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WECC Capital Cost Recommendations. June 4, 2012. Arne Olson, Partner Nick Schlag, Consultant Gabe Kwok, Associate. History. In 2009, E3 provided WECC with recommendations for capital costs of new electric generation technologies to use in its 10-year study cycles - PowerPoint PPT Presentation
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WECC Capital Cost Recommendations
June 4, 2012
Arne Olson, Partner
Nick Schlag, Consultant
Gabe Kwok, Associate
History
In 2009, E3 provided WECC with recommendations for capital costs of new electric generation technologies to use in its 10-year study cycles
• Prior to this effort, the relative costs of WECC’s study cases could only be compared on a variable-cost basis (using PROMOD results)
• This effort provided WECC with a framework to quantify relative scenario costs on a basis reflecting their actual prospective costs to ratepayers by combining variable & fixed costs
In 2011, WECC asked E3 to review the capital costs to ensure continued accuracy
• Due to the continued evolution of solar PV technologies, E3 lowered its estimates of photovoltaic capital costs
2
Total Cost
Variable Costs(PROMOD)
Fixed Costs(E3 Capital Cost Tool)= +
Background
In the midst of its 10- and 20-year study plans, WECC has asked E3 to provide guidance on resource cost and performance to use in those studies
These capital costs will serve as inputs to the 10- and 20-year studies:
• Including capital costs in the 10-year study cycles enables comparisons of total costs between scenarios
• Capital costs will serve as an input to the 20-year study’s LTPT, allowing for the development of robust scenarios through cost minimization
3
Updates
E3 presented its initial recommendations to stakeholders on May 15, 2012
Based on stakeholder feedback and comments, E3 has reviewed its recommendations for wind and solar costs
Minor revisions were made to several of the present day solar PV costs to better capture expected cost differentials between system types and sizes
E3 has revised some of the data inputs used to forecast of cost declines for solar PV and solar thermal technologies:
• Forecasts of installed capacity for solar PV and solar thermal have been revised to account for near-term projections of global market dynamics
• Learning rate for solar thermal has been adjusted to reflect greater potential for technological improvements than originally anticipated
Modeling Framework
5
Capital Costs(E3 Capital Cost
Tool)
2022 S
tud
y2032 S
tud
y
Resource Performance
(NREL)
Resource Performance
(WREZ)
PROMOD
LTPT/NXT
Resource Portfolio
Capital Costs(E3 Capital Cost
Tool)
Total Scenario Costs
Resource Portfolio
Total Scenario
Cost
Scope of Updates
E3’s Capital Cost Tool considers a broad range of potential new generation technologies
The scope for E3’s update is divided into two phases:
• Near term (integrated in this year’s study cycle): update costs for wind and solar technologies
• Long term (integrated into subsequent study cycles): review costs for all technologies
This division prioritizes updating those costs that are most likely to have changed given the limited time before the start of this study cycle
6
Technology Subtypes
Biomass
Biogas Landfill, Other
Gas CT
Gas CCGT
CHP Small, Large
Coal Steam, IGCC
Nuclear
Hydro Small, Large, Upgrade
Solar PV Fixed Tilt, Tracking
Solar Thermal No Storage, 6hrs Storage
Wind Onshore
Technologies in E3’s Capital Cost Tool
Technologies Covered
E3’s current update encompasses the following technologies—an expanded set compared to the original Capital Cost Tool
7
Solar PV
Large Utility (20 MW +)
• Fixed Tilt
• Tracking
Solar Thermal Wind
No Storage
6hrs StorageOnshore
Small Utility (1-20 MW)
• Fixed Tilt
• Tracking
Rooftop
• Commercial
• Residential
Mod
ele
d
in P
rior
WEC
C
Stu
die
s
New
to T
his
Year’
s
Stu
dy C
ycle New technology characterizations
are needed to represent increasing specificity of photovoltaic resources modeled by WECC, especially in the High DG/DSM Case
Approach
1. Determine the cost to install a power plant today (2012)
• Given limited time, focus is on wind and solar technologies
• Prior recommendations for other technologies are carried forward
2. Use learning curves to forecast declines in technology capital costs over the next two decades
3. Determine the appropriate applicability of federal tax incentives for renewable technologies over the 10- and 20-year study cycles
4. Develop and apply updated regional multipliers to capture geographic variations in resource costs around the WECC
8
Notes on Resource Performance
With the limited time available before the commencement of the present study cycles, E3’s present scope of work focuses on updating resource costs
WECC staff is developing assumptions on resource performance for use in the current study cycle
Over a longer timeframe, E3 will work with WECC to ensure that cost and performance assumptions are consistent with one another and represent our best expectations of future development patterns
9
Present Day Wind and Solar Costs
Present-Day Costs
To derive estimates of present-day wind and solar costs, E3 has reviewed a wide range of recent studies and publications
For developing technologies, precise capital costs are a moving target that are difficult to pin down
• A review of literature provides both…
• …outdated forecasts of what costs would be today; and
• …retrospective analysis of actual costs from several years ago
E3 has used this information to develop its best estimates of costs to install wind and solar plants in 2012
All costs are expressed in 2010 dollars
11
Historical Trends in Solar PV Costs
Installed solar PV costs continue to decrease:
• Average U.S. behind-the-meter PV data from 1998-2010 (Left)
• California Solar Initiative (CSI) data from 2009-2011 (right)
• CSI is focused on rooftop PV
Less data available for utility-scale PV and solar thermal
12
Tracking the Sun IV: An Historical Summary of the Installed Cost of Photovoltaics in the United States from 1998 to 2010
California Solar Statistics
Current Trends in Solar PV Prices
13
Market data and experience have shown substantial movement in PV prices over the past two years, suggesting we are on a relatively steep portion of the “learning curve.” This makes identifying current prices a challenging exercise.
Source: Technical Potential for Local Distributed Photovoltaics in California
Historical Trends in Wind Costs
Average 2010 installed cost was similar to 2009
142010 Wind Technologies Market Report (June 2011)
Data Sources
15
Author Report NamePublication
DateInstallation
YearHistorical
or Forward
CPUC 33% RPS Calculator Update May 2012 2012 Forward
E3/CPUC Technical Potential for Local Distributed Photovoltaics in California
Mar. 2012 2009 – 2020 Both
B&V/NREL Cost and Performance Data for Power Generation Technologies Feb. 2012 2010 - 2050 Both
NREL Residential, Commercial, and Utility-Scale Photovoltaic (PV) System Prices in the United States: Current Drivers and Cost-Reduction Opportunities
Feb. 2012 2010 Historical
DOE SunShot Vision Study Feb. 2012 2010 – 2020 Both
CSI California Solar Statistics Jan. 2012 2009 - 2011 Historical
LBNL Tracking the Sun IV: An Historical Summary of the Installed Cost of Photovoltaics in the United States from 1998 to 2010
Sept. 2011 2010 Historical
LBNL 2010 Wind Technologies Report June 2011 2010 Historical
Lazard Levelized Cost of Energy Analysis – Version 5.0 June 2011 2012 Forward
Sandia Power Tower Technology Roadmap and Cost Reduction Plan April 2011 2013 Forward
EIAUpdated Capital Cost Estimates for Electricity Generation Plants (for AEO2011)
Nov. 2010 2011 Forward
NWPCC Sixth Northwest Conservation and Electric Power Plan Feb. 2010 2010 Forward
CECComparative Costs of California Central Station Electricity Generation
Jan. 2010 2010 Forward
Solar PV – Fixed Utility (20 MW+)
TEPPC 2011
Current Update
16
AuthorCost
($/kWDC)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
RETI 2B $3,230 2010 20 Thin Film
LTPP $3,400 2010
EIA $3,963 2011 180
TEPPC 2011 $3,400 2012 100
AuthorCost
($/kWDC)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
B&V/NREL $2,396 2015 100
NREL $3,800 2010 187.5
CPUC $2,380 2012 150 California
Recommended
$2,550 $117 2012 100
Capital costs for solar PV technologies shown here are expressed relative to the DC nameplate rating. To convert to an AC capital cost, these costs should be multiplied by 1.18 (assuming DC-AC conversion of 85%).
Solar PV – Tracking Utility (20 MW+)
TEPPC 2011
Current Update
17
AuthorCost
($/kWDC)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
NWPCC $7,294 2008 25 Crystalline
RETI 2B $3,825 2010 20 Crystalline
LTPP $3,995 2010
CEC $4,626 2010 25
TEPPC 2011 $3,995 2012 100
AuthorCost
($/kWDC)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
B&V/NREL $2,664 2015 100
NREL $4,400 2010 187.5
CPUC $2,800 2012 150 California
Recommended
$2,800 $123 2012 100
Capital costs shown relative to DC nameplate rating
Solar PV – Fixed Utility (1-20 MW)
Technology has not been represented in past WECC modeling efforts
18
AuthorCost
($/kWDC)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
EIA $5,042 2011 8.4
B&V/NREL $2,877 - $3,538 2010 1 - 10
B&V/NREL $2,593 - $3,233 2015 1 - 10
CPUC $2,590 - $2,730 2012 5 - 20 California
Lazard $2,750 2012 10 Crystalline
Recommended
$2,975 $135 2012 1 - 20
Capital costs shown relative to DC nameplate rating
Solar PV – Tracking Utility (1-20 MW)
Technology has not been represented in past WECC modeling efforts
19
AuthorCost
($/kWDC)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
B&V/NREL $3,142 - $3,844 2010 1 - 10
B&V/NREL $2,827 - $3,477 2015 1 - 10
CPUC $3,325 2012 1 - 5
Lazard $3,500 2012 10 Crystalline
Recommended
$3,225 $138 2012 1 - 20
Capital costs shown relative to DC nameplate rating
Solar PV - Commercial
Technology has not been represented in past WECC modeling efforts
20
AuthorCost
($/kWDC)
Generic LCOE
($/MWh)
Installation Vintage
Size(kW)
Notes
LBNL $5,800 2010 100 – 500
NREL $4,590 2010 217
CSI $5,622 2011 56 California
B&V/NREL $4,870 2010 100
B&V/NREL $3,904 2015 100
Recommended
$5,000 $256 2012
Capital costs shown relative to DC nameplate rating
Solar PV - Residential
Technology has not been represented in past WECC modeling efforts
21
AuthorCost
($/kWDC)
Generic LCOE
($/MWh)
Installation Vintage
Size(kW)
Notes
LBNL $6,600 2010 5 – 10
NREL $5,710 2010 4.9
CSI $6,472 2011 5.5 California
B&V/NREL $6,050 2010 4
B&V/NREL $4,413 2015 4
Recommended
$6,000 $301 2012 <10
Capital costs shown relative to DC nameplate rating
Solar Thermal – Without Storage
TEPPC 2011
Current Update
22
AuthorCost
($/kW)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
NWPCC $4,761 2008 100 Trough
CEC COG $3,687 2010 250 Trough; California
RETI 2B $5,350 - $5,550 Trough; California
LTPP $5,300 Trough; California
EIA $4,714 2011 100 Trough; Wet-cooled
EIA $4,692 2011 100 Tower; Wet-cooled
TEPPC 2011 $5,350 2012
AuthorCost
($/kW)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
B&V/NREL $4,992 2010 200 Trough
B&V/NREL $4,799 2015 200 Trough
DOE SunShot $4,500 2010 100 Trough; Wet-cooled
Lazard $5,000 - $5,400 2012 250 TroughRecommended
$4,900 $187 2012
Solar Thermal – With Storage
TEPPC 2011
Current Update
23
AuthorCost
($/kW)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
RETI 2B $7,650 - $7,850 California
LTPP $7,500 California
TEPPC 2011 $7,500
AuthorCost
($/kW)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
B&V/NREL $7,178 2010 200 Trough, 6hrs
B&V/NREL $6,914 2015 200 Trough, 6hrs
DOE SunShot $7,870 2015 250 Trough, 6hrs
Lazard $6,300 - $6,500 2012 250 Trough, 3hrs
B&V/NREL $7,158 2010 200 Tower, 6hrs
Sandia $7,427 2013 100 Tower, 9 hrs
DOE SunShot $5,940 2015 100 Tower, 6 hrs
Recommended $7,100 $199 2012 Generic, 6 hrs
Wind
TEPPC 2011
Current Update
24
AuthorCost
($/kW)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
NWPCC $2,127 2008 100 NW
RETI 2B $2,150 - $2,600 CA
LTPP $2,350 CA
EIA $2,438 2011 100
TEPPC 2011 $2,350
AuthorCost
($/kW)
Generic LCOE
($/MWh)
Installation Vintage
Size(MW)
Notes
CEC COG $2,023 2010 50 CA
LBNL $2,148 2009-2010 US
B&V/NREL $2,013 2010
Lazard $1,300 - $1,900 2012 100
Recommended $2,000 $63 2012
Recommended Resource Costs
Technology
Subtype
DC Capital
Cost ($/kWDC)
AC Capital
Cost($/kW)
Generic AC Capacity
Factor (%)
Generic LCOE
($/MWh)
Solar PV
Fixed (>20 MW) $2,550 $3,000 27% $117
Tracking (>20 MW) $2,800 $3,300 29% $123
Fixed (1-20 MW) $2,975 $3,500 27% $135
Tracking (1-20MW) $3,225 $3,800 29% $138
Comm Roof $5,000 $5,900 23% $256
Res Roof $6,000 $7,100 23% $301
Solar Thermal
No Storage n/a $4,900 28% $187
6hr storage n/a $7,100 36% $199
Wind Onshore n/a $2,000 37% $63
25
Cost Summary (2010 $)
Capital costs for solar PV are converted from DC to AC by multiplying by 1.18 (assuming DC-AC conversion of 85%).
Comparison of Updated Costs to Prior Recommendations
WECC 2011 2012 Update
Technology SubtypeGeneric AC Capacity
Factor (%)
AC Capital Cost ($/kW)
Generic LCOE
($/MWh)
AC Capital Cost
($/kW)
Generic LCOE
($/MWh)
Solar PV
Fixed (>20 MW) 27% $4,000 $150 $3,000 $117
Tracking (>20 MW) 29% $4,700 $164 $3,300 $122
Fixed (1-20 MW) 27% n/a n/a $3,500 $135
Tracking (1-20MW) 29% n/a n/a $3,800 $138
Comm Roof 23% n/a n/a $5,900 $256
Res Roof 23% n/a n/a $7,100 $301
Solar Thermal
No Storage 28% $5,350 $200 $4,900 $187
6hr storage 36% $7,500 $208 $7,100 $199
Wind Onshore 37% $2,350 $75 $2,000 $63
26
Cost Summary (2010 $)
Forecasting Future Costs for Wind and Solar
Considerations in Forecasting Technology Cost
Technology cost changes
• As nascent technologies become increasingly mature, they may experience cost declines as a result of learning by doing and increased scale of manufacturing
• Technology costs are sensitive to other factors as well:
• Trends in the costs of raw materials
• Relationship of supply and demand
Tax credit expiration
• ITC for solar technologies is set to expire in 2017
• PTC for wind expires in 2013; for other technologies in 2012
Learning curves describe an observed empirical relationship between the cumulative experience in the production of a good and the cost to produce it
• Increased experience leads to lower costs due to efficiency gains in the production process
• The functional form for the learning curve is empirically derived and does not have a direct theoretical foundation
Learning Curve Theory
The learning rate (LR) is used to describe the expected decrease in costs with a doubling of experience
29
2x
2x-20%
-20%Pr
ice
Cumulative Experience
Example: 20% Learning Rate
The theory of learning curves in economics was formalized by Kenneth Arrow in 1962 in “The Economic Implications of Learning by Doing”. This empirical relationship has since been affirmed in a number of works that span many sectors of the economy.
Learning Curves and Solar PV
Declines in solar PV module price have tracked the functional form of the learning curve with a learning rate of approximately 20% since 1976
30Source: Global Overview on Grid-Parity Event Dynamics (Breyer and Gerlach)
Past performance does not indicate future potentialRecent cost reductions have not followed the longer-term trends of historical learning
Learning Curves and Solar PV
Module costs represent only a fraction of solar PV system costs; total system costs have historically declined at a slightly lower learning rate (~17%)
31Source: Navigant Consulting
2010 2012 2014 2016 2018 2020
Inst
alle
d PV
Cos
t Historical Trend Pessimistic Path
Optimistic Path
Uncertainty in Future Costs
32
Past trends do not guarantee future declines, and other factors influence technology costs
Optimistic Path
Solar PV continues to reap benefits of a high learning rate
Global installed capacity grows rapidly
Pessimistic Path
Today’s low prices caused by excess supply followed by a rebound as markets re-equilibrate
Cost of raw materials rise
Int’l markets saturate and US growth slows as the ITC expires
Uncertainty in Global Installed Capacity
Future growth of solar PV can vary widely, as shown by the IEA’s 2010 Energy Technology Perspectives scenarios
• IEA BLUE, High Renewables: renewables serve 75% of load in 2050
• IEA BLUE Map: global CO2 emissions reduced to half of 2005 levels
• IEA Baseline: business-as-usual; no new policies affect energy sector
33
40300
1,700
3,000
0
500
1,000
1,500
2,000
2,500
3,000
3,500
Existing, 2010 Baseline BLUE MAP BLUE HighRenewables
IEA Projections, 2050
Glo
bal I
nsta
lled
Capa
city
(GW
)
Solar PV
Sensitivity of Learning Curves to Global Installations Forecast
The choice of a forecast of future installations has a significant impact on anticipated future cost declines
The impact of an additional MW of capacity declines as the cumulative installed capacity increases
34
Forecast declines based on a 10% learning rate
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
2012 2017 2022 2027 2032 2037
Glo
bal I
nsta
lled
Sola
r PV
Cap
acity
(G
W)
65%
71%
90%
0%
20%
40%
60%
80%
100%
120%
140%
2012 2017 2022 2027 2032 2037
Sola
r PV
Capi
tal C
ost (
% o
f 20
12)
IEA BLUE, High Renewables IEA BLUE Map IEA Baseline
Near-Term Outlook for Solar PV
E3 has reviewed additional predictions of trends in global installed capacity for solar PV
The European Photovoltaic Industry Association’s Global Market Outlook predicts between 208 and 343 GW of solar PV by 2016
35
0
50
100
150
200
250
300
350
400
2004 2006 2008 2010 2012 2014 2016
Sola
r PV
Glo
bal I
nsta
lled
Capa
city
(GW
)
EPIA Moderate
EPIA Policy Driven
Historical
Policy Driven Scenario: continuation of support mechanisms (FiTs) and strong political favor for solar PV
Moderate Scenario: pessimistic market behavior, reduced policy support for PV development
Forecasting Solar PV Global Installations Through 2032
Short-term market outlook is generally consistent with IEA’s long-term vision
The average trajectory of the EPIA’s forecasts results in approximately 1,000 GW of solar globally by 2030
• E3 uses the average of the EPIA-derived long-term forecasts to forecast cost reductions for solar PV
36
0
200
400
600
800
1,000
1,200
1,400
2010 2014 2018 2022 2026 2030
Sola
r PV
Glo
bal I
nsta
lled
Capa
city
(GW
)
EPIA Moderate
EPIA Policy Driven
Historical
EPIA Moderate (Extrap)
EPIA Policy Driven (Extrap)
IEA 2050 BLUE Map (Linear)
Avg of EPIA-Derived Forecasts
Solar PV Learning Rate Recommendation
E3 recommends a learning rate of 10% for solar PV, which is applied to the entire capital cost (not just modules)
No guarantee that historical rates (17%) will continue
• Learning rates for mature technologies (coal & gas) have decreased with technology maturation
• As balance-of-systems components begin to represent larger shares of system costs, learning rates are likely to decrease
37
Coupled with the EPIA-derived long-term PV forecast, this learning rate yields the following estimates of long-term cost reductions
-16%-23% -27% -29%
0%
20%
40%
60%
80%
100%
120%
2012 2017 2022 2027 2032
Sola
r The
rmal
Cap
ital C
ost s
(% o
f 201
2)
Comparison of Recommended PV Costs to Other Sources
38
$0
$2,000
$4,000
$6,000
$8,000
2008 2012 2016 2020 2024 2028 2032 2036
$/kW
-DC
Res Roof PVE3 LDPV (20% LR)
E3 LDPV (0% LR)
B&V/NREL
CSI Data
NREL Benchmark
NREL Evolutionary
DOE Sunshot
LBNL
E3/WECC
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
2008 2012 2016 2020 2024 2028 2032 2036
$/kW
-DC
Large Ground PV - Fixed Tilt
B&V/NREL
NREL Benchmark
NREL Evolutionary
DOE Sunshot
CPUC RPS Calc
E3/WECC
$0
$2,000
$4,000
$6,000
$8,000
2008 2012 2016 2020 2024 2028 2032 2036
$/kW
-DC
Comm Roof PVE3 LDPV (20% LR)
E3 LDPV (0% LR)
B&V/NREL
CSI Data
NREL Benchmark
NREL Evolutionary
DOE Sunshot
LBNL
E3/WECC
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
2008 2012 2016 2020 2024 2028 2032 2036
$/kW
-DC
Small Ground PV - Fixed Tilt
E3 LDPV (20% LR)
E3 LDPV (0% LR)
B&V/NREL
NREL Benchmark
NREL Evolutionary
DOE Sunshot
CPUC RPS Calc
E3/WECC
51
0
50
100
150
200
250
2010 2014 2018 2022 2026 2030Sola
r The
rmal
Glo
bal I
nsta
lled
Capa
city
(GW
)
ESTELA 2025 Potential Greenpeace - Reference Greenpeace - Moderate
IEA ETP Reference IEA ETP BLUE Map Interp/Extrap
Forecasting Solar Thermal Global Installed Capacity by 2032
IEA’s BLUE Map Scenario includes 600 GW of solar thermal capacity by 2050
• To reach this goal, solar thermal global installed capacity would have to reach approximately 200 GW by 2030
• European Solar Thermal Electricity Association’s Solar Thermal Electricity 2025 anticipates a cumulative total between 60 and 100 GW by 2025—substantially less
E3 has developed a forecast based on the ESTELA forecast that reflects lower anticipated near-term installations of solar thermal facilities
• Total global capacity installed by 2032 is forecast to be 51 GW
39
Aspirational
Pessimistic
Solar Thermal Learning Recommendation
Based on stakeholder feedback, a learning rate of 10% was selected for solar thermal
Combined with the forecast of global installed capacity from the prior slide, this learning rate yields the following projection of solar thermal cost reductions:
40
-20%-29%
-36% -39%
0%
20%
40%
60%
80%
100%
120%
2012 2017 2022 2027 2032
Sola
r The
rmal
Cap
ital C
ost s
(% o
f 201
2)
Wind Learning Recommendation
Wind is a much more mature technology than either solar PV or solar thermal, with a global installed capacity of close to 200 GW
Estimates of learning rates for wind range from 0% - 15%; E3 has adopted a rate of 5%
41
-5% -8% -10% -12%
0%
20%
40%
60%
80%
100%
120%
2012 2017 2022 2027 2032
Win
d Ca
pita
l Cos
t s (%
of 2
012)
• In combination with IEA’s BLUE Map scenario (2,000 GW of wind by 2050), this assumption results in a 12% reduction in wind capital costs by 2032
Federal Tax Credit Landscape
Current federal tax policy provides large incentives to wind and solar developers:
• Accelerated depreciation (5-yr MACRS for wind and solar)
• Investment tax credit (30% of capital costs for solar)
• Production tax credit ($22/MWh for wind)
42
$114
$186
$63
$186
$301
$114
$0
$50
$100
$150
$200
$250
$300
$350
Large Solar PV Solar Thermal Wind
LCO
E ($
/MW
h)
Impact of Five Year MACRS
Impact of Federal Tax Credit
Expiration of Federal Tax Credits
Federal tax credits are scheduled to retire in the near future
• Investment tax credit reverts from 30% to 10% in 2017
• Production tax credit ($22/MWh for wind) expires in 2013
• PTC for other technologies expires in 2014
The 5-year MACRS, as part of the general tax code, is assumed to remain in place
43
Combined Impact of Tax Credit Expiration and Technology Learning
Increased resource costs resulting from the expiration of tax credits are largely offset by technological progress over the next two decades
44
0
50
100
150
200
250
2012 2017 2022 2027 2032
LCO
E (2
010
$/M
Wh)
Wind
Large Solar PV (Fixed Tilt)
Solar Thermal (no storage)
Recommended Resource Costs
Technology Subtype 2012 2022 2032
Solar PV
Fixed (>20 MW) $3,000 $2,322 $2,121
Tracking (>20 MW) $3,300 $2,554 $2,333
Fixed (1-20 MW) $3,500 $2,709 $2,475
Tracking (1-20MW) $3,800 $2,941 $2,687
Comm Roof $5,900 $4,567 $4,171
Res Roof $7,100 $5,496 $5,020
Solar Thermal
No storage $4,900 $3,455 $2,992
6hr storage $7,100 $5,007 $4,336
Wind Onshore $2,000 $1,834 $1,711
45
AC Capital Costs by Installation Year (2010 $/kW)
Recommendations that have been modified since May 15 are highlighted in orange
Resulting LCOEs
Technology Subtype
AC Capacity Factor
(%)
2012 2022 2032
Solar PV
Fixed (>20 MW) 27% $117 $117 $109
Tracking (>20 MW) 29% $123 $122 $114
Fixed (1-20 MW) 27% $135 $134 $124
Tracking (1-20MW) 29% $138 $137 $127
Comm Roof 23% $256 $254 $235
Res Roof 23% $301 $299 $276
Solar Thermal
No storage 28% $187 $172 $153
6hr storage 36% $199 $182 $161
Wind Onshore 37% $63 $82 $80
46
Levelized Cost of Energy by Installation Year (2010 $/MWh)
Average vs. Marginal
Average vs. Marginal
The cost to install one additional MW of solar in 2022 will not equal to the average cost of the solar resources installed between present day and 2022
• A large fraction of the solar resources installed by 2022 will have been installed gradually over the next decade
48
0
50
100
150
200
250
2012 2017 2022 2027 2032
LCO
E (2
010
$/M
Wh)
Wind
Large Solar PV (Fixed Tilt)
Solar Thermal (no storage)
Recommendations for Installed Cost Vintages
To account for the many mitigating factors that will affect resource development over the, E3 recommends using the 2015 installed cost for resources installed in the first decade and the 2027 installed cost for resources installed in the second decade
To simplify this analysis, E3 also recommends assuming that the PTC is extended through the same time horizon as the ITC, expiring in 2017
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First Decade
Most new resources (especially solar) will come online relatively soon to claim tax credits
The choice of 2015 for “average” resource costing reflects this expectation
Second Decade
No resources can claim tax credits
Year-by-year development of renewables is highly uncertain, so the midpoint of the range (2022-2032) is used as a basis for installed costs
Regional Multipliers
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Regional Multiplier Methodology
The original Capital Cost Tool included state-specific estimates of technology costs derived from “regional multipliers”
• Regional multiplier methodology captures geographical differences in costs of labor and materials
As part of this update, E3 has explored several questions related to this subject:
1. With the release of an update to the Civil Works Construction Cost Index System, should the regional cost multipliers be updated?
2. What other factors besides construction cost contribute to geographic difference in resource cost and can easily be incorporated into E3’s capital cost tool?
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Regional Multiplier Methodology
E3 derives technology-specific regional multipliers based on:
• The relative proportions of equipment, material, and labor that constitute a plant’s costs
• The Civil Works Construction Cost Index System’s (CWCCIS) state adjustment factors
The CWCCIS is a construction-based cost indexing system developed by the US Army Corps of Engineers
• State adjustment factors capture approximate geographic cost differences in generic construction projects
• Since equipment costs represent a larger share of costs in power plant construction than in other construction applications, E3 applies state adjustment factors only to the shares of a plant’s cost associated with materials and labor
Sample Comparison of Regional Multiplier Calculations
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A B C D E F
CWCCIS State Adjustment
FactorCategory
Percent of Total Costs
Percent Variable by
Location
Total Weight {=D x [B x E +
(1-E)]}
California 1.21
Equipment 70% 0% 0.700
Materials 10% 50% 0.111
Labor 20% 100% 0.242
Total 100% 1.053
Wyoming 0.90
Equipment 70% 0% 0.70
Materials 10% 50% 0.095
Labor 20% 100% 0.180
Total 100% 0.975
Example regional multiplier calculations, Gas CCGTs in California and Wyoming
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CWCCIS Update
The Army Corps of Engineers released an update to the CWCCIS in March 2011
• E3’s prior work was based on CWCCIS from March 2008
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40 ACOE (March 2008) ACOE (March 2011)
Changes to state adjustment factors are minimal but are easy to incorporate into TEPPC pro-forma
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Benchmarking Regional Adjustment Factors
E3’s adjustment factors capture the same general regional trends as those used by EIA (created by RW Beck)
0
0.2
0.4
0.6
0.8
1
1.2
1.4
AZ CA CO ID MT NV NM OR UT WA WY
Regi
onal
Mul
tiplie
r
Gas CCGT
E3
RW Beck
Correlation: 88%
0
0.2
0.4
0.6
0.8
1
1.2
1.4
AZ CA CO ID MT NV NM OR UT WA WY
Regi
onal
Mul
tiplie
r
Small PV
E3
RW Beck
Correlation: 94%
0
0.2
0.4
0.6
0.8
1
1.2
1.4
AZ CA CO ID MT NV NM OR UT WA WY
Regi
onal
Mul
tiplie
r
Solar Thermal
E3
RW Beck
Correlation: 92%
0
0.2
0.4
0.6
0.8
1
1.2
1.4
AZ CA CO ID MT NV NM OR UT WA WY
Regi
onal
Mul
tiplie
r
Wind
E3
RW Beck
Correlation: 77%
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Other Factors Affecting Relative Geographic Costs
State and local tax codes vary widely by location and that have important implications for plant costs
The table below shows different tax policies for wind projects in WECC states and their resulting impact on project LCOEs, which range from $88 to $101/MWh
AZ CA CO ID MT NV NM OR UT WA WY
State Income Tax (%) 7.0% 8.8% 4.6% 7.6% 6.8% 7.6% 7.9% 5.0%
Sales Tax (%) 2.4% 0.8% 4.3% 6.0% 3.0% 0.7% 3.9% 5.4%
Property Tax (%) 0.3% 1.0% 0.4% 1.2% 0.5% 1.0% 0.6% 1.0% 0.7%
Gross Receipts Tax (%) 3.0% 6.5% 0.5%
Tax Credit ($/MWh) $10 $10 $3.50
Excise Tax ($/MWh) $1
Generic Wind Cost ($/MWh) $88 $96 $94 $96 $94 $96 $91 $92 $92 $101 $99
Source of information:Tax policies based on E3’s Wyoming Wind Energy Costing ModelGeneric wind cost calculated assuming capital cost of $2,000 and a capacity factor of 30%
Incorporating State Income Tax
One significant variant in state-by-state tax codes that affects the cost of development is the state income tax
• Ranges from 0% (NV, WA and WY) to 9% (CA)
• Can be easily integrated into E3’s updated pro-forma
In addition to an update of regional multipliers, E3 proposes to incorporate state-by-state income tax rates into the pro-forma to enhance the geographic differentiation of project costs
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