francis o’sullivan and richard...

Francis O’Sullivan and Richard Schmalensee

Rutgers Energy Institute, November 6, 2015

The latest in the MIT “Future of…” studies exploring the

roles of key energy technologies in a carbon-constrained future

Limiting climate risk to acceptable levels will require

drastic reductions in global carbon dioxide emissions

from electricity generation by mid-century.

This will be politically difficult unless the electric power sector can also

meet the needs of a growing global economy at reasonable cost.

Solar is about 1% of global generation; can it be scaled up by around 50x

by 2050 to play a major role in meeting future electricity demand?

If so, what policies would make this most likely? 2

http://web.mit.edu/mitei/research/studies/report-natural-gas.pdf

With today’s technology, total U.S. electricity demand could be

met by solar covering 0.43% of the contiguous U.S.

Source: Map adapted from Albuisson, M., M. Lefevre, and L. Wald. Averaged Solar Radiation 1990-2004, Ecole des Mines de Paris. (2006).

Map showing global variations in average annual solar irradiance

3

The scale and distribution of the solar resource make it one of the few low

carbon technologies capable of meeting a substantial fraction of

worldwide electricity demand even with rapid economic growth.

Today we have two practical pathways for generating solar electricity, PV

and CSP – PV dominates contemporary solar electricity generation and it will

continue to do so for the foreseeable future

Solar photovoltaics (PV) - Mature:

~97% of global

solar capacity

- Modular:

efficiency does not

depend on scale

- Output responds

immediately to

changes in

insolation

Concentrated solar power (CSP) - Less mature,

more expensive

- Capital costs

fall with scale

- Needs clear skies

- Dispatchable when

thermal storage is

added

4

5

The past half decade has borne witness to remarkable growth in the scale of

installed solar generation capacity – This year will see 65GW of new PV

capacity come online with 40 GW coming from the US, Japan and China alone

0

50

100

150

200

250

2008 2009 2010 2011 2012 2013 2014 2015E

USA

China

Europe

ROW

Cumulative global installed PV capacity

GW

Global installed solar capacity will approach 250GW

by the end of 2015, a 12X expansion since 2008

Source: MIT Analysis, National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, Solar Energy Industry Association, European Photovoltaic Industry Association, IHS

65 GW of new PV

capacity in 2015

6

The pathway for solar growth depends on the local market – In the US and

China, utility scale systems are the dominant growth vector, while in markets

like Japan distributed systems lead the way

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

2008 2009 2010 2011 2012 2013 2014 2015E

Utility

Commercial

Residential

Annual US PV capacity additions by system type

MW

0

4000

8000

12000

16000

20000

2014

Other

New Mexico

Texas

New York

Hawaii

Nevada

Massachusetts

North Carolina

New Jersey

Arizona

California

Cumulative PV capacity by state (2014)

MW

In the US, close to 60% of all PV capacity is in the

form of utility-scale units

Source: MIT Analysis, National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, Solar Energy Industry Association, European Photovoltaic Industry Association, IHS

Deployment support at federal,

state, and local levels has also

driven growth

… but federal subsidies are scheduled to

be drastically cut from 2017, and

state programs have not expanded

recently

… and there has been a backlash

against rooftop solar in some states

7 Source: MIT Analysis, National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, U.S. Department of Energy, Solar Energy Industry Association, Photon Consulting

LLC

Rapid declines in PV module prices

have been important drivers of

growth

… but these declines may have slowed

… and BOS costs have declined much

less rapidly

Evolution of PV module & system prices

$/Wp

MODULE

Price Drop

~85%

UTILITY

PV system

MODULE

BOS

RESIDENTIAL

PV System

A large reduction in the cost of PV modules has been a key factor in the

recent growth of solar installations – These dynamics also mean that the

focus of solar economics is shifting to the balance-of-system (BOS)

8

Levelized cost of electricity

$/MWh

0

50

100

150

200

250

300

350

Gas Combined Cycle

76

Benchmark LCOE

for Natural Gas

Generation

PV Systems

ITC Subsidy Value

CA MA

Regional variation

Minimum LCOE

CA MA

Utility-Scale

PV

Residential-Scale

PV

105

158

* CSP LCOE numbers based on CA system having 11 hours and MA system having 8 hours of nameplate capacity storage

Source: MIT Analysis, U.S. Energy Information Administration

With these lower costs, utility-scale PV is increasingly competitive in

regions with high quality solar resource like CA, even without subsidy –

But residential PV and CSP systems have notably higher costs

CSP Systems*

192

287

CA MA

141

CSP

331 After Subsidy LCOE

9

However, as PV penetration increases the average price a PV generator

receives will be suppressed significantly – For solar to succeed at very large

scales, its costs must be reduced substantially

Source: MIT Analysis

60

20

55

50

45

40

35

30

25

0 36 6 12 18 24 30

Illustration of how the price a solar generator receives for its output can fall well

below the average market price as solar penetration increases

$/MWh

Solar Penetration

(% Peak Demand)

10

Increasing solar penetration in Germany has already lead to this new pricing

paradigm in their power system – Large-scale solar generation has led to

shaving of peak prices in the Germany wholesale power market

At marginal

penetration the

realized peak

price is high

As penetration rises

the peak price is

suppressed

Source: MIT Future of Solar Study

In light of all this, what needs to be done now to make it more likely that

solar energy can play a major role in limiting climate change?

11

Three main messages:

1. A long-term approach should be taken to technology

development

2. Preparation should be made for much greater

penetration of PV generation

3. Subsidies for solar deployment should be reformed

to improve their efficiency

Message 1:

A long-term approach should be taken to technology

development

What that means in practice:

Federal R&D spending should focus on emerging technologies with

the potential to deliver transformative cost reductions; the private

sector has the incentives and ability to improve those technologies

that are currently commercially marketed.

12

Wafer-based PV technologies and in particular crystalline silicon (c-Si)

dominate today’s solar market – In may respects this is a very attractive

technology but it has limitations

13

Current c-Si PV technology

c-Si PV technology is efficient and mature, but its intrinsic properties

may limit the potential for much further system cost reductions

ADVANTAGES

Efficient

Reliable

Robust and

Durable

Abundant

Non-toxic

DISADVANTAGES

Thick wafers

Rigid and heavy

Complex

manufacturing

14

With today’s c-Si PV technology balance of system (BOS) costs dominate

total system costs – Industry has the ability and incentive to reduce BOS

costs

14 Source: MIT Analysis

0.65 0.40

0.40 0.05

0.30

1.80

0.00

1.00

2.00

Module Inverter & OtherHardware

Engineering andConstruction

Sales Tax Margin and G&A System Cost

2014 System cost build-up $/W

Balance of System

Utility-Scale

PV

BOS now accounts

for 65% of utility-scale

system cost

0.65

0.90

0.35

0.56

0.05

0.74

3.25

0.00

1.00

2.00

3.00

Module Inverter, OtherHardware &

Logistics

InstallationLabor

CustomerAcquisition &

PII

Sales Tax Margin andG&A

System Cost

2014 System cost build-up $/W

Balance of System

Residential-Scale

PV

BOS now accounts for

80% of residential-scale

system cost

15

Emerging thin-film technologies have the potential to lower both

module and BOS costs

Light & Flexible High-throughput Abundant

Much more R&D needs to be done, and this is where federal

solar R&D should focus

15

Kaltenbrunner, et al. 2012

(Current) Challenges

Low efficiency

Low stability

Unproven at scale

16

DOE solar R&D funding has increasingly focused on

areas other than core solar technology development

0

50

100

150

200

250

300

350

400

2010 2011 2012 2013 2014 2015 2016*

Breakdown of DOE’s Solar Energy Technology Office budget

$110M

or

31%

$241M

or

69%

Funding for work on

Current Technologies

addressing:

• grid integration

• enhanced manufacturing

competitiveness

• reduction of c-Si

BOS “soft costs”

Funding for work

directly focused on

Advanced Solar

Technologies

* 2016 SETO budget values are proposed not actual

Source: Department of Energy Annual Budget Justification statements

PV

CSP

Other

$Millions

17

To reduce CSP costs substantially, new high-temperature system

designs & materials must be developed and tested at pilot scale

Reminder:

Storage is integral for CSP

in the form of stored heat

that can be used on demand

to produce electricity

More efficient solar

collectors can convert

more of the incident

solar energy into thermal

energy Higher-temperature

power cycles can

convert more of the

absorbed thermal

energy into electricity


CSP energy losses and opportunities

Key Recommendations:

Technology Development

18

• Federal PV R&D should focus on transformative

technologies rather than on near-term reductions

in the cost of crystalline silicon systems.

• Federal PV R&D efforts should focus on new and

emerging thin-film PV technologies that use

environmentally benign, Earth-abundant materials

and that are compatible with low-cost manufacturing

and lower BOS costs.

• Federal CSP R&D efforts should focus on new

materials and system designs, and should establish

a program to test new designs in pilot-scale facilities,

akin to those common in the chemical industry.

Message 2:

Preparation should be made for much greater

penetration of PV generation


Given that c-Si PV will likely be the dominant solar technology for

many decades to come and very large-scale reliance on PV will pose

much more serious challenges than have been encountered to date, it

is necessary to focus on developing both the technical and

market/policy solutions needed to mitigate these challenges

19

Higher levels of PV penetration yield a number of challenges for the grid

operation including capacity and ramping requirements – These issues

can be mitigated to various degrees by storage

Simulated net demand for non-PV generation at different levels of PV penetration

ERCOT (Texas) typical summer day

20

24 hour day

INCREASED RAMPING

RATE REQUIRED

ELECTRICITY

DEMAND

PEAK NON-PV

GENERATION

Diurnal and seasonal changes in PV output are predictable, but PV

output varies with the weather, which is imperfectly predictable

21

• At high levels of reliance on PV, large-scale storage with various capacities

(e.g., minutes, hours, days, …) and response speeds will likely be necessary.

• Apart from pumped (hydro) storage, which is economical but difficult to site,

large cost reductions in storage are necessary for widespread deployment.

Source: NREL

Hourly solar radiation at Golden, Colorado during 2012

22

Distributed PV can help lower line losses, but as penetration grows those

savings are generally outweighed by investments needed to maintain

power quality

Average total costs with increased distributed PV penetration under

different assumptions about design standards & generation mix


23

Net metering subsidizes residential PV more than utility-scale PV at the

expense of other customers – This has already produced conflict

Wholesale

energy price

Retail price

including

network

costs

Utility Customers

A B C

Network cost paid by customer per kWh

Energy cost paid by customer per kWh

System before A installs solar

…N

Wholesale

energy price

Higher retail price

with cost shifted

Utility Customers

A B C

Network cost paid to customer A per kWh

Energy cost paid to net-metered customer per kWh

System after A becomes a net solar seller

…N

Net-metered rate

paid to Customer A

Additional network cost paid by customers without solar

Utility Rate

$/kWh

Utility Rate

$/kWh

- When A sells power, she gets the retail price, while utility-

scale sellers get the wholesale price, often much lower

- When A stops covering any network costs, the retail rate

must go up so the other customers cover those costs –

plus the network cost paid to A!


Grid integration

24

• R&D aimed at developing low-cost, scalable energy

storage technologies is a crucial part of a strategy to

achieve economic PV deployment at large scale.

• Utilities, regulators, and stakeholders should develop

and deploy fair pricing systems that allocate distribution

network costs to all users of the network—including

distributed solar generators.

Message 3:

Subsidies for solar deployment should be reformed to

improve their efficiency


There is a good case for continuing to subsidize the deployment of

solar generation, but today taxpayers and utility ratepayers are paying

considerably more per kilowatt-hour of solar generation than they

could be. Appropriate reforming of today’s subsidy mechanisms will

ensure greater solar deployment per dollar of subsidy investment

25

Federal, state, & local governments

subsidize the deployment of solar technologies through an array

of tax credits, regulatory requirements, and direct subsidies

26

• These subsidies help lay the foundation for a major solar scale-up

by building experience with manufacturing & deployment and

overcoming institutional barriers

• Particularly in the absence of a nation-wide price on carbon

emissions, the US should continue to subsidize solar deployment

• The main federal solar subsidies are accelerated depreciation and

a 30% investment tax credit (ITC) for businesses and individuals

who own a solar system.

• At the end of 2016 the business ITC is scheduled to be cut to 10%,

and the individual ITC is scheduled to expire

• Such a drastic cut in federal support would be unwise

• Federal, state, and local support of solar deployment should be

reformed to enhance the efficiency of these programs

Solar developers are generally not capable of monetizing the ITC without use

of the tax equity market – Having to partner with tax equity investors is costly and

reduces the effectiveness of the entire subsidy mechanism

27

68

101

37

57

0

50

100

150

200

250

300

350

CA MA

120

180

72

107

CA MA

Utility-Scale PV Residential-Scale PV

ITC subsidy cost per

kWh

After ITC electricity

LCOE

Levelized cost of electricity $/MWh

- The current solar ITC subsidy regime

means that more expensive systems

receive higher subsidies

- Generation from residential systems

can receive 2X or more subsidy per

kWh than from utility-scale systems

- Not only that, firms that build and

own residential solar systems can

calculate ITC and depreciation based

on the present value of systems’

income, which in markets with little

competition may be well above the

actual investment cost.


The 24 state-level RPSs that require utilities to buy solar electricity

from distributed generators are a major driver of solar deployment

28

All RPS programs are different; almost all restrict generator location; many states

have multiple solar support policies; some localities do also

Source: dsireusa.org


Deployment policy

29

• Particularly in the absence of a nationwide price on

carbon emissions, drastic cuts in federal support for

solar technology deployment would be unwise.

• Policies to support solar deployment should reward

generation, not investment; should not provide greater

subsidies to residential generators than to utility-scale

generators; and should avoid the use of tax credits.

• State RPS programs should be replaced by a uniform

national program. If this is not possible, states should

remove restrictions on out-of-state siting of eligible

solar generation.

Working Draft

Last Modified 4/28/2010 8:16:26 AM GMT Standard Time

Printed 4/28/2010 8:08:33 AM GMT Standard Time

Thank You

31

Study Chair

RICHARD SCHMALENSEE

Howard W. Johnson Professor of Economics and Management

John C. Head III Dean (Emeritus)

Sloan School of Management, MIT

Study Co-Chair

VLADMIR BULOVIĆ

Fariborz Maseeh (1990) Professor of Emerging Technology

Associate Dean for Innovation

Electrical Engineering and Computer Science, MIT

Study Group

ROBERT ARMSTRONG

Chevron Professor, Department of Chemical Engineering, MIT

Director, MIT Energy Initiative

CARLOS BATTLE

Visiting Scholar, MIT Energy Initiative

Associate Professor, Institute for Research in Technology

Comillas Pontifical University

PATRICK BROWN

PhD Candidate, Department of Physics, MIT

JOHN DEUTCH

Institute Professor, Department of Chemistry, MIT

HENRY JACOBY

Professor (Emeritus), Sloan School of Management, MIT

JOEL JEAN

PhD Candidate, Department of Electrical Engineering

and Computer Science, MIT

RAANAN MILLER

Associate Director, MIT Energy Initiative

Executive Director, Solar Energy Study

FRANCIS O’SULLIVAN

Senior Lecturer, Sloan School of Management, MIT

Director, Research and Analysis, MIT Energy Initiative

JOHN PARSONS

Senior Lecturer, Sloan School of Management, MIT

JOSE IGNACIO PĖREZ-ARRIAGA

Professor, Institute for Research in Technology

Comillas Pontifical University

Visiting Professor, Engineering Systems Division, MIT

NAVID SEIFKAR

Research Engineer, MIT Energy Initiative

ROBERT STONER

Deputy Director for Science and Technology, MIT

Energy Initiative

Director, Tata Center for Technology and Design, MIT

CLAUDIO VERGARA

Postdoctoral Associate, MIT Energy Initiative

ROBERT JAFFE

Morningstar Professor of Science, Department of

Physics, MIT

Study Participants

more than 35

years of current

production

required by 2050 6 years

1400

years

COMMERCIAL THIN FILM PV Source: MIT Analysis 32 32

Te, In, Ga, and Se

are now produced only as

by-products from the

production of other metals.

Substantial increases in

production volumes of these

materials would likely require

primary production with

unknown technologies.

Thin-film PV technologies promise lower BOS costs due to their

format that can eliminate heavy glass substrates, … but, unlike

c-Si, materials availability and high-temperature processing will

limit the scale-up of today’s commercial thin-film PV

Source: MIT Analysis 33 33

at most 3 years

of current

production

required by 2050

EMERGING Thin-Film PV

Material Sets

COMMERCIAL THIN FILM PV

EMERGING THIN FILM PV

There is a promising set of emerging thin-film PV

technologies that are not materials-constrained and

that can be developed at near room-temperature

34

The PV system cost reductions that have been achieved have not necessarily

been passes along to US consumers – In the utility sector, pricing tends to be

competitive, while “value pricing” is a prominent feature of the residential market

Utility-scale PV – ~1MW and above Residential-scale PV – up to 10kW

- Utilities driving market by need to meet RPS

targets

- Strong competition among developers to

secure PPAs

- Pricing strongly linked to underlying cost

base

PV Pricing Mechanisms

- Emerging awareness and demand among

homeowners

- Installers developing innovative business

models reducing upfront costs to owners

- “Value Pricing” linking solar prices to local

utility rates

Today, utility sector PPAs are being signed in the $40-50/MWh range, this

is at or below what today’s capex costs can allow – This is evidence of

operators being confident they can take out further cost

35

2008 2009 2010 2011 2012 2013 2014 2015

300MW

100MW

0

50

100

150

200ERCOT Southwest California Northwest MISO SPP Southeast

Average PPA prices

$/MWh

Sources: Bloomberg NEF, “U.S. PPA Market Outlook.” 07/08/15. GTM/SEIA, “US SMI Q1 2015.”

Price formation in the residential sector differs from market-to-market and is

often linked to regulated utility rates – Consumer willingness to pay can lead to

a decoupling of solar price from underlying cost

36

UnsubsidizedCosts - Gross

Price toConsumer

Federal Subsidy Net Price toConsumer

Net ConsumerWillingness to

Pay

Federal Subsidy Gross Price toConsumer

$3.25/W

$4.50/W

$2.27/W ITC: $0.98/W

Reported

price in

competitive

market

Reported price in

immature market

ITC: $1.35/W

Competitive Market Immature or Uncompetitive Market

WTP: $3.15/W

Source: MIT Team Analysis

37

One of the most important factors in the growth of solar in the residential

market has been the rise of the “third party owned” business model – High

capital cost and tax appetite, two key barriers to US residential solar penetration

have been eliminated

Source: California Solar Initiative and other state reporting systems

Average system price by ownership type

$/Wp

$4.15

$5.25

3.00

3.50

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

Q4'10

Q1'11

Q2'11

Q3'11

Q4'11

Q1'12

Q2'12

Q3'12

Q4'12

Q1'13

Q2'13

Q3'13

Q4'13

Q1'14

Q2'14

Q3'14

Q4'14

Q1'15

Q2'15

AZ CA, Host-owned

CA, 3rd-party MA, Host-owned

MA, 3rd-party MD

NY, Host-owned NY, 3rd-party

The success of the third-party owned model is rooted in the ability to “value

price” solar power relative to incumbent utility supplied power

38

Range of future utility

prices: PU, t

Power Price

¢/kWh

Years 0 1 2 3… …N

Predefined future PV lease

or PPA price: PPV, t

PU, 0

PPV, 0

- Third party solar ownership, either via leases or PPA structures is allowed allowed in at least 22

states today

- The third party model makes residential solar very affordable and in most major markets it entirely

dominates installations – In CA more than 75% of new installations are third party

- Third party solar developers are explicit in viewing themselves as competing directly with utilities Source: MIT Team Analysis

Cost-basis calculation for ITC purposes is an area where the third-party model

causes issues

39

- The cost method is the most straightforward and is based on the assumption that an informed

purchaser will pay no more for a system than the cost of replacing it.

- The market method relies on data from recent sales of comparable systems.

- The income method estimates FMV based on the cash flows generated by the system.

Allowable methods for establishing the solar ITC cost basis:

How the ITC cost basis is established based on the “income method”


In many contemporary U.S. residential solar markets, allowing the ITC cost

basis be established via the “income method” amplifies the subsidy by 50%

or more – In highly competitive markets this amplification would be eliminated

40

UnsubsidizedCost

Lease PV Subsidy PV Total IncomePV

Lease PV Subsidy PV Total IncomePV

Subsidies:

ITC:

$0.98/W

MACRS: $0.26/W $4.24/W

Cost Method Income Method

$3.00/W

Subsidies:

ITC:

$1.45/W

MACRS: $0.39/W

$3.00/W

$4.84/W

$3.25/W


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