,000
20,000
25,000
Mic
rotu
rbin
e
ATS
Con
vent
iona
l CT
Dua
l Fue
led
Otto
/Spa
rk
Die
sel
MW
Peaking DG Economic Market Potential, High Fuel Price, 2010
0
5,000
10,000
15,000
20,000
25,000
Mic
rotu
rbin
e
ATS
Con
vent
iona
l CT
Dua
l Fue
led
Otto
/Spa
rk
Die
sel
MW
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Value Mountain 2002 Peaker, Feeder Location
Peak Load @ Feeder, 2002, Base Case Fuel Prices
0
5
10
15
20
25
30
61 71 81 91 101 111 121 131
Avoided Cost ($/kW-yr)
Fre
qu
ency
of
Occ
urr
ence
(o
f a
giv
en c
ost
)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Eco
no
mic M
arket P
oten
tial (% o
f MW
)
Avoided Cost Frequency
Portion of MW (Market)
EEI_DG_2001_Results
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Observations and Conclusions Peaker DGs
• very competitive with respect to total annual cost to serve new load as capacity resources
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Value Mountain 2002 Baseload, Feeder Location
Baseload @ Feeder, Base, 2002, Base Case Fuel Prices
0
5
10
15
20
25
30
261 271 281 291 301 311 321 331
Avoided Cost ($/kW-yr)
Fre
qu
ency
of
Occ
urr
ence
(o
f a
giv
en c
ost
)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Eco
no
mic M
arket P
oten
tial (% o
f MW
)
Avoided Cost Frequency
Portion of MW (Market)
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Results, Baseload• Markets are essentially zero with two
important exceptions.
• ATS all at sub (low cost gas), base case fuel price
only
2002: ~29% 2010: <3%
• Advanced Fuel Cell all at sub (low cost gas), 2010 only
2010 base case fuel prices: 68.3%
2010 high fuel prices: 4.1%
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Baseload DGs: Observations• Difficult for even superior DGs to compete
with grid as utility-owned energy resource, especially with regard to– production cost / wholesale price of electricity– capacity cost for new central generation
• Conversely: Viability Very Sensitive to Fuel Price and Efficiency
• “Low cost,” efficient fuel cells can compete for “small” portion of load growth
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Baseload DGs: Conclusions
• May need one or more of the following– more run hours– DGs with even lower cost than expected– DGs with even higher efficiency than expected– CHP benefits– Aggregated/Bulk Purchases of Gas
• to reduce fuel cost for feeder/customer locations
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Caveats and Considerations
• “Economic Market Potential”– based purely on direct cost-effectiveness for
meeting load growth– based on utility annual (avoided) cost ($/kW-year)
– without regard to institutional challenges
• Estimates made assuming that technologies are commercially viable and readily available.
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Caveats and Considerations
• Baseload and Peaking duty cycles evaluated in isolation.
• Each DG evaluated individually– without regard to substitutes
(i.e., other types of distributed generation, storage, or geographically targeted DSM)
• Assumed fuel access and availability.
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Implementation Issuesor, if it’s so good why isn’t it happening?
EXCEPTION:increasing use of DGs for “supply” benefits…
…limited regard to “local” benefits (T&D)…
...for now?
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Implementation Issuesor, if it’s so good why isn’t it happening?
• Complexity – versus planning of “conventional” option:
Fuel + G + T + D
• Not Standard Engineering Practice
• Insufficient Evaluation Tools– engineering – financial
• Insufficient Data
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Implementation Issuesor, if it’s so good why isn’t it happening?
• Financials– utility-owned DGs -- financing and rules?– lease or rent DGs -- strains modest utility
expense budgets (especially distribution)– benefits sharing arrangements/partnerships?
• Intra-utility Discontinuities– overlapping / divergent missions– uncertain incentives
• Emissions Issues
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R&D Needs and Opportunities• Utility Markets Topics
– Plant Capital Cost Sensitivities– Regional Analysis– Activate Customer-owned Backup Generators
as Utility Resource– Intermediate Load DG Operation, i.e.,
• Peak/capacity DG’s seem great
• difficult for baseload/energy DG’s to compete
– Air Emissions Implications
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R&D Needs and Opportunities• Customer Perspective Market Potential
– Bill Reduction
• Customer Perspective, segments– commercial – institutional– industrial – IT operations
• DR Options– CHP
–Targeted Demand Management
– Storage
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Customer Economics
lower energy billbetter service--quality, reliability
Comparing Central to DU Solutions
Bill and Benefits Comparison
Purchasingpower
cost and benefits ofDG options
DUVal-C
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Institutional Customer Bill Analysis Results Summary
2002
DG Type B/CEconomic
Run-Hours B/CEconomic
Run-Hours B/CEconomic
Run-Hours
Microturbine 1.294 3,465 .615 881 .594 599Microturbine
CHP1.472 7,778 .856 7,828 .79 5,234
Diesel .985 1,914 .708 881 .653 599ATS-cogen 1.311 7,778 .898 7,828 .725 2,782Gas Spark 1.196 3,465 .684 881 .654 599
Fuel Cell .619 3,465 .228 881 .206 599
2010
DG Type B/CEconomic
Run-Hours B/CEconomic
Run-Hours B/CEconomic
Run-Hours
Microturbine 1.434 3,465 .716 881 .699 599Microturbine
CHP1.575 7,778 .916 7,828 .856 5,234
Diesel 1.006 3,465 .712 881 .662 599ATS-cogen 1.378 7,778 .913 7,828 .758 2,782Gas Spark 1.249 3,465 .707 881 .665 599
Fuel Cell 1.063 3,465 .611 2,403 .403 599
Region 3
Region 1 Region 2 Region 3
Region 1 Region 2
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Diesel Gensets, Cost Versus B/C Ratio
Installed Cost versus Benefit Cost Ratio, for Diesel Gensets
.6
.7
.8
.9
1.0
1.1
1.2
1.3
1.4
1.5
1.6
50 100 150 200 250 300 350 400Installed Cost ($/kW)
B/C
Ra
tio
PG&E-599 Hours
SDG&E-1,913 Hours
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Customer Bill Reduction Potential (Economic Benefits)
Technology
Operation Hours Per
YearTotal B/C
Ratio
Incremental Savings ($/kW-yr)
Total Savings ($/kW-yr)
Incremental Savings
($Milion/yr)Total Savings ($Million/yr)
Microturbine 3,465 1.29 208.42 83.70 1,955 785
Microturbine w/CHP
7,778 1.47 343.17 168.56 3,219 1,581
Diesel 1,914 0.99 85.30 -3.63 800 -34ATS w/CHP 7,778 1.31 272.33 124.84 2,554 1,171
Gas Spark 3,465 1.20 163.38 60.35 1,532 566Fuel Cell 3,465 0.62 180.70 -227.05 1,695 -2,130
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Customer Bill Analysis with Resulting DG Air Emissions
Operation Portion of Total % Change, Relative to In-state, Average Central Generation Only
TechnologyHours Per
YearEnergy
From DGB/C
Ratio NOx SOx CO CO2 PM VOC
Microturbine 3,465 44.5% 1.29 +346% +13% +648% +210% -12% +44%Micro
turbine 7,778 100.0% 1.47 +398% +29% +970% -117% -74% -294%
Diesel 1,914 24.6% .99 +3,032% +5,819% +1,341% +173% +590% +2,433%
ATS w/CHP 7,778 100.0% 1.31 +376% +2% +1,017% -47% -75% -214%
Gas Spark 3,465 44.5% 1.2 +1,095% -23% +1,933% +165% +141% +4,405%
Fuel Cell 3,465 44.5% .62 -45% -45% -45% +134% -45% -45%
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Emissions Due to Cost-effective Utility Use of DG
2010 Load Growth (MW/yr): 1,144 Tons of Emissions (000 tons CO2)
Peaking DG OptionPortion of Growth NOx SOx CO CO2 VOCs PM
System Only 100% 15 2 238 24 2 13
Microturbine 75.3% 90 2 278 101 4 10
ATS 70.3% 89 2 280 83 3 9
Conventional CT 79.0% 104 3 170 100 4 10
Dual Fueled Engine 52.0% 602 7 1,897 63 61 25
Otto/Spark Engine 54.5% 169 2 607 71 95 1,890
Diesel Engine 74.8% 1,457 26 2,625 151 172 260
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DG Gas Price Details
Commodity ($/MMBtu)
Transportation ($/MMBtu)
Price($/MMBtu)
Industrial/Substation Base Case 2002 2.727 .787 3.5152010 2.821 .792 3.613
High Price 2002 5.741 .824 6.5652010 6.268 .828 7.096
Commercial/Feeder Base Case 2002 2.727 2.963 5.6912010 2.821 2.928 5.749
High Price 2002 5.741 3.178 8.9192010 6.268 3.038 9.306
* 2002 values = average of 2002 - 2020 prices
** 2010 values = average of 2010 - 2020 prices
*** Base Case values from AE2001, $1999
**** High Price Case based on Futures Prices, Walls Street Journal. Feb 28, 2001.
Price Escalation based on growth rate in EIA AE2000 for High Gas Case.
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Peaking Generation Cost Details Year 2002
Base Case Total Cost
Variable Cost Fixed Cost Total Total Cost
Capacity Type
HeatRate
(Btu/kWh)
FuelPrice
($/MMBtu)
FuelCost
(¢/kWh)O&M
(¢/kWh) (¢/kWh) ($/kW-yr) (¢/kWh) ($/kW-yr) (¢/kWh) ($/kW-yr)
Upgrade Emergency Generators 12,000 9.0 10.8 3.0 13.8 27.6 9.0 18.0 22.8 45.6Refurbish Old CT - gas 13,000 3.5 4.6 2.5 7.1 14.1 12.0 24.0 19.1 38.1
New Utility Peaker CT - gas 12,000 3.5 4.2 1.5 5.7 11.4 21.0 42.0 26.7 53.4Purchase Capacity - gas -- 3.5 0.0 -- -- 20.0 40.0 20.0 40.0
Annual Hours of operation = 200
Fixed Charge Rate = .1200
High Fuel Cost Case Total Cost
Variable Cost Fixed Cost Total Total Cost
Capacity Type
HeatRate
(Btu/kWh)
FuelPrice
($/MMBtu)
FuelCost
(¢/kWh)O&M
(¢/kWh) (¢/kWh) ($/kW-yr) (¢/kWh) ($/kW-yr) (¢/kWh) ($/kW-yr)
Upgrade Emergency Generators 12,000 9.0 10.8 3.0 13.8 27.6 9.0 18.0 22.8 45.6Refurbish Old CT - gas 13,000 6.6 8.5 2.5 11.0 22.1 12.0 24.0 23.0 46.1
New Utility Peaker CT - gas 12,000 6.6 7.9 1.5 9.4 18.8 21.0 42.0 30.4 60.8Purchase Capacity - gas -- 6.6 0.0 -- -- -- 20.0 40.0 20.0 40.0
Annual Hours of operation = 200
Fixed Charge Rate = .1200
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Peaking Generation Cost Details Year 2010
Base Fuel Cost Case Total Cost
Variable Cost Fixed Cost Total Total Cost
Capacity Type
HeatRate
(Btu/kWh)
FuelPrice
($/MMBtu)
FuelCost
(¢/kWh)O&M
(¢/kWh) (¢/kWh) ($/kW-yr) (¢/kWh) ($/kW-yr) (¢/kWh) ($/kW-yr)
Upgrade Emergency Generators 12,000 9.0 10.8 3.0 13.8 27.6 9.0 18.0 22.8 45.6Refurbish Old CT - gas 13,000 3.6 4.7 2.5 7.2 14.4 12.0 24.0 19.2 38.4
New Utility Peaker CT - gas 12,000 3.6 4.3 1.5 5.8 11.7 21.0 42.0 26.8 53.7Purchase Capacity -- 3.6 0.0 -- -- -- 20.0 40.0 20.0 40.0
Annual Hours of operation = 200
Fixed Charge Rate = .1200
High Fuel Cost Case Total Cost
Variable Cost Fixed Cost Total Total Cost
Capacity Type
HeatRate
(Btu/kWh)
FuelPrice
($/MMBtu)
FuelCost
(¢/kWh)O&M
(¢/kWh) (¢/kWh) ($/kW-yr) (¢/kWh) ($/kW-yr) (¢/kWh) ($/kW-yr)
Upgrade Emergency Generators 12,000 9.0 10.8 3.0 13.8 27.6 9.0 18.0 22.8 45.6Refurbish Old CT - gas 13,000 7.1 9.2 2.5 11.7 23.5 12.0 24.0 23.7 47.5
New Utility Peaker CT - gas 12,000 7.1 8.5 1.5 10.0 20.0 21.0 42.0 31.0 62.0Purchase Capacity -- 7.1 0.0 -- -- -- 20.0 40.0 20.0 40.0
Annual Hours of operation = 200
Fixed Charge Rate = .1200
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T&D Cost Calculations Details
Item 1997 1998 1999 AverageIOU T All Years ($000) 63,800,198 66,932,701 68,542,040
Budget ($000) 1,875,926 2,118,026 2,311,942 2,101,965IOU D All Years ($000) 158,485,763 169,539,790 179,702,556
Budget ($000) 9,358,122 9,423,258 10,385,483 9,722,287
Load (MW) 637,677 660,293 681,449 659,806
Load Growth (MW) 20,000 21,000 22,000 21,000T Estimated* Capacity Added 24,000 25,200 26,400 25,200T Incremental Cost*** $/kW 102.8 110.6 115.2 109.6
$/kW-yr 11.3 12.2 12.7 12.1D Estimated** Capacity Added 32,000 33,600 35,200 33,600
D Incremental Cost*** $/kW 384.8 369.0 388.2 380.7$/kW-yr 42.3 40.6 42.7 41.9
• Load Diversity Factors
T = 1.2 D = 1.6 • Fixed Charge Rates
T = .1100 D = .1100
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Economic Market Potential Estimates Details Year 2002
High Fuel Cost
2002 Mkt Size: 21,822 MWBaseload Peakload
Technology System @ Sub @ Feeder Technology System @ Sub @ FeederMicroturbine 99.7% 0.2% 0.1% Microturbine 16.6% 0.0% 83.4%
ATS 41.0% 58.7% 0.3% ATS 1.3% 0.0% 98.7%Conventional CT 99.3% 0.6% 0.1% Conventional CT 15.4% 0.0% 84.6%Dual Fuel Engine 99.3% 0.5% 0.2% Dual Fuel Engine 13.2% 0.0% 86.8%
Fuel Cell 100.0% 0.0% 0.0%Spark Engine (Natural Gas) 4.8% 0.0% 95.2%Advanced Fuel Cell 100.0% 0.0% 0.0% Diesel 4.9% 0.0% 95.1%
Base Case Fuel Cost
2002 Mkt Size: 21,822 MWBaseload Peakload
Technology System @ Sub @ Feeder Technology System @ Sub @ FeederMicroturbine 99.8% 0.0% 0.2% Microturbine 61.0% 0.0% 39.0%
ATS 99.5% 0.3% 0.2% ATS 16.4% 0.0% 83.6%Conventional CT 99.8% 0.0% 0.2% Conventional CT 58.5% 0.0% 41.5%Dual Fuel Engine 99.8% 0.0% 0.2% Dual Fuel Engine 51.1% 0.0% 48.9%
Fuel Cell 100.0% 0.0% 0.0%Spark Engine (Natural Gas) 33.6% 0.0% 66.4%Advanced Fuel Cell 100.0% 0.0% 0.0% Diesel 16.6% 0.0% 83.4%
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Economic Market Potential Estimates Details Year 2010
High Fuel Cost
Base Case Fuel Cost
2010 Mkt Size: 22,205 MWBaseload Peakload
Technology System @ Sub @ Feeder Technology System @ Sub @ FeederMicroturbine 99.9% 0.0% 0.1% Microturbine 23.2% 0.0% 76.8%
ATS 99.9% 0.0% 0.1% ATS 10.0% 0.0% 90.0%Conventional CT 99.9% 0.0% 0.1% Conventional CT 15.9% 0.0% 84.1%Dual Fuel Engine 99.9% 0.0% 0.1% Dual Fuel Engine 31.8% 0.0% 68.2%
Fuel Cell 100.0% 0.0% 0.0%Spark Engine (Natural Gas) 29.7% 0.0% 70.3%Advanced Fuel Cell 95.7% 4.1% 0.2% Diesel 13.6% 0.0% 86.4%
2010 Mkt Size: 22,205 MWBaseload Peakload
Technology System @ Sub @ Feeder Technology System @ Sub @ FeederMicroturbine 99.8% 0.0% 0.2% Microturbine 11.4% 0.0% 88.6%
ATS 97.3% 2.4% 0.3% ATS 4.4% 0.0% 95.6%Conventional CT 99.6% 0.2% 0.2% Conventional CT 7.6% 0.0% 92.4%Dual Fuel Engine 99.8% 0.2% 0.0% Dual Fuel Engine 27.1% 0.0% 72.9%
Fuel Cell 100.0% 0.0% 0.0% Spark Engine (Natura 23.0% 0.0% 77.0%Advanced Fuel Cell 31.4% 68.3% 0.3% Diesel 25.0% 0.0% 75.0%