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Wind and Other Renewable Assumptions in EPA’s 2008 IPM Base Case
Elliot Lieberman and Serpil Kayin Clean Air Markets Division U.S. EPA Office of Air and Radiation NWCC Environmental Costs and Benefits Workshop October 8, 2008
Outline of Presentation Key Assumptions for Potential (New) Renewable Capacity in IPM • Wind – Cost, performance, and penetration assumptions – Potential wind resource base – Capacity credits
• Cost and performance assumptions for – – – –
Solar Geothermal Landfill gas Biomass (standalone and co-firing)
• Tax incentives for renewables • Renewable portfolio standards • Issues for future consideration
What is IPM • The Integrated Planning Model (IPM) is a long-term capacity expansion and production costing model for analyzing the electric power sector • It is a multi-regional, deterministic, dynamic linear programming model • IPM finds the least-cost solution to meeting electricity demand subject to environmental, transmission, fuel, reserve margin, and other system operating constraints • Developed by ICF International and populated with assumptions specified by each client • Used by U.S. EPA to project the impact of emission policies on the U.S. electric power sector
Wind Generation Assumptions
4
Cost, Performance and Penetration Assumptions for Potential Wind Technology The EPA Base Case explicitly models onshore wind units. Off shore wind units are not modeled. The wind technology assumptions modeled in the EPA Base Case are primarily based on AEO 2008. The wind resources are categorized into 3 wind classes, 4, 5 and 6; and 5 cost classes ranging from 1 (least expensive) to 5 (most expensive). Wind generation profile assumptions that specify hourly generation patterns for a representative day by region, season and wind class are based on AEO 2008. These generation profiles define the dispatch of these units. The EPA Base Case includes a wind penetration constraint for each model region, which restricts each region’s total wind generation up to 20 percent of total generation. Base cost assumptions for new (potential) wind generation: Cost Parameter Capital Cost (2006$/kW)
1,707
Fixed O&M Cost (2006$/kW-yr)
29.48
Variable O&M Cost (2006$/MWh)
0.0 5
Potential Wind Resource Base The assumptions regarding the wind resource base were obtained from PERI (Princeton Economic Research Inc.). The table below shows the wind resource base modeled by NEMS region in the EPA Base Case. Available Wind Resource Incremental Capacity (MW) in Each Cost Multiplier Step NEMS Region
1X
1.2X
1.5X
2X
3X
Total
484
484
329
329
310
1,934
5,054
9,999
5,118
3,803
6,132
30,107
MAAC
245
245
167
167
157
981
MAIN
980
980
667
667
627
3,922
MAPP
6,068
76,443
265,185
526,490
1,066,530
1,940,716
913
913
621
621
585
3,654
1,804
2,556
1,482
1,482
1,395
8,720
Florida
0
0
0
0
0
0
SERC
870
870
592
592
557
3,482
SPP
6,423
42,468
89,049
207,712
421,577
767,229
NWP
11,271
41,997
36,824
199,846
405,747
695,685
RA
2,934
9,009
3,718
55,892
11,0581
182,135
California
6,404
6,404
4,355
4355
4,099
25,616
Total
43,452
192,369
408,107
1,001,955
2,018,297
3,664,180
ECAR ERCOT
New York New England
6
Wind Technology – Capacity Credit
For intermittent technologies such as wind and solar units, their contribution towards regional reserve margin requirements is less than 100%. The reserve margin contribution for such technologies is estimated based on a unit’s generation profile.
First, the hourly load for the model region is sorted in descending order (highest to lowest). Next, the average generation, derived from the generation profile, for the top 30% of the hours is calculated.
The resulting value, expressed as a percent of the unit’s rated output capacity is used as the reserve margin contribution/ capacity credit for the unit. The table below shows the national average reserve margins by wind class, modeled in the EPA Base Case.
Wind Class
Reserve Margin Contribution (%)
Wind Class 4
32
Wind Class 5
39
Wind Class 6
46
7
Solar Generation Assumptions
8
Cost and Performance Assumptions for Potential Solar Technology Modeled in EPA Base Case The EPA Base Case models two types of solar technologies: Solar Thermal and Solar Photovoltaic. The cost characteristics for the potential solar technologies are obtained from EIA’s AEO 2008 and are shown in the table below. Capital Costs (2006$ /kW)
FOM Costs (2006$ /kW)
VOM Costs (mills /kWh)
Solar PV
4,915
11.37
0
Solar Thermal
3,004
55.24
0
Solar generation profile assumptions that specify hourly generation patterns for a representative day by region and season are based on AEO 2008. These generation profiles define the dispatch of these units. 9
Geothermal Generation Assumptions
10
Performance and Unit Cost Assumptions for Geothermal Technologies Geothermal technology assumptions in the EPA Base Case are site specific and are based on EIA’s AEO 2008. There are 88 sites in total. The ranges of the site specific assumptions are summarized below.
Technology
Heat Rate (Btu /kWh)
Capital Costs (2006$ /kW)
FOM Costs (2006$ /kW-yr)
VOM Costs (mills /kWh)
Total Capacity (MW)
Geothermal
29,660 – 397,035
1,049 – 13,352
147 - 212
0
8,963
11
Landfill Gas Generation Assumptions
12
Cost Performance and Assumptions for Landfill Gas Technology Potential landfill gas technology assumptions are obtained from AEO 2008. The potential is divided into 3 categories: High, Low and Very Low methane producing landfills.
Heat Rate (Btu /kWh)
Capital Costs (2006$ /kW)
FOM Costs (2006$ /kW)
VOM Costs (mills /kWh)
Resources (MW)
Landfill Gas (High)
13,648
1,799
111
0.01
653
Landfill Gas (Low)
13,648
2,266
111
0.01
581
Landfill Gas (Very Low)
13,648
3,489
111
0.01
3,819
13
Biomass Generation Assumptions
14
Biomass Technologies Modeled in EPA Base Case Heat Rate (Btu /kWh)
Capital Costs (2006$ /kW)
FOM Costs (2006$ /kW)
VOM Costs (mills /kWh)
Conventional Direct Fired Boiler (before 2020)
13,500
3,000
83.0
11.3
Advanced BGCC (2020- )
9,800
2,600
47.0
8.6
The EPA Base Case 2008 models Two types of standalone biomass technologies: • •
Biomass conventional direct fired boiler (prior to 2020) Biomass gasification combined cycle (from 2020 onward)
Biomass co-firing in coal fired units • •
Cost characteristics shown in adjacent table Limited to maximum of
•10% of a coal unit’s net capacity coming from biomass and • 50 MW of such capacity at any given facility
The biomass supply curves used in the EPA Base Case are obtained from AEO 2008.
Biomass Cofiring Assumptions Boiler Type
All
Plant Size (MW)
600
Biomass Cofiring Size (MW)
50
Capital Cost (2006$/kW1)
178
Fixed O&M Cost (2006$/kW)
7.4
Maximum Biomass Co-firing Rate possible
10% / 50MW at a facility
1Per
kW of biomass power
15
Tax Incentives for Renewable Technologies
16
Tax Incentives for Renewable Technologies
Technology
Production Tax Credits (PTC)1
Investment Tax Credits (ITC)
Depreciation
Wind
-
-
5 year MACRS2
Solar - PV
-
10%
5 year MACRS
Solar - Thermal
-
10%
5 year MACRS
Geothermal
-
10%
5 year MACRS
Landfill
-
-
5 year MACRS
Biomass
-
-
5 year MACRS
1No
PTC is assumed in EPA Base Case 2008 since the first year modeled is 2012 and existing PTC provisions expire prior to 2012. 2Modified Accelerated Cost Recovery System 17
Renewable Portfolio Standards
18
State Renewable Portfolio Standards Renewable portfolio standards (RPS) require utilities to use renewable energy or renewable energy credits (RECs) to account for a certain percentage of their retail electricity sales – or a certain amount of generating capacity – within a specified timeframe. More than half of all U.S. states have established a RPS. The level of RPS requirements and the technologies applicable to meet the RPS requirements vary by state. The RPS assumptions in the EPA Base Case are based on AEO 2008.
19
Assumptions for Renewable Portfolio Standards (RPS) by NEMS Region Year
2012
NEMS Region
2015
2020
2025
2030
% of Generation Unless Otherwise Indicated
ERCOT
3.9
5.0
5.0
5.0
5.0
MAAC
7.3
9.4
13.1
13.3
13.3
MAIN
3.7
5.7
8.9
12.1
12.1
MAPP
6.2
8.5
10.0
11.1
11.1
New England
6.8
8.3
11.1
11.5
11.5
SERC
0.5
0.9
1.7
1.9
1.9
NWP
4.1
6.6
11.4
12.3
12.3
RA
3.0
4.2
6.0
6.9
6.9
CNV
0.0
12.0
11.0
10.0
10.0
4,745
5,461
5,615
5,660
5,793
New York 1
Source: Table 75. Aggregate Regional RPS Requirements http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/renewable.pdf 1. Figures represent GWh.
20
Issues for Future Consideration
21
Issues for Future Consideration Modeling wind classes 3 and 7. Modeling offshore wind. Revising methodology for estimating capacity credits for intermittent technologies such as wind and solar. Re-evaluating capital cost assumptions for renewable (and conventional) generating technologies in view of escalating costs in the current market.
22
Elliot Lieberman and Serpil Kayin Clean Air Markets Division U.S. EPA Office of Air and Radiation NWCC Environmental Costs and Benefits Workshop October 8, 2008
Outline of Presentation Key Assumptions for Potential (New) Renewable Capacity in IPM • Wind – Cost, performance, and penetration assumptions – Potential wind resource base – Capacity credits
• Cost and performance assumptions for – – – –
Solar Geothermal Landfill gas Biomass (standalone and co-firing)
• Tax incentives for renewables • Renewable portfolio standards • Issues for future consideration
What is IPM • The Integrated Planning Model (IPM) is a long-term capacity expansion and production costing model for analyzing the electric power sector • It is a multi-regional, deterministic, dynamic linear programming model • IPM finds the least-cost solution to meeting electricity demand subject to environmental, transmission, fuel, reserve margin, and other system operating constraints • Developed by ICF International and populated with assumptions specified by each client • Used by U.S. EPA to project the impact of emission policies on the U.S. electric power sector
Wind Generation Assumptions
4
Cost, Performance and Penetration Assumptions for Potential Wind Technology The EPA Base Case explicitly models onshore wind units. Off shore wind units are not modeled. The wind technology assumptions modeled in the EPA Base Case are primarily based on AEO 2008. The wind resources are categorized into 3 wind classes, 4, 5 and 6; and 5 cost classes ranging from 1 (least expensive) to 5 (most expensive). Wind generation profile assumptions that specify hourly generation patterns for a representative day by region, season and wind class are based on AEO 2008. These generation profiles define the dispatch of these units. The EPA Base Case includes a wind penetration constraint for each model region, which restricts each region’s total wind generation up to 20 percent of total generation. Base cost assumptions for new (potential) wind generation: Cost Parameter Capital Cost (2006$/kW)
1,707
Fixed O&M Cost (2006$/kW-yr)
29.48
Variable O&M Cost (2006$/MWh)
0.0 5
Potential Wind Resource Base The assumptions regarding the wind resource base were obtained from PERI (Princeton Economic Research Inc.). The table below shows the wind resource base modeled by NEMS region in the EPA Base Case. Available Wind Resource Incremental Capacity (MW) in Each Cost Multiplier Step NEMS Region
1X
1.2X
1.5X
2X
3X
Total
484
484
329
329
310
1,934
5,054
9,999
5,118
3,803
6,132
30,107
MAAC
245
245
167
167
157
981
MAIN
980
980
667
667
627
3,922
MAPP
6,068
76,443
265,185
526,490
1,066,530
1,940,716
913
913
621
621
585
3,654
1,804
2,556
1,482
1,482
1,395
8,720
Florida
0
0
0
0
0
0
SERC
870
870
592
592
557
3,482
SPP
6,423
42,468
89,049
207,712
421,577
767,229
NWP
11,271
41,997
36,824
199,846
405,747
695,685
RA
2,934
9,009
3,718
55,892
11,0581
182,135
California
6,404
6,404
4,355
4355
4,099
25,616
Total
43,452
192,369
408,107
1,001,955
2,018,297
3,664,180
ECAR ERCOT
New York New England
6
Wind Technology – Capacity Credit
For intermittent technologies such as wind and solar units, their contribution towards regional reserve margin requirements is less than 100%. The reserve margin contribution for such technologies is estimated based on a unit’s generation profile.
First, the hourly load for the model region is sorted in descending order (highest to lowest). Next, the average generation, derived from the generation profile, for the top 30% of the hours is calculated.
The resulting value, expressed as a percent of the unit’s rated output capacity is used as the reserve margin contribution/ capacity credit for the unit. The table below shows the national average reserve margins by wind class, modeled in the EPA Base Case.
Wind Class
Reserve Margin Contribution (%)
Wind Class 4
32
Wind Class 5
39
Wind Class 6
46
7
Solar Generation Assumptions
8
Cost and Performance Assumptions for Potential Solar Technology Modeled in EPA Base Case The EPA Base Case models two types of solar technologies: Solar Thermal and Solar Photovoltaic. The cost characteristics for the potential solar technologies are obtained from EIA’s AEO 2008 and are shown in the table below. Capital Costs (2006$ /kW)
FOM Costs (2006$ /kW)
VOM Costs (mills /kWh)
Solar PV
4,915
11.37
0
Solar Thermal
3,004
55.24
0
Solar generation profile assumptions that specify hourly generation patterns for a representative day by region and season are based on AEO 2008. These generation profiles define the dispatch of these units. 9
Geothermal Generation Assumptions
10
Performance and Unit Cost Assumptions for Geothermal Technologies Geothermal technology assumptions in the EPA Base Case are site specific and are based on EIA’s AEO 2008. There are 88 sites in total. The ranges of the site specific assumptions are summarized below.
Technology
Heat Rate (Btu /kWh)
Capital Costs (2006$ /kW)
FOM Costs (2006$ /kW-yr)
VOM Costs (mills /kWh)
Total Capacity (MW)
Geothermal
29,660 – 397,035
1,049 – 13,352
147 - 212
0
8,963
11
Landfill Gas Generation Assumptions
12
Cost Performance and Assumptions for Landfill Gas Technology Potential landfill gas technology assumptions are obtained from AEO 2008. The potential is divided into 3 categories: High, Low and Very Low methane producing landfills.
Heat Rate (Btu /kWh)
Capital Costs (2006$ /kW)
FOM Costs (2006$ /kW)
VOM Costs (mills /kWh)
Resources (MW)
Landfill Gas (High)
13,648
1,799
111
0.01
653
Landfill Gas (Low)
13,648
2,266
111
0.01
581
Landfill Gas (Very Low)
13,648
3,489
111
0.01
3,819
13
Biomass Generation Assumptions
14
Biomass Technologies Modeled in EPA Base Case Heat Rate (Btu /kWh)
Capital Costs (2006$ /kW)
FOM Costs (2006$ /kW)
VOM Costs (mills /kWh)
Conventional Direct Fired Boiler (before 2020)
13,500
3,000
83.0
11.3
Advanced BGCC (2020- )
9,800
2,600
47.0
8.6
The EPA Base Case 2008 models Two types of standalone biomass technologies: • •
Biomass conventional direct fired boiler (prior to 2020) Biomass gasification combined cycle (from 2020 onward)
Biomass co-firing in coal fired units • •
Cost characteristics shown in adjacent table Limited to maximum of
•10% of a coal unit’s net capacity coming from biomass and • 50 MW of such capacity at any given facility
The biomass supply curves used in the EPA Base Case are obtained from AEO 2008.
Biomass Cofiring Assumptions Boiler Type
All
Plant Size (MW)
600
Biomass Cofiring Size (MW)
50
Capital Cost (2006$/kW1)
178
Fixed O&M Cost (2006$/kW)
7.4
Maximum Biomass Co-firing Rate possible
10% / 50MW at a facility
1Per
kW of biomass power
15
Tax Incentives for Renewable Technologies
16
Tax Incentives for Renewable Technologies
Technology
Production Tax Credits (PTC)1
Investment Tax Credits (ITC)
Depreciation
Wind
-
-
5 year MACRS2
Solar - PV
-
10%
5 year MACRS
Solar - Thermal
-
10%
5 year MACRS
Geothermal
-
10%
5 year MACRS
Landfill
-
-
5 year MACRS
Biomass
-
-
5 year MACRS
1No
PTC is assumed in EPA Base Case 2008 since the first year modeled is 2012 and existing PTC provisions expire prior to 2012. 2Modified Accelerated Cost Recovery System 17
Renewable Portfolio Standards
18
State Renewable Portfolio Standards Renewable portfolio standards (RPS) require utilities to use renewable energy or renewable energy credits (RECs) to account for a certain percentage of their retail electricity sales – or a certain amount of generating capacity – within a specified timeframe. More than half of all U.S. states have established a RPS. The level of RPS requirements and the technologies applicable to meet the RPS requirements vary by state. The RPS assumptions in the EPA Base Case are based on AEO 2008.
19
Assumptions for Renewable Portfolio Standards (RPS) by NEMS Region Year
2012
NEMS Region
2015
2020
2025
2030
% of Generation Unless Otherwise Indicated
ERCOT
3.9
5.0
5.0
5.0
5.0
MAAC
7.3
9.4
13.1
13.3
13.3
MAIN
3.7
5.7
8.9
12.1
12.1
MAPP
6.2
8.5
10.0
11.1
11.1
New England
6.8
8.3
11.1
11.5
11.5
SERC
0.5
0.9
1.7
1.9
1.9
NWP
4.1
6.6
11.4
12.3
12.3
RA
3.0
4.2
6.0
6.9
6.9
CNV
0.0
12.0
11.0
10.0
10.0
4,745
5,461
5,615
5,660
5,793
New York 1
Source: Table 75. Aggregate Regional RPS Requirements http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/renewable.pdf 1. Figures represent GWh.
20
Issues for Future Consideration
21
Issues for Future Consideration Modeling wind classes 3 and 7. Modeling offshore wind. Revising methodology for estimating capacity credits for intermittent technologies such as wind and solar. Re-evaluating capital cost assumptions for renewable (and conventional) generating technologies in view of escalating costs in the current market.
22
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