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

49

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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