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
Total
Cost
=
Variable Costs
(PROMOD)
+
Fixed Costs
(E3 Capital Cost Tool)
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
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
2032 Study
2022 Study
Resource
Portfolio
Resource
Performance
(NREL)
PROMOD
Total Scenario
Costs
Capital Costs
(E3 Capital Cost
Tool)
Resource
Performance
(WREZ)
LTPT/NXT
Resource
Portfolio
Total
Scenario
Cost
Capital Costs
(E3 Capital Cost
Tool)
5
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
Technologies in E3’s Capital Cost Tool
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
6
Technologies Covered
E3’s current update encompasses the following
technologies—an expanded set compared to the original
Capital Cost Tool
New to This Year’s
Study Cycle
Modeled
in Prior
WECC
Studies
Solar PV
Large Utility
(20 MW +)
•
Fixed Tilt
•
Tracking
Solar Thermal
No Storage
6hrs Storage
Wind
Onshore
Small Utility
(1-20 MW)
•
Fixed Tilt
•
Tracking
Rooftop
•
Commercial
•
Residential
New technology characterizations
are needed to represent increasing
specificity of photovoltaic resources
modeled by WECC, especially in the
High DG/DSM Case
7
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
Tracking the Sun IV: An Historical Summary of the Installed Cost of
Photovoltaics in the United States from 1998 to 2010
California Solar Statistics
12
Current Trends in Solar PV Prices
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
13
Historical Trends in Wind Costs
Average 2010 installed cost was similar to 2009
14
2010 Wind Technologies Market Report (June 2011)
Data Sources
Author
Report Name
Publication
Date
Installation
Year
Historical
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 CostReduction 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
EIA
Updated 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
CEC
Comparative Costs of California Central Station Electricity
Generation
Jan. 2010
2010
Forward
15
Solar PV – Fixed Utility (20 MW+)
TEPPC 2011
Author
Cost
($/kWDC)
Generic
LCOE
($/MWh)
Installation
Vintage
Size
(MW)
20
RETI 2B
$3,230
2010
LTPP
$3,400
2010
EIA
$3,963
2011
180
$3,400
2012
100
Installation
Vintage
Size
(MW)
TEPPC 2011
Notes
Thin Film
Current Update
Author
Cost
($/kWDC)
Generic
LCOE
($/MWh)
B&V/NREL
$2,396
2015
100
NREL
$3,800
2010
187.5
CPUC
$2,380
2012
150
2012
100
Recommended
$2,550
$117
Notes
California
Capital costs for solar PV technologies shown here are expressed relative
to the DC nameplate rating. To convert to an AC capital cost, these costs
should be multiplied by 1.18 (assuming DC-AC conversion of 85%).
16
Solar PV – Tracking Utility (20 MW+)
TEPPC 2011
Author
Cost
($/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
$3,995
2012
100
Installation
Vintage
Size
(MW)
TEPPC 2011
Current Update
Author
Cost
($/kWDC)
Generic
LCOE
($/MWh)
B&V/NREL
$2,664
2015
100
NREL
$4,400
2010
187.5
CPUC
$2,800
2012
150
2012
100
Recommended
$2,800
$123
Notes
California
Capital costs shown relative to DC nameplate rating
17
Solar PV – Fixed Utility (1-20 MW)
Technology has not been represented in past WECC
modeling efforts
Generic
LCOE
($/MWh)
Installation
Vintage
Size
(MW)
$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
$2,750
2012
10
Crystalline
2012
1 - 20
Author
EIA
Lazard
Recommende
d
Cost
($/kWDC)
$2,975
$135
Notes
Capital costs shown relative to DC nameplate rating
18
Solar PV – Tracking Utility (1-20 MW)
Technology has not been represented in past WECC
modeling efforts
Author
Cost
($/kWDC)
Generic
LCOE
($/MWh)
Installation
Vintage
Size
(MW)
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
2012
1 - 20
Recommende
d
$3,225
$138
Notes
Crystalline
Capital costs shown relative to DC nameplate rating
19
Solar PV - Commercial
Technology has not been represented in past WECC
modeling efforts
Author
Cost
($/kWDC)
Generic
LCOE
($/MWh)
Installation
Vintage
Size
(kW)
LBNL
$5,800
2010
100 – 500
NREL
$4,590
2010
217
CSI
$5,622
2011
56
B&V/NREL
$4,870
2010
100
B&V/NREL
$3,904
2015
100
Recommended
$5,000
$256
Notes
California
2012
Capital costs shown relative to DC nameplate rating
20
Solar PV - Residential
Technology has not been represented in past WECC
modeling efforts
Author
Cost
($/kWDC)
Generic
LCOE
($/MWh)
Installation
Vintage
Size
(kW)
LBNL
$6,600
2010
5 – 10
NREL
$5,710
2010
4.9
CSI
$6,472
2011
5.5
B&V/NREL
$6,050
2010
4
B&V/NREL
$4,413
2015
4
2012
<10
Recommended
$6,000
$301
Notes
California
Capital costs shown relative to DC nameplate rating
21
Solar Thermal – Without Storage
TEPPC 2011
Author
Cost
($/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
$5,350
2012
Current Update
Author
Cost
($/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
$5,000 - $5,400
2012
250
Trough
Lazard
Recommended
$4,900
$187
2012
22
Solar Thermal – With Storage
TEPPC 2011
Generic
LCOE
($/MWh)
Installation
Vintage
Author
Cost
($/kW)
RETI 2B
$7,650 - $7,850
California
$7,500
California
LTPP
TEPPC 2011
Size
(MW)
Notes
$7,500
Current Update
Author
Cost
($/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
$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
Lazard
Recommended
$7,100
$199
2012
Generic, 6 hrs
23
Wind
TEPPC 2011
Author
NWPCC
RETI 2B
Cost
($/kW)
Generic
LCOE
($/MWh)
$2,127
Installation
Vintage
Size
(MW)
2008
100
Notes
NW
$2,150 - $2,600
CA
LTPP
$2,350
CA
EIA
$2,438
TEPPC 2011
2011
100
Installation
Vintage
Size
(MW)
50
$2,350
Current Update
Author
Cost
($/kW)
Generic
LCOE
($/MWh)
CEC COG
$2,023
2010
LBNL
$2,148
2009-2010
B&V/NREL
$2,013
2010
$1,300 - $1,900
2012
Lazard
Recommended
$2,000
$63
Notes
CA
US
100
2012
24
Recommended Resource Costs
Cost Summary (2010 $)
Technolog
y
Solar PV
DC
Capital
Cost
($/kWDC)
AC
Capital
Cost
($/kW)
Generic AC
Capacity
Factor (%)
Generic
LCOE
($/MWh)
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
Subtype
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
Capital costs for solar PV are converted from DC to AC by multiplying by
1.18 (assuming DC-AC conversion of 85%).
25
Comparison of Updated Costs to
Prior Recommendations
Cost Summary (2010 $)
Technology
WECC 2011
2012 Update
Generic AC
Capacity
Factor (%)
AC Capital
Cost ($/kW)
Generic
LCOE
($/MWh)
AC Capital
Cost
($/kW)
Generic
LCOE
($/MWh)
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
No Storage
28%
$5,350
$200
$4,900
$187
6hr storage
36%
$7,500
$208
$7,100
$199
Onshore
37%
$2,350
$75
$2,000
$63
Subtype
Solar PV
Solar
Thermal
Wind
26
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 Curve Theory
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
Example: 20% Learning Rate
The learning rate (LR) is used
to describe the expected
decrease in costs with a
doubling of experience
Price
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.
2x
-20%
2x
-20%
Cumulative Experience
29
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
Past performance does not
indicate future potential
Recent cost reductions have not
followed the longer-term trends
of historical learning
Source: Global Overview on Grid-Parity Event Dynamics (Breyer and Gerlach)
30
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%)
Source: Navigant Consulting
31
Uncertainty in Future Costs
Past trends do not guarantee future declines, and
other factors influence technology costs
Optimistic Path
Pessimistic Path
Solar PV continues to reap benefits
of a high learning rate
Today’s low prices caused by excess
supply followed by a rebound as
markets re-equilibrate
Global installed capacity grows
rapidly
Cost of raw materials rise
Installed PV Cost
Int’l markets saturate and US
growth slows as the ITC expires
2010
Historical Trend
Pessimistic Path
Optimistic Path
2012
2014
2016
2018
2020
32
Uncertainty in Global Installed
Capacity
Future growth of solar PV can vary widely, as shown by the
IEA’s 2010 Energy Technology Perspectives scenarios
Global Installed Capacity (GW)
Solar PV
3,500
3,000
3,000
2,500
2,000
1,700
1,500
1,000
500
40
300
0
Existing, 2010
Baseline
BLUE MAP
BLUE High
Renewables
IEA Projections, 2050
•
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
Sensitivity of Learning Curves to
Global Installations Forecast
The impact of an
additional MW of
capacity declines as
the cumulative
installed capacity
increases
Global Installed Solar PV Capacity
(GW)
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0
2012
Solar PV Capital Cost (% of
2012)
The choice of a
forecast of future
installations has a
significant impact on
anticipated future
cost declines
2,000
2017
2022
2027
2032
2037
140%
120%
90%
100%
80%
71%
60%
65%
40%
20%
0%
2012
2017
IEA BLUE, High Renewables
2022
2027
IEA BLUE Map
2032
2037
IEA Baseline
Forecast declines based on a 10% learning rate
34
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
Solar PV Global Installed
Capacity (GW)
400
350
300
250
EPIA Moderate
200
EPIA Policy Driven
150
Historical
100
50
0
2004
2006
2008
Moderate Scenario: pessimistic
market behavior, reduced policy
support for PV development
2010
2012
2014
2016
Policy Driven Scenario: continuation
of support mechanisms (FiTs) and
strong political favor for solar PV
35
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
Solar PV Global Installed
Capacity (GW)
1,400
1,200
EPIA Moderate
1,000
EPIA Policy Driven
800
Historical
600
EPIA Moderate (Extrap)
EPIA Policy Driven (Extrap)
400
IEA 2050 BLUE Map (Linear)
200
Avg of EPIA-Derived Forecasts
0
2010
2014
2018
2022
2026
2030
36
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
120%
Solar Thermal Capital Cost s (% of 2012)
Coupled with the
EPIA-derived longterm PV forecast,
this learning rate
yields the following
estimates of longterm cost reductions
100%
-16%
80%
-23%
-27%
-29%
2027
2032
60%
40%
20%
0%
2012
2017
2022
37
Comparison of Recommended PV
Costs to Other Sources
Res Roof PV
Comm Roof PV
$8,000
$8,000
E3 LDPV (20% LR)
E3 LDPV (20% LR)
E3 LDPV (0% LR)
E3 LDPV (0% LR)
$6,000
B&V/NREL
CSI Data
NREL Benchmark
$4,000
$/kW-DC
$/kW-DC
$6,000
B&V/NREL
CSI Data
NREL Benchmark
$4,000
NREL Evolutionary
NREL Evolutionary
DOE Sunshot
$2,000
DOE Sunshot
$2,000
LBNL
LBNL
E3/WECC
2012
2016
$6,000
2020
2024
2028
2032
2036
2012
2016
$6,000
Small Ground PV - Fixed Tilt
$5,000
E3 LDPV (0% LR)
B&V/NREL
NREL Benchmark
$3,000
NREL Evolutionary
$2,000
DOE Sunshot
2020
2024
2028
2032
2036
Large Ground PV - Fixed Tilt
$5,000
E3 LDPV (20% LR)
$4,000
$/kW-DC
E3/WECC
$0
2008
B&V/NREL
$4,000
$/kW-DC
$0
2008
NREL Benchmark
NREL Evolutionary
$3,000
DOE Sunshot
$2,000
CPUC RPS Calc
CPUC RPS Calc
$1,000
$0
2008
E3/WECC
2012
2016
2020
2024
2028
2032
2036
E3/WECC
$1,000
$0
2008
2012
2016
2020
2024
2028
2032
2036
38
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
Solar Thermal Global Installed
Capacity (GW)
•
250
Aspirational
200
150
100
51
50
Pessimistic
0
2010
2014
2018
2022
2026
2030
ESTELA 2025 Potential
Greenpeace - Reference
Greenpeace - Moderate
IEA ETP Reference
IEA ETP BLUE Map
Interp/Extrap
39
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:
Solar Thermal Capital Cost s (% of 2012)
120%
100%
-20%
80%
-29%
-36%
-39%
2027
2032
60%
40%
20%
0%
2012
2017
2022
40
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%
120%
Wind Capital Cost s (% of 2012)
• 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
100%
-5%
-8%
-10%
-12%
2017
2022
2027
2032
80%
60%
40%
20%
0%
2012
41
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)
$350
$301
LCOE ($/MWh)
$300
$250
$200
$186
$186
$150
$100
Impact of Five Year MACRS
$114
Impact of Federal Tax Credit
$114
$50
$63
$0
Large Solar PV
Solar Thermal
Wind
42
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
250
LCOE (2010 $/MWh)
200
Solar Thermal (no storage)
150
Large Solar PV (Fixed Tilt)
100
Wind
50
0
2012
2017
2022
2027
2032
44
Recommended Resource Costs
AC Capital Costs by Installation Year (2010 $/kW)
Technology
2012
2022
2032
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
Solar PV
Subtype
Recommendations that have been modified since May 15 are highlighted in orange
45
Resulting LCOEs
Levelized Cost of Energy by Installation Year (2010 $/MWh)
AC
Capacity
Factor
(%)
2012
2022
2032
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
Technology
Solar PV
Subtype
46
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
250
200
LCOE (2010 $/MWh)
•
Solar Thermal (no storage)
150
Large Solar PV (Fixed Tilt)
100
Wind
50
0
2012
2017
2022
2027
2032
48
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
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
49
Regional Multipliers
Regional Multiplier Methodology
The original Capital Cost Tool included statespecific 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?
51
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
52
Sample Comparison of Regional
Multiplier Calculations
Example regional multiplier calculations, Gas CCGTs in California and Wyoming
A
California
Wyoming
B
C
D
E
F
CWCCIS State
Adjustment
Factor
Category
Percent of
Total Costs
Percent
Variable by
Location
Total Weight
{=D x [B x E +
(1-E)]}
Equipment
70%
0%
0.700
Materials
10%
50%
0.111
Labor
20%
100%
0.242
Total
100%
1.21
1.053
Equipment
70%
0%
0.70
Materials
10%
50%
0.095
Labor
20%
100%
0.180
Total
100%
0.90
0.975
53
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
1.40
ACOE (March 2008)
ACOE (March 2011)
1.20
1.00
0.80
0.60
0.40
0.20
0.00
Changes to state adjustment factors are minimal but are
easy to incorporate into TEPPC pro-forma
54
Benchmarking Regional
Adjustment Factors
E3’s adjustment factors capture the same general
regional trends as those used by EIA (created by
RW Beck)
Gas CCGT
Regional Multiplier
1.2
1.4
Correlation: 88%
1
0.8
E3
0.6
RW Beck
0.4
0.2
Correlation: 94%
1
0.8
E3
0.6
RW Beck
0.4
0.2
0
0
CA
CO
ID
MT
1.4
NV
NM
OR
UT
Wind
1.2
WA WY
AZ
CA
CO
ID
1.4
Correlation: 77%
1
0.8
E3
0.6
RW Beck
0.4
0.2
MT
NV
NM
OR
UT
Solar Thermal
1.2
Regional Multiplier
AZ
Regional Multiplier
Small PV
1.2
Regional Multiplier
1.4
WA WY
Correlation: 92%
1
0.8
E3
0.6
RW Beck
0.4
0.2
0
0
AZ
CA
CO
ID
MT
NV
NM
OR
UT
WA WY
AZ
CA
CO
ID
MT
NV
NM
OR
UT
WA WY
55
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 $101/MWh
AZ
CA
CO
ID
MT
State Income Tax (%)
7.0%
8.8%
4.6%
7.6%
6.8%
Sales Tax (%)
2.4%
0.8%
4.3%
6.0%
Property Tax (%)
0.3%
1.0%
0.4%
Gross Receipts Tax (%)
Tax Credit ($/MWh)
NV
NM
OR
UT
7.6%
7.9%
5.0%
3.0%
1.2%
0.5%
3.0%
1.0%
WA
WY
0.7%
3.9%
5.4%
0.6%
1.0%
0.7%
6.5%
$10
0.5%
$10
$3.50
Excise Tax ($/MWh)
Generic Wind Cost ($/MWh)
$1
$88
$96
$94
$96
$94
$96
$91
$92
$92
$101
$99
Source of information:
Tax policies based on E3’s Wyoming Wind Energy Costing Model
Generic wind cost calculated assuming capital cost of $2,000 and a capacity factor of 30%
56
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
57