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When renewable energy met sustainable growth
Regulation, cost reduction, and the rise of renewable energy in the United States
Written on 07/29/2016
H
istorically and famously fossil-fuel dependent, the U.S. energy and
electricity mixes are evolving quickly as costs fall for renewables,
regulations mandate their implementation, and fiscal policy
incentivizes their installation.
Samantha Stephens
SRI Analyst
The investment and production tax credits (ITC and PTC) as well as power
purchase agreements (PPAs) are well-known for their contributions to the
development of solar and wind capacity, and the recent extensions of these
credits has led to a positive outlook for continued growth in installations and
generation. In addition, the green power market is experiencing record
participation, as tracking the positive environmental externalities of
renewable power has become important to meet renewable portfolio
standards, which mandate implementation of renewable energy by state.
Cost reduction is further taking place globally due to technological advances
and economies of scale, which serves as another key driver for development.
Of course, challenges are still present, particularly due to a plentiful and
inexpensive domestic fossil fuel supply, uneven application of regulation and
incentives state-by-state, and the uncertainty of continued political support.
Even so, a progressive lowering of traditional barriers is leading to the
potential for widespread deployment of renewables across the American
landscape.
www.mirova.com
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Table of contents
Wind and solar: disrupting the U.S. energy mix? .......................................... 3
The growing role of renewables ...................................................................................................... 3
Differentiated growth among renewable energy sources ................................................... 4
Historical development of wind and solar .................................................................................. 6
Cost reduction and regulation are driving the development of
renewables ................................................................................................................. 9
Two case studies..................................................................................................................................... 9
Cost reduction is taking place rapidly........................................................................................ 11
Policy and regulation ......................................................................................................................... 15
Review of project cash flows .......................................................................................................... 19
Renewables and the marketplace ................................................................... 20
The solar value chain ......................................................................................................................... 20
The wind value chain......................................................................................................................... 23
Conclusion................................................................................................................ 24
Appendix .................................................................................................................. 26
I: Deregulation of utilities opened the door for independent power
producers ................................................................................................................................................ 26
II: Other influential incentives are also present .................................................................... 26
Bibliography............................................................................................................ 29
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Environmental and
energy security
concerns mean that
renewables are being
implemented more and
more, even in regions
with large fossil
resources.
Recent years have seen enormous energy policy changes throughout the
world due to economic, environmental, security, and social concerns, many
of which influence renewables. Given the United States’ responsibility for
16% of global CO2 emissions in 2014, rapid deployment of low-carbon,
renewable energy sources is essential for reducing the global increase in
temperature and alleviating the multifaceted threats posed by climate
change. While climate issues do remain a point of contention in the United
States, all agree on the need for greater energy security. So, despite regional
complexities like divided politics, limited federal regulatory power, and
plentiful fossil resources, renewable capacity additions and their share in the
energy mix have been increasing rapidly.
Wind and solar: disrupting the U.S. energy mix?
The growing role of renewables
Until the early 2000s, the global implementation of renewable energy was
highly dependent on cost; only hydropower and geothermal energy sources
could compete on a cost basis with fossil fuels for electricity generation while
for transportation, residential, commercial, and industrial use there was
almost no cost-competitive alternative. As a result, only countries with high
hydro and geothermal power availability, such as Brazil, Norway, and
Iceland, had a significant share of renewables in their electricity mix. In all
other countries, fossil fuels, and to a lesser extent nuclear, have been
dominant.
More recently, however, with mounting environmental and energy security
concerns, regulation, technology, and fiscal policy have led to reduced costs
for certain renewables relative to other fuels. The European Union has been
particularly quick to react, implementing targets and subsidies to push for a
swift development of these energy sources. Uptake in the United States and
China has been slower for a variety of reasons, including their large
hydrocarbon resources, the Chinese focus on rapid, low-cost development,
and the American reluctance towards government intervention in the free
market. Even so, as costs fall and environmental issues move increasingly
into the public, private, and regulatory eye, growth is intensifying in both
regions.
Figure 1: Renewables' share of electricity in select regions, 1990 - 2030
Wind, solar, and bioenergy
Hydro and geothermal
30%
30%
25%
25%
20%
20%
15%
15%
10%
10%
5%
5%
United States
China
Europe
0%
1990
2000
2010
2020
2030
0%
1990
World
2000
2010
2020
2030
Source: Mirova / BP 2015/ IEA 2015
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In the U.S., renewable energy sources accounted for 9.8% of the total energy
consumption and 13.5% of electricity generation in 2014, their highest share
since the early 20th century. Slightly more than half of all renewable energy
was used to generate electricity, with hydro producing about 50%, followed
by wind (33%), solar (6%), and geothermal (3%).
Figure 2: Renewables in the US energy mix
U.S. energy and electricity mixes, 2014
Natural Gas
(mainly direct
residential /
commercial
use)
Biofuels (mainly
transportation)
Natural Gas
Nuclear
Electricity
Coal
Crude Oil
(mainly
transportation)
Hydro
Biomass /
Waste
Coal
(mainly
industry)
Wind / Solar /
Other
Renewables in the electricity mix
Renewables in the energy mix
Wind
Wind
Solar
Solar
Biomass
and Waste
Geothermal
Biofuels,
Biomass,
and Waste
Geothermal
Hydro
Hydro
Source: Mirova / US EIA 2016/ IEA 2015
Differentiated growth among renewable energy sources
If the global temperature rise is to be kept below 2°C, the International
Energy Agency (IEA) states, renewables (including solar, wind, bioenergy,
hydro, and geothermal) must make up at least 33% of the American
electricity mix by 2040, while the proportion of fossil fuels must
simultaneously decrease; maintaining the current U.S. fuel mix implies a
temperature rise of about 6°C. Even so, the growth likely to be experienced
by each type of renewable will vary widely.
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Figure 3: Evolution of the U.S. energy and electricity mixes in a 2° scenario
U.S. Primary Energy Consumption
Electricity Generated (TWh)
Primary Energy (Mtoe)
2500
U.S. Electricity Generation
Projections based on
the IEA 2°C scenario
2000
1500
1000
500
0
5000
4500
4000
3500
3000
2500
2000
1500
1000
500
0
Projections based on
the IEA 2°C scenario
Wind / Solar / Other
Bioenergy
Hydro
Nuclear
Natural gas
Oil
Coal
Source: Mirova / BP 2015/ IEA 2015
Hydro and geothermal have little growth potential
Space is limited for
hydropower and
geothermal energy,
while bioenergy still
raises some concerns.
Large-scale hydropower and geothermal energy, the “historical renewables,”
have already been implemented in most available sites. As a result, even if
their carbon intensity is low and their environmental impacts are limited1,
these energy sources exhibit relatively low growth potential. This is
supported by the IEA, which predicts that hydropower will make up 8% of
the 2040 US electricity mix, compared to the same value today. Similarly, the
share of geothermal energy will rise from less than 1% today to only 2% in
2040, despite advancements in decentralized geothermal heat and electricity
production.
The development of bioenergy remains uncertain
Bioenergy refers to plant-based matter used as an energy source and
comprises about 50% of the United States’ total renewable energy
consumption. Though it can be used to generate electricity as biomass or
agricultural waste, the majority of plant-based fuels are used in the
transportation sector as biofuels like biodiesel or ethanol. These are mixed
with fossil fuels or used as additives, sometimes providing a less polluting
alternative to crude oil. In 2005, the U.S. became the world’s largest biofuel
producer, and its biofuel market looks set to continue to expand as pollution
standards are tightened and tax incentives increase.
Even so, bioenergy comes with drawbacks: significant pollutant emissions,
plus the possible need for dedicated crops which could compete with food
for agricultural space. Bioenergy does represent a source of lower-carbon
energy2, but these problems threaten to mitigate its growth, despite the fact
that second-generation biofuels seek to reduce the impact they have.
Though large-scale hydropower projects can be met with opposition because they may displace local
populations or disrupt ecosystems, these issues are not particularly pertinent in the U.S. context.
1
2
The true carbon content of biofuels has proven somewhat controversial; some studies indicate that it is a lowcarbon fuel, while others indicate that it is as polluting fossil fuels when its lifecycle and land use changes are
taken into account. See Matthews et al. (2014), Searchinger et al. (2008), and Bowyer et al. (2013) for more
information.
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Mtoe
Figure 4: U.S. transportation fuel mix
Projections based on
the IEA 2°C scenario
800
700
600
500
400
300
200
100
0
1990 2000 2010 2020 2030 2040
Oil
Gas
Biomass
Source: Mirova / US EIA 2015
Wind and solar are the most viable candidates for large-scale
implementation in the coming years
Overall, wind and solar promise the highest growth potential of all
renewable energy sources in the U.S. This is due to their minimal social and
environmental externalities, abundant and easily accessible resources, and
falling costs. These factors represent major opportunities for development,
which looks set to increase from 10% of power generation today to 31% in
2040 in line with the IEA’s 2°C scenario.
Historical development of wind and solar
Wind and solar
represent the greatest
opportunity, and carry
the fewest negative
social / environmental
externalities.
The heterogeneous levels of growth in wind and solar power across states
are typically attributed to utility regulatory structures, large domestic fossil
resource deposits, and a shifting political landscape. Firstly, each of the 50
states regulates its utilities independently, many with starkly differing
practices. Secondly, regulations mandated at the federal level can face a slow
adoption process, or may be challenged by utilities and/or state legislatures,
both of which have a potential economic interest in preserving their states’
fossil fuel-related activities. Finally, given the highly politicized nature of the
climate debate in the U.S., it is often assumed that state politics have a clear
impact upon state renewables policy and development, though the
relationship is not as simple as Democrats versus Republicans.
Neither resource diversity nor politics entirely explain the variation
The U.S. territory is vast and diverse in resources, both fossil and renewable.
While one might expect that any unevenness in the state-by-state
development of renewables would be attributable only to differences in solar
and wind availability, this is not necessarily the pattern that has determined
the varying degrees of renewable energy advancement among states.
Interestingly, renewable capacity developments do not appear to be linked
to the dominant ideology in a particular state either. Whether this is
primarily due to limited state-level public involvement or the increasing
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appeal of renewables to both parties is difficult to discern. So the
development of renewables in a particular state cannot be predicted reliably
on the basis of politics or resource availability alone.
Florida, for instance, has significant solar resources but supporting policies
lag, perhaps in part due to the strong presence of utilities in the political
sphere3. Though often considered a stronghold of conservatism, Texas has
embraced renewables for long-term cost savings, though another
explanation could be that the free market ideals embodied by decentralized
energy generation are highly compatible with the state’s ideological base.
Accordingly, the state is endowed with the largest wind energy potential in
the U.S. and has developed it extensively.
Massachusetts, however, is one of the top five states in terms of solar
capacity installed; though it lacks strong solar resources, the state’s
progressive culture has led to active participation in the energy transition.
Lastly, California possesses strong political will plus large solar and wind
resources, a combination which has made it the American leader in
renewable energy.
Figure 5: Wind, state-by-state
Average wind potential (kWh/m2)
Wind as percent of in-state generation
Source: Mirova / US EIA 2015/ NREL 2016 / Carto
3
See Florida Center for Investigative Reporting, 2015 and Dickinson, 2016.
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Figure 6: Solar, state-by-state
Average solar potential (kWh/m2/day)
Solar as percent of in-state generation
Source: Mirova / US EIA 2015 / NREL 2016/ CartoDB
Despite these differences, however, strong trends are still very much evident
in the aggregated view. The observed growth and year-to-year fluctuations in
wind and solar installations can be explained, by cost reduction and
regulatory support.
The solar market has grown rapidly and steadily in recent years, while wind
is a slightly more mature market subject to greater variation. In 2015, wind
made up 41% of total annual new capacity additions, a significant increase
from 26% in 2014. Solar represented approximately 26% of annual capacity
additions in both 2014 and 2015.
Figure 7: historic U.S. wind and solar market development
Wind
14
Annual Capacity Installed (GW)
Annual Capacity Installed (GW)
Solar
12
10
8
6
4
2
0
2004
2006
2008
2010
2012
2014
14
12
10
8
6
4
2
0
2004
2006
2008
2010
2012
2014
Source: Mirova / US EIA 2016
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Cost reduction and regulation are driving the
development of renewables
The combination of cost reduction, policy, and regulation has made
renewables increasingly attractive to developers, investors, and the general
populace.
There are currently three main types of support for renewables in the US:
Cost reduction, policy,
and regulation have
made large-scale
implementation of
renewables more and
more viable.
−
Power purchase agreement (PPA): often essential to secure
financing, a PPA is a long-term contract between an electricity
generator and a purchaser which secures a steady revenue stream
from the sales of electricity over a set period. It allows a company to
host a solar or wind power system at no upfront cost.
−
Renewable Portfolio Standards (RPS) and Renewable Energy
Certificates (RECs): regulatory standards which mandate sourcing a
fixed portion of a state’s electricity from renewables (RPS) give rise to
the green power market, which then depends on the purchase and
sales of RECs.
−
Fiscal policy:

ITC and PTC: the Investment Tax Credit (ITC) is a one-time credit
of 30% of installed costs typically applied to solar projects, and the
Production Tax Credit (PTC) is ten-year production-tied credit
typically applied to large-scale wind ($23/MWh). These are the
best-known and influential drivers of renewable energy
development in the United States.

Modified Accelerated Cost Recovery System (MACRS): an
accelerated depreciation scheme which can lead to significantly
less tax liability upfront and potentially over the project’s lifetime..
The following case studies serve to demonstrate the financial implications of
the aforementioned schemes on a renewable energy project.
Two case studies
Illustrative case study 1: California, utility-scale solar
Utility-scale solar
depends on PPAs, the
ITC, and RECs, but
decreases in capital
cost signal that it will
continue to become
increasingly
competitive alone.
Given that nearly half of the U.S. solar capacity is situated in California and
more than half of this is utility-scale, utility-scale solar plants in California
are a relevant example of implementation of solar energy in the U.S.
U.S. solar capacity, 2015
Rest of US
Solar PV
(Utility-Scale)
Massachusetts
California
Nevada
Solar Thermal
(Utility-Scale)
North Carolina
Solar PV
(Distributed)
New Jersey
Arizona
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It is evident that the Investment Tax Credit, the sale of solar RECs, and PPAs
are instrumental for the economic feasibility of solar power, and its
profitability still relies on power purchase agreements somewhat above
market price.
The figure below therefore sets electricity prices at $65/MWh
(representative of an average PPA at the end of 2014), allowing the plant to
be profitable with the help of the ITC and REC sales. Since PPAs often include
the purchase of RECs, RECs and a PPA do not necessarily contribute
separately to a project’s revenues.
Estimation of solar project expenses and revenues
Tax avoided due to MACRS
MACRS
State Incentives (California)
Value created Tax
MACRS
Federal Incentives (PTC)
Electricity Sales (PPA addition)
Tax
Interest
Tax
Interest
O&M
Interest
O&M
O&M
Capex
Capex
State Incentive
State Incentive
Capex
Federal Incentives (ITC)
Federal Incentives (ITC)
Electricity Sales (PPA additio
Electricity Sales (market price)
Electricity Sales (PPA addition
Electricity Sales (market pric
Electricity Sales (market price)
Revenues
Revenues
(without
(without
incentives)
incentives)
Revenues
Revenues
(with
(with
incentives)
incentives)
Expenses
Expenses
Assumptions: $65/MWh PPA; ITC at 2016 levels; $1.5/WDC installed system cost; 28% capacity factor;
$19/kW/year O&M cost factor; 6.6% WACC; $28/MWh wholesale electricity price; tax equity investor with
sufficient appetite to use any generated tax credits in same year of production
Source: Mirova / US EIA 2016/ DSIRE 2016/ US NREL 2015
Illustrative case study 2: Texas, onshore wind
Texas possesses nearly 25% of the U.S. wind generation capacity and is
therefore a representative example of a location which facilitates the growth
of wind power.
Wind power in Texas,
already nearly
competitive at market
price, is only made
more attractive by the
PTC.
U.S. wind capacity, 2015
Texas
Rest of US
Iowa
California
Illinois
Kansas Oklahoma
The PTC remains a major contributor to the economics of wind power as it
begins to approach grid parity. Even with an electricity price of $30/MWh (as
modeled below, based on the average PPA price in 2014), only a few dollars
higher than the wholesale price in Texas, significant value is created for
shareholders.
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As costs (particularly capex) continue to fall, onshore wind power will thus
continue its current trajectory and will become increasingly competitive with
other energy sources.
Interest
O&M
Capex
Estimation of wind project expenses and revenues
Tax avoided due to MACRS
Value created
Tax
Tax Tax
MACRS
InterestMACRS
Interest
Federal Incentives (PTC)
Federal Incentives
(PTC +(PPA
MACRS)
Electricity Sales
addition)
O&M Interest
O&M
Electricity Sales (PPA addition)
Revenues
(without
incentives)
Revenues
(with
incentives)
O&M
Capex
Capex
Federal Incentives (PTC)
Capex Federal Incentives (PTC)
Electricity Sales (PPA addition)
Electricity
Sales
(PPA
addition)
Electricity
Sales
(market
price)
Electricity Sales
Sales (market
(market price)
price)
Electricity
Expenses
Electricity Sales (market price)
Revenues
Revenues
(without
(without
incentives)
incentives)
Revenues
Revenues
(with
(with
incentives)
incentives)
Expenses
Expenses
Assumptions: $30/MWh PPA; ITC at 2016 levels; $1.3/W installed system cost; 45% capacity factor;
$30/kW/year O&M cost factor; 5.2% WACC; $28/MWh wholesale electricity price; tax equity investor with
sufficient appetite to use any generated tax credits in same year of production
Source: Mirova / US EIA 2016/ DSIRE 2016/ US NREL2015
These case studies indicate that wind is on track to become fully competitive
with other fuels, even without policy aids, while solar still needs to improve
its cost structure in order to become completely independent from
regulatory support. It is worth noting, however, that with the relatively low
wholesale electricity prices in the U.S. (down 27-37% across the country in
2015 compared to 2014 and trending around $25/MWh, largely due to low
natural gas prices) even some fossil-fuel plants are straining to remain
competitive at market price.
Cost reduction is taking place rapidly
While hardware costs
of wind and solar are
decreasing, soft costs,
like labor, site
preparation, and
financing, remain
significant.
High costs tend to be the first argument employed against renewables and
have been a major barrier for installing on-site generation capacity.
However, the relatively fast deployment of renewable technologies, high
learning rates, and government subsidies have been reducing costs for
installers rapidly in recent years. This implies that renewables will continue
to become increasingly competitive with fossil fuels.
Solar photovoltaic is still relatively costly, but its price is dropping4
Costs for solar installations are split fairly evenly between hardware and soft
costs. Hardware costs derive from an often-complex supply chain due to the
highly materials- and labor-intensive manufacturing process required to
produce the PV module, as well as the necessary electrical and structural
components often referred to as the balance of system (BOS). Soft costs
include permitting, labor, site preparation, grid connection, financing, and
installation fees.
All figures henceforth will reference polycrystalline PV cells, which represent the majority of the market.
Concentrated solar power will likewise be omitted as it comprises a small portion of recent capacity additions.
4
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Figure 8: Breakdown of solar PV installed costs (poly. silicon, 2014)
Cost per watt ($/W)
3.5
Customer acquisition,
permitting, tax, etc.
3
2.5
Installation labor
2
1.5
BOS
1
Inverter
0.5
0
5 kW
200 kW
Residential Commercial
100 MW
Utility
(fixed)
100 MW
Utility
(single-axis)
Module
Hardware costs, including the module, inverter, and other electrical components, make
up 35-40% of the capital cost for PV systems. Soft costs are generally 40% for largescale systems and 55-60% for small-scale or residential systems.
Source: Mirova / NREL2015
Photovoltaic technology is relatively new, and still has significant potential
for improvement. As a result, module costs have historically provided the
greatest opportunity for cost reductions. These costs decreased by 75%
between 2009 and 2014, mostly due to decreasing polysilicon prices,
advances in technology, and economies of scale. Efficiency alone represents a
major opportunity for continued progress; since improved efficiency means
more electricity produced per same panel area, it has a direct impact on
capital costs. As the technology matures, decreases are slowing, which
emphasizes the need for further optimizing BOS and soft costs.
Capital costs ($ / W DC)
14
250
12
200
10
8
150
6
100
4
50
2
0
0
Average PPA price ($ / MWh)
Figure 9: Evolution of solar prices
1999 2001 2003 2005 2007 2009 2011 2013
Module ($/W DC)
Installed Price ($/W DC)
PPA ($/MWh)
Source: Mirova / US DOE 2014-2015 / US NREL 2013
Wind hardware costs are likewise diminishing due to greater
economies of scale
Wind-based power generation technology is relatively mature; the principal
components and functions are similar to other means of power generation.
As a result, the variation in technology employed by wind projects is
relatively low.
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Capital costs for wind power consist mainly of hardware (the turbine and all
its components) and soft costs like construction, grid connection, planning,
and financing. Civil works, grid connection, and planning costs tend to be
significantly higher for offshore wind projects than onshore due to greater
difficulty of access.
Turbine cost breakdown
Nacelle / Drivetrain
Pitch Mechanisms
Hub and Nose Cone
Blades
Tower
Control and Safety
Cost per kilowatt ($/ kW)
Figure 10: Breakdown of wind installed costs, 2014
5000
4000
3000
2000
1000
0
Onshore
Wind turbine
Civil works
Offshore
Grid connection
Planning and other
Turbine cost represents 64-84% of the capital costs of onshore projects but 3050% for offshore projects as grid connection, engineering, and construction costs
are much higher offshore.
Source: Mirova / US DOE 2015 / NREL 2013
Hardware cost again provides the largest opportunity for cost reduction.
Turbine prices have decreased significantly from their 2009 peak price, as
rotor diameters have increased and towers have become higher, allowing for
greater electrical output.
Figure 11: Evolution of commercial turbine diameters
Source : Mirova , based on company data
Increased economies of scale and competition have likewise contributed to
hardware cost reduction. Soft costs are largely related to financing and the
remoteness of the project, which represent limited opportunity; as
technology improves and the most suitable sites are developed, more remote
areas will be utilized, implying increased operating and soft costs.
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Figure 12: Evolution of wind prices
Capital costs ($/kW)
2500
80
70
2000
60
50
1500
40
1000
30
20
500
10
0
0
Average PPA price ($ / MWh)
Decrease in USD value compared to EUR, increased input prices, turbine and
component supply shortages, and up-scaling of turbine size.
1997 1999 2001 2003 2005 2007 2009 2011 2013
Turbine ($/kW)
Installed Price ($/kW)
PPA ($/MWh)
Source: Mirova / NREL 2013 / AWEA 2015
LCOE shows greater competitiveness, particularly for onshore wind
Levelized cost of energy (LCOE) allows for comparability between energy
systems and cost structures on a long-term basis; it is calculated by
accounting for all of a system’s expected lifetime costs and dividing them by
the system’s expected lifetime output.
For renewables, LCOE is highly dependent on region due to variations in
resource availability, incentives, and ease of grid interconnection. As a result,
within the U.S. the LCOE of solar and wind systems varies significantly. While
biomass, hydropower, and geothermal resources have provided electricity at
a price comparable to fossil fuels for several decades, the LCOE of onshore
wind has only recently proven itself lower than fossil fuels or the
aforementioned renewables. Despite this apparent competitiveness,
however, solar and wind LCOEs do not take costs of intermittency into
account, which could be costly, including measures to integrate these energy
sources into the grid and (potentially) storage. Meanwhile, offshore wind and
all types of solar still have significantly higher LCOEs than other fuels in the
majority of regions.
Figure 13: LCOE by technology, 2014
Solar Thermal
Wind - Offshore
Solar PV
Coal
Biomass
Hydro
Nuclear *
Gas
Wind - Onshore
Geothermal
0
100
200
300
LCOE ($/MWh)
Range shown represents regional variation. Assumption of 30 year cost recovery
period and 6.1% WACC; wind and solar apply only to utility-scale.
* this price level is still subject to uncertainty given the potential need for additional waste
and decommissioning provisions.
Source: Mirova / U.S. EIA 2016
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Policy and regulation
Even if prices are decreasing, wind and solar have relied on policy support
thus far. And while onshore wind is becoming competitive on its own, both
wind and solar continue to rely on these mechanisms for the moment.
In general, the structure of the U.S. government provides the federal
government with limited powers to impose stringent regulation upon states
and companies. Though guidelines can be outlined at the federal level, states
retain the ability to challenge these directives and control implementation,
again leading to the aforementioned heterogeneity in policies from one
region to the next (see annex 1 for an overview of the U.S. utility market).
Even so, there have been several regulatory measures implemented at the
federal level which promote the development of renewables, typically billed
as spurring domestic employment and energy security. These include the
U.S. Public Utility Regulatory Policies Act, the Energy Policy Acts of 1992 and
2005, the American Recovery and Reinvestment Act of 2009, and the 2015
Clean Power Plan.
The U.S. federal
government has
limited regulatory
power, made clear by
the current block of the
Clean Power Plan.
The Clean Power Plan seeks to reduce carbon pollution from electricity
generation over a 15-year period by implementing new standards for (coal)
power plants and emissions reductions goals state-by-state. When in place,
carbon pollution from power generation will be 32% below 2005 levels and
a fully-fledged emissions trading system will exist. As of February 2016, the
Plan was blocked in 27 states by the Supreme Court after it was challenged
on the basis of encroaching upon states’ rights. The final ruling is expected to
take place in late 2016, after the 2016 presidential election and nomination
of a new Supreme Court justice, which implies some risk for its future.
While the Clean Power Plan would positively impact renewables if it is
ultimately implemented, other types of regulations have already proven to be
highly influential. These include power purchase agreements, renewable
energy certificates, renewable portfolio standards, and federal tax incentives.
Power Purchase Agreements (PPAs) lock in above-market electricity
prices
Renewables operate at zero marginal cost, so their electricity can be sold at a
fixed price over the life of the project, typically via a PPA. These play a key
role in financing independent power producers, many of which are
renewables-focused, as well as renewable energy projects.
Generally, a PPA is a long-term agreement between the owner of a facility
which generates electricity and a wholesale energy purchaser. It allows the
facility owner to secure a revenue stream from the project, which is
necessary for financing, and useful if the purchaser wishes to ensure supply
security, when a small number of customers want the bulk of the generation,
when the project requires protection from cheaper competition, or when
revenues are uncertain, and some revenue guarantee is needed to make the
project viable.
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Figure 14: Leaders in renewable energy capacity built via PPAs
MW
Power purchase
agreements and the
green power market
are key drivers of
development in many
states.
2000
1800
1600
1400
1200
1000
800
600
400
200
0
Source: Mirova / Bloomberg New Energy Finance 2016
The advantage of a PPA is that it allows a company (or the government) to
host a wind or solar power system with zero upfront costs for the buyer
itself. A developer builds a system that can be financed by a tax equity
investor who thereby becomes eligible for the associated tax benefits. The
company then pays potentially above-market rates for the electricity (and
RECs) over time, which helps the developer and investor recoup their costs.
This structure allows for the construction of large-scale solar projects
without the need for capital budget allocation by the government/company.
PPAs vary in terms of the length of the agreement (though typically 15-25
years), the commissioning process, the purchase and sale of renewable
energy certificates, price, and insurance. Finally, there are different iterations
of PPAs: offsite solar PPAs, which include a solar installation offsite shared by
multiple users; offsite corporate wind PPAs, which provide power to
corporate customers with high energy loads; rooftop PPAs, essentially a
rooftop solar lease which relieves homeowners of large upfront payments;
and utility PPAs, in which utilities or large power traders purchase electricity
from generators.
Renewable Energy Certificates (RECs) have facilitated development
of the green power market
Since it is impossible to track the electrons generated by renewable sources
individually, the U.S. renewable power market is instead based on tradable
renewable energy certificates (RECs), which make it possible to account for
the positive environmental impacts of renewable energy. These are only
generated by the energy sources with the fewest negative social and
environmental impacts: solar, wind, geothermal, small-scale hydro and
biomass.
For each megawatt-hour (MWh) produced, a grid-tied renewable electricity
generator produces two separate products: one MWh of physical electricity
and one REC, which represents its positive environmental externalities. The
generator can sell these two products together or separately, thus choosing
whether to keep the RECs for themselves and claim the environmental
benefit or sell them.
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There are two separate markets for RECs, the voluntary market and the
mandatory market. The voluntary segment consists of companies wishing to
claim environmental benefit and customers seeking to offset the negative
environmental effects of the electricity they use themselves; the mandatory
segment consists of entities seeking to fulfill regulatory requirements like
Renewable Portfolio Standards. The voluntary market represents about 25%
of the total U.S. renewable power market, while the mandatory market
represents the remaining 75%.
REC prices vary depending on region and resource type, but typically wind
RECs lie between a few cents and a few dollars per MWh, representing 10%
or less of the wholesale cost of electricity, while solar RECs (SRECs) are
usually bought and sold at much higher prices ($40-100/MWh, often
significantly higher than wholesale prices). This discrepancy comes from
specific state goals which encourage solar, the high above-market cost of
solar, and the desirability of SRECs on the voluntary market. For this reason,
sale and self-generation of RECs, particularly SRECs, can lead to significant
recuperation of expense recoupment.
Renewable Portfolio Standards (RPS) provide binding targets for
implementation of renewables state-by-state
The ITC and PTC are
the most famous and
perhaps the most
influential incentives
available.
By far the most widespread and influential state-level policies are Renewable
Portfolio Standards (RPS), which intertwine the renewable energy certificate
market and regulation. RPS effectively created the mandatory market for
RECs, requiring utilities to provide a specified percentage of electricity from
renewable resources, either through self-generation or purchase of RECs.
There is currently no RPS program at the national level, but 30 states have
enacted enforceable standards ranging in ambition, approved technology,
and timeframe.
Some examples of this variation include the particularly ambitious RPS are
present in California, which seeks to obtain 50% of its power from renewable
sources by 2030, and Hawaii, which looks to obtain 100% by 2045. Illinois’
standards, however, are technology-based, and stipulate that 25% of
renewable power (6% of total) must be obtained via solar and 75% from
wind in 2016. North Carolina’s standards are demarcated between investorowned utilities (12.5% renewables by 2021) and municipalities (10% by
2018).
Federal tax incentives, namely the ITC and PTC, deserve much of the
credit for recent growth in wind and solar installations
Subsidy and tax incentives constitute a large part of federal support for
renewables and act to reduce the cost of installation for individuals,
companies, and institutions. As such, energy-related subsidies increased
nearly 40% between 2010 and 2013, largely due to an increase in support
for renewable energy. In 2013, renewables received the greatest share of
direct federal subsidies and support, totaling 72% of all such subsidies. More
than two-thirds of these subsidies were direct or tax expenditures targeting
up-front capital investments for projects expected to produce energy for at
least 20 years.
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Tax expenditures typically lead to a special credit, preferential tax rate, or
deferral of tax liability. In 2013, this type of subsidy represented an
expenditure of $12.4 billion total (42% of total energy subsidies and
support), 44% of which went to support renewable energy sources. The two
tax expenditures considered to have sizeable impact on the development and
deployment of renewable energy in the U.S. are the Business Energy
Investment Tax Credit (ITC) and the Renewable Electricity Production Tax
Credit (PTC). Both of these allow certain taxpayers to subtract the amount of
the credit from the total they owe the state, thus significant tax liabilities are
required to fully benefit from these credits. The Modified Accelerated Cost
Recovery System can also lead to consequential effects on a company’s tax
liabilities.
 The ITC has proven especially beneficial for utility-scale solar
The ITC began in 2005, but greatly expanded in 2008 as part of the Energy
Improvement and Extension Act, again in 2009 as part of the American
Recovery and Reinvestment Act, and was extended recently until the end of
2019, with a phase-out period between 2019 and 2023. It applies to solar
photovoltaics, fuel cells, small wind turbines, geothermal, and combined heat
and power. It provides a credit for 10% (geothermal, CHP) or 30%
(solar, small wind, and fuel cells) of all installed costs. The credit is
applicable to commercial, industrial, agricultural, and utility sectors, and it
should be noted that it is the sole federal tax credit currently available to
commercial solar facilities. As such, it has been hailed as widely successful in
promoting the development of solar, particularly utility-scale.
 The PTC favors development of large-scale wind systems
The PTC was established by the Energy Policy Act of 1992. Since then, it has
been extended in one- or two-year intervals, and recently received another
extension (with phase-out) to the end of 2019. This unpredictability has been
cause for consternation in the industry as capacity additions tend to drop
sharply as an expiration date approaches.
Annual Capacity Installed
(GW)
Figure 15: historic U.S. wind capacity additions
14
12
10
8
6
4
2
0
PTC expiry
-92%
PTC extension
-92%
1998
-76%
2000
2002
-76%
2004
2006
2008
2010
2012
2014
Source: Mirova / US EIA 2016
The PTC allows owners of qualified renewable energy facilities to receive tax
credits for each kWh of energy generated by the facility over a 10 year
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period. Under the full PTC, owners receive 2.3 cents/kWh for the
production of electricity from utility-scale wind turbines, geothermal
resources, or closed-loop biomass systems, or 1.1 cents/kWh for other
biomass and small-scale hydroelectric sources. Even so, this credit has
been used primarily for large-scale wind energy systems.
 The Modified Accelerated Cost Recovery System can also lead
to less tax liability, especially coupled with the ITC / PTC
Along with the ITC and PTC, the Modified Accelerated Cost Recovery System
(MACRS) has helped to fuel recent growth in annual renewable energy
installations. It allows investments in renewable energy property to be
partially recovered over five years through annual tax deductions, leading to
greater market certainty and an accelerated rate of return on solar and wind
investments. Recently, bonus depreciation under MACRS was extended,
allowing companies to depreciate 50% of the basis during the first year,
before the rest depreciates over the usual five-year period. The bonus
depreciation policy is nevertheless set to be phased out beginning 2017.
Numerous other
incentives also
contribute to
ultimately making
renewables both
financially and
environmentally
attractive.
Use of the tax credit funds to immediately offset existing tax liability leads to
a significantly greater net present value of the incentive (approximately 57%
of CAPEX; 30% PTC and 27% MACRS) than if the credit is used to offset tax
liabilities incurred only once the project becomes profitable (about 31% of
CAPEX; 10% PTC and 21% MACRS)5. For this reason, large utilities with
existing tax appetite are able to use the incentive far more effectively than
smaller entities without the ability to immediately apply the credit; the latter
would likely derive more benefit from direct subsidies or grants.
Other types of regulation have also impacted renewables
In addition, there are many other types of policy and regulation which have
impacted renewables. These are presented in appendix II and include
−
State-level incentives and policies, including direct and tax subsidies,
feed-in tariffs, net metering, and interconnection standards;
−
Direct federal subsidies.
Review of project cash flows
With the current price structure and all of these incentives employed, a
positive cash flow is obtained within the first few years of plant operation.
This is in part due to the application of MACRS and the PTC/ITC (see case
studies on pages 10 and 11). Since depreciation is treated as a deduction
from taxable income, it eliminates the projects’ relatively small annual
income tax expense and typically leads to net operating loss. Thus these
projects have greater tax savings early in their lifetime, increasing the
incentive to invest and increasing the likelihood of non-negative cash flow.
5
See Bolinger, 2014.
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Million USD
Figure 16: Wind case study cash flow diagram
Expiration of the PTC
150
Tax
100
Dividends
Change in Net Debt
Cash Flow
50
Interest
0
O&M
-50
Federal Incentive
-100
Electricity Sales
Annual Cash Flow
-150
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20
Source: Mirova
Individual Cash Flows
Million USD
Figure 17: Solar case study cash flow diagram
6
4
Tax
Dividends
2
Change in Net Debt
0
Interest
O&M
-2
Electricity Sales
Annual Cash Flow
-4
-6
1
6
11
16
21
26
Each of these diagrams follows the same set of assumptions as the case studies: see page 10 for the
parameters applicable to solar and page 11 for those applicable to wind. Assumptions include
financing with 80% debt and 20% equity; all value created is attributed directly to shareholders.
Source: Mirova
Renewables and the marketplace
With an understanding of the mechanisms driving development of
renewables, the following turns to the value. This is particularly pertinent as
the wind and solar value chains diverge somewhat from those of other fuels
for power generation; understanding these value chains allows for deeper
insight into both present and future industry challenges, opportunities, and
risks.
The solar value chain
The solar value chain is
international and
depends on a highly
capital-intensive cell
manufacturing
process.
The solar value chain is international and consists of three major steps:
manufacturing, installation, and operation, though the process and the actors
involved vary slightly depending on the type of technology employed. Here,
the focus will be on polycrystalline solar cells as they make up the majority of
the market. However, monocrystalline silicon, thin film, and concentrating
solar power chains diverge somewhat, particularly in manufacturing.
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For polycrystalline solar cells, the manufacturing process is multi-step:
−
Silicon production. Silicon, a semiconductor, is the raw material for
photovoltaic cells. The first step in creating a solar panel is production
of ultrapure silicon, which takes place in two stages: the
transformation of quartz or sand into metallurgical-quality silicon, then
its purification into solar-grade/polycrystalline.
−
Wafer production. Before being transformed into photovoltaic cells,
the purified silicon must be transformed into a large ingot, and then cut
into slices. These slices are called “wafers.”
−
Cell production. The wafers must be chemically treated and metallic
parts must be added for them to become cells.
−
Module production. A single cell does not generate much electricity,
so many cells are assembled into a module, which produces greater
quantities of electricity and includes a protective structure.
Though some of the largest silicon / cell / module producers are vertically
integrated, manufacturing of a complete panel ready for balance of system
(BOS), installation, and grid integration, does not necessarily take place at a
single factory site, or even within a single company. Instead, it is often
distributed between two or three: one to produce the ultrapure silicon
required, often another to treat this silicon such that it becomes appropriate
for PV applications, and potentially a third to fuse these cells together into
modules. This is largely due to the split in capital intensity between cell and
module manufacturing: cell manufacturing is highly capital-intensive ($1-2
million / MW of plant capacity), while module/panel production is less so,
allowing it to be either done on-site at the cell producer or closer to the endmarket by smaller local players. The market for BOS elements, including the
inverter and its associated electrical components, is dominated by a few
large players.
The majority of global solar cell production takes place in China, while the
majority of solar cell installations take place in the U.S. and Europe. In China,
production of solar cells is significantly less expensive than in the United
States ($0.91 versus $1.19), attributed to less strict regulation, lowered
environmental standards, and inexpensive labor. From a social and
environmental point of view, this poses risks, particularly as Chinese
companies are not held to high standards of transparency.
Installation represents low capital costs but high labor costs. As a result, the
market for installers tends to be regional and fragmented. Though some
concern must be paid to worker and site location, installation of solar power
usually provides a positive impact on local economic, social, and
environmental value creation with minimal inherent risk.
Finally, utilities can purchase the panels and use it to generate power to sell
into the grid, or homeowners mount residential PV systems. Some companies
lease rooftop space from residents and sell them the resulting power at a
lower rate than the local utility.
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Figure 18: Solar value chain and market leaders
Manufacturing
Raw material (ultrapure silicon) production and
processing
Silicon wafer manufacturer
Creates cells by adding contacts, coatings, and
alteration
of the (ultrapure
wafer
Raw material
silicon) production and
Raw material (ultrapure silicon) production and
processing
processing
Solders cells together and applies frames for mounting
Creates cells by adding contacts, coatings, and
Creates cells by adding contacts, coatings, and
Cell producers
alteration of the wafer
Cell producers
alteration
wafer
Cell
/
Module
Producers
(shareofofthe
U.S.
residential
2014)
Top cell and/or module producers
Top U.S.market,
inverter
vendors
Solders cells together
andMW
applies
frames for2014)
mounting
Yingli(by
Green
(% U.S.Module
residential
market,
2014)
shipped,
Module
producers
ac
Solders cells together(China)
and applies frames for mounting
producers
Manufacturing
Cell producers
Manufacturing
Silicon wafer manufacturer
Silicon wafer manufacturer
Module producers
Others
35%
17%
Trina Solar (share of U.S. residential market, 2014)
Cell//Module
ModuleProducers
Producers
Cell
market, 2014)
SMA
Others
(China) (share of U.S. residential
24%
Yingli Green
ABB
Yingli Green
Trina Solar
(China)
(China)
19%
(China)
Others
17%
Others
17%
17%
35%
35%
ReneSola
Yingli
Green
(China)
(China)
Sharp (Japan)
4%
ReneSola
Trina
Solar
Trina
Solar
17% (China)
17% Canadian Solar
(China)
(China)
JinkoSolar
Advanced
Others
(China)
17%
4%
17%
(China)
Energy
26%
6%
4%
ReneSola
ReneSola
Sharp Solar
17%
Canadian
(China)
(China)
(Japan)
Enphase
SolarEdge
Solar
(China)
Sharp
(Japan)
Sharp (Japan)
4%
SunPower
4%
4%
Technologies Energy
6%
17%
17%
Canadian
Solar
Canadian
Solar
(U.S.)
JinkoSolar
JinkoSolar
8%
(China)
(China)
6%
17%
(China)
(China)
6%
6%
Puts modules
into array structure, adds essential
4%
4%
35%
17%
Installation
BOS
electrical components for grid connection (i.e. inverter)
Installs modules in their final location, integrates with
the
grid
Puts
modules
structure,
adds
essential
Puts
modulesinto
intoarray
array
structure,
adds
essential
electrical
forfor
grid
connection
(i.e.
inverter)
electricalcomponents
components
grid
connection
(i.e.
inverter)
Installation
Installation
Integration and installation
BOS
BOS
Installs
final
location,
integrates
with
Installsmodules
modulesinintheir
their
final
location,
integrates
with
Integration
and
installation
Integration
and
installation
Installers
(Utility
by MW, 2014)
Installers (Residential by MW, 2014)
the
thegrid
grid
Solar
Total All(utility-scale
Others
Installers
by MW,First
2014)
38%
Installers
(Utility
44%
Installers
(Utilityby
byMW,
MW,2014)
2014)
First Solar
Total All Others
First Solar
First Solar
Total AllTotal
Others
All Others
38%
44%
Carolina
NRG Energy
38%
38%
44%
44%Solar
Energy
13%
Hanwha Q
1%
FLS Energy
CELLS
2%
2%
Carolina Solar
NRG Energy
Solar
NRG
Energy
CarolinaCarolina
Solar
NRG Energy
Energy
13%
Hanwha Q
13%
Energy Energy
13%
1%
FLS
Energy
Hanwha
Q
Hanwha
Q
CELLS
1%
FLS2%
Energy
1%
FLS Energy
CELLS
2%
2%
Operation CELLS
2%
2%
2%
Others
SolarCity
Installers
42% (residential by MW, 2014)
34%
Installers
(Residential
byby
MW,
2014)
Installers
(Residential
MW,
2014)
Others
SolarCity
Others
SolarCity
SolarCity
Vivint
Solar
Next 42%
5Others
42%
34%34%
34%
11%
Installers42% c
Sunrun
6% NRG Home
3%
Solar Sungevity
Vivint
Solar
5
Vivint
Solar
NextNext
5Next
2%
2%
Vivint Solar
Installers5
11%11%
Sunrun
Installers
11%
Installers
Sunrun
6%
Sunrun
Home
6% NRG
6%NRG
Home
3% 3%
NRG
Home
Sungevity 3%
SolarSungevity
Solar Solar Sungevity
2%
2%
2% 2% 2% 2%
Generates power (and SRECs)
Utility / IPP
Operation
Operation
Homeowner
Use the electricity themselves or sell it back onto the grid
Generates power (and SRECs)
Utility / IPP
Generates power (and SRECs)
Utility / IPP
Leases panels to commercial / residential establishments
Solar equipment lease
Use
the electricity themselves or sell it back onto the grid
Homeowner
Use the electricity themselves or sell it back onto the grid
Homeowner
Utilities (by
total installed
capacity,
2014) establishments
Leases
panels to solar
commercial
/ residential
Solar equipment lease
Leases panels to commercial / residential establishments
Solar equipment lease
Pacific Gas
Utilities (by total installedand
solar
capacity, 2014)
Electric
Others
Utilities
(by total installed (CA)
solar capacity, 2014)
39%
28% capacity, 2014)
Utilities (by total installed solar
Pacific Gas
Others
39%
Others
Others
39%
39%
Duke Energy
Progress (NC)
2%
Public
Service
Duke Energy
Electric &(NC)
Gas
Progress
Company
(NJ)
Duke
Energy
2%
Duke
Energy
4%
Progress
(NC)
Progress
(NC)
Public Service
2%
2% & Gas
Electric
PublicService
Service
Company
(NJ)
Public
Electric
Gas
4%&&Gas
Electric
Company (NJ)
Company (NJ)
4%
4%
andPacific
ElectricGas
Pacific Gas
(CA)Electric
and
and
Electric
Southern
28%
(CA)
(CA)
California
28%(CA)
28%
Edison
14%
Southern
California
Arizona Public
San Diego
Southern
Southern
(CA)
Service (AZ) Gas &Edison
Electric
California
California
14%
5%
(CA)
Edison
Edison(CA)
(CA)
8%
Arizona Public
14%
San Diego14%
Service (AZ) Gas & Electric
Arizona
5% Public
(CA)Diego
Arizona
Public San
San
Diego
Service (AZ)
& Electric
8%
Service
(AZ) Gas
Gas
& Electric
5%
(CA)
5%
(CA)
8%
8%
Source: Mirova / SEIA 2015/ Solar Power World 2015 / SEPA 2015
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The wind value chain is
more straightforward,
and turbines’ size
favors decentralized
manufacturing.
The wind value chain
The wind value chain consists of manufacturing, installation, and operation
steps. After obtaining the raw materials necessary (including steel, cast iron,
fiberglass, rubber, concrete, and aluminum) from individual suppliers,
component manufacturers create the turbine, including the blades, tower,
drivetrain, and/or generator. Compared to solar modules, manufacturing
turbines is relatively straightforward, if capital intensive, although the large
product size means market access is somewhat limited by factory location.
Figure 19: Wind value chain and market leaders
Manufacturing
Manufacturing
Raw materials
Raw materials
Component manufacturers
Component manufacturers
Raw materials include steel, cast iron, fiberglass, rubber,
Raw materials
include steel, cast iron, fiberglass, rubber,
concrete,
and aluminum
concrete, and aluminum
Create turbines: blades, tower, nacelle (drivetrain), and/or
Create blades, tower, nacelle (drivetrain), and the
generator
generator
Turbine producers
Turbine producers
Producers
(share of U.S.
market,
2014)
(share ofTurbine
U.S. market,
2014)
(share
of U.S.
market, 2015)
Turbine Producers (share of U.S. market, 2014)
Nordex
Nordex Gamesa
Nordex
(Germany)
(Germany) (Spain)
Vestas
(Germany)
1.9%
1.9%
Vestas
0.5%
(Denmark)
1.9%
Vestas
(Denmark)
12.0%
(Denmark)
12.0%
12.0%
Siemens
(Germany)
25.6%
Gamesa
Gamesa
(Spain)
(Spain)
0.5%
0.5% Gamesa
Others
16.8%
(Spain)
5.9%
Siemens
(Germany)
GE Wind
14.9%
GE Wind
GE Wind
Siemens
Siemens
(USA)
(Germany)
(Germany)
60.0%
25.6%
25.6%
GE Wind
(USA)
42.5%
(USA)
(USA)
60.0%
Vestas
60.0%
(Denmark)
19.9%
Installation
Installation
Project
Project Development
Development
Carries
regarding project
project feasibility,
feasibility, land
land
Carries out
out studies
studies regarding
leasing,
community effects,
effects, and
and biodiversity
biodiversity
leasing, grid
grid access,
access, community
Integration
Integration and
and installation
installation
Installs
in their
their final
final location
location and
and integrates
integrates
Installs components
components in
with
with the
the grid
grid
Operation
Operation
Operates
maintenance on
on the
the turbines
turbines
Operates and
and performs
performs maintenance
Utility
Utility // IPP
IPP
Utilities (by total installed wind capacity, 2014)
Utilities
installed
wind
capacity, 2014)
2014)
Utilities (by
(by total
totalXcel
installed
wind capacity,
Energy (MN)
11%
Others
Others
Others61%
61%
61%
Xcel
Berkshire
Berkshire
Xcel Energy
Energy
Berkshire
Southern
Hathaway
Energy
(MN)
Hathaway
(MN)
Hathaway
California Edison
(IA) (IA)
11%
Energy
11%
Energy
(CA)
9% (IA)
9%
9%
6%
Southern
Southern
American
Electric
California
California
Power
(OH)
Edison
(CA)
Edison
(CA)
4%
American
6%
PacificAmerican
Gas &
Electric
Power
Electric
Electric
(CA)Power
(OH)
& 4% (OH)
Pacific Gas &
4%
4%
(CA) Valley
San Diego GasElectric
&
Tennessee
(CA)
Electric (CA)
4%Authority (TN)
2%
3%
Tennessee
Tennessee
Valley Authority
Authority
Valley
San Diego Gas
(TN)
(TN)
& Electric
(CA)Mirova / AWEA2015 / NREL 2016
Source:
3%
3%
2%
Though the world’s largest wind turbine manufacturers are in China, they
occupy very little of the U.S. market share. This is because nacelles, blades,
and towers are large and expensive to ship, especially if not entirely on
ocean-going vessels. Most areas of high U.S. wind potential are in the
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Focus
country’s interior, so land transportation of the turbine components is
necessary after arrival at the seaport. As a result, 88% of the wind capacity
installed in the U.S. in 2015 used a turbine supplier with at least one
domestic manufacturing facility. Vestas, for example, operates manufacturing
plants in Colorado, conveniently located near areas of high wind potential.
Installation again leads to relatively low capital expenditures but potentially
high permitting and labor costs, depending largely on the remoteness of the
installation. Installers tend to be numerous and vary by region, and must be
careful to continuously ensure worker safety. Installation of wind turbines
represents low inherent environmental or social risk, though onshore wind
does have more potential than solar to cause community disturbance
through noise and shadow. Ultimately, utilities or independent power
producers operate the turbines; few homeowners or commercial
establishments are able to implement on-site wind power due to space and
licensing restrictions. Maintenance is increasingly being undertaken by the
manufacturer through lifetime contracts.
Conclusion
Regulation and government policies play a crucial role in the development of
renewables in the U.S., as evidenced by the steep decline in wind capacity
installations each time the PTC is set to expire, and by the contribution
MACRS and tax credits make to the financial feasibility of wind and solar
projects. Given the recent and relatively long-term extensions of the
influential ITC and PTC, short-term prospects for continued development of
the American renewable energy market are positive, particularly at the end
of the value chain. Large utilities are able to take full advantage of the tax
credits and RPS to increase the profitability of their wind and solar projects.
Utilities which position themselves as leaders in facilitating access to
renewables, whether utility- or residential-scale, will thus be positively
situated from economic and regulatory standpoints.
Excluding major
political or economic
shock, renewables
seem set to continue
their conquest of the
American electricity
mix.
Within the intermediate steps of the value chain, solar represents more
technological opportunity for improvement than wind as it is less mature.
Efficiencies of solar modules continue to increase and new (non-silicon) cells
are being continuously developed: though thin-film cells have been falling
from favor, very rapid advances are being made in perovskite and
heterojunction cells. As a result, the likelihood of new players entering the
market with a larger variety of technologies is high in the mid-term. For
silicon cell producers, prices will likely continue to fall, leading to more
competitive prices, greater competition between existing manufacturers on
price, and greater implementation (as solar still remains relatively
expensive). However, the solar supply chain comprises many overseas
players with low transparency and frail regulatory frameworks, making its
detailed analysis outside the scope of this paper.
Given that wind turbine technology is mature, the likelihood of actors
competing on the basis of technology is low. Instead, the competition
regarding wind turbines will be cost-related; achieving economies of scale on
bigger and more streamlined turbines will be the source of short-term cost
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reduction (from a peak in 2009), but not as drastic in nature as those facing
solar. Given that operations and maintenance contracts are often sold by the
turbine manufacturer covering the lifetime of the plant, this will also present
an opportunity for cost-competition. These opportunities combined with the
uncomplicated and uncontroversial turbine supply chain indicates that
turbine manufacturers are well-suited for investment.
Going forward, reinstatement of the Clean Power Plan, a key piece of
renewable energy-promoting climate policy, is highly contingent on the
nomination of a climate-friendly Supreme Court justice to replace Antonin
Scalia. Even so, whether this is necessary for a coal phase-out and overall
reduction in carbon intensity of U.S. generation or whether these measures
serve primarily for political signaling is unclear; the decreasing
competitiveness of coal and bankruptcies of U.S. coal giants are already
taking place, primarily due to the shale gas boom and the resulting low gas
prices. National renewable portfolio standards are constantly under
discussion, but no progress has been made in this regard for several years. In
general, the high level of uncertainty brought by the presidential election
taking place this November prohibits further speculation regarding
regulatory movement.
Favorable financial structures, solutions to grid and intermittency concerns
(namely electric storage) and political consensus on the necessity of
decarbonizing electricity generation (through regulation like the Clean
Power Plan) will be crucial. Some competition for new capacity will derive
from readily available, inexpensive, domestic natural gas, which still
represents a means of decreasing the carbon intensity of the electricity mix,
even if not to the extent of renewables.
Regardless, as time passes and renewables become known for both the cost
and carbon savings they bring, they will likely comprise increasingly greater
portions of the U.S. electricity mix. For wind, which is already competitive
compared to fossil fuels, turbine manufacturers and utilities stand to
contribute to, and benefit most from its continued development. Some cost
reduction still needs to take place for solar to achieve the same level of
deployment, but if current trends continue, companies which facilitate U.S.
solar installations (whether at utility or residential scale) are likewise wellsituated.
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Appendix
I: Deregulation of utilities opened the door for independent
power producers
There are two major types of utilities in the U.S., publicly owned utilities
(POUs) and private investor-owned utilities (IOUs). POUs are memberowned cooperatives, government-owned, or municipally-owned utilities,
kand are generally exempt from regulation. IOUs, on the other hand, are
large, vertically-integrated, and regulated at the state level by regulatory
commissions. The Federal Energy Regulatory Commission regulates
wholesale prices, but per the U.S. constitution it is only allowed to intervene
if interstate transmission is involved.
Percent of Total
Figure 20: U.S. Utility Market Overview
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Non-Utility Generators
Federal Electric Utilities
Power Marketers
Cooperatives
POUs
IOUs
Sales to Generation
Ultimate
(GWh)
Customers
(GWh)
Number
Source: Mirova / APPA 2015
Since the mid-1990s, restructuring of the electricity market has taken place
in 16 states, allowing non-utility generators (such as independent power
producers, or IPPs) to sell electricity to utilities and for retail providers to
buy electricity from generators and sell it to end-use customers. This
deregulation occurred with the hope that incentives provided by competition
would improve efficiency and lower consumer costs, but many of the IPPs
made possible by deregulation are also major contributors to the expansion
of the renewable energy and electricity market.
It is also worth noting that utility ownership of transmission infrastructure is
managed on the state-level, but few state regulatory frameworks require
cooperative management. Building new infrastructure falls into a mixture of
local, state, and federal jurisdiction depending on the project. The only
standardized transmission-related regulation is the pricing of wholesale
transmission transactions, which is regulated on the federal level.
II: Other influential incentives are also present
State fiscal incentives complement the federal
Numerous state-specific financing programs and incentives are also in place
to improve feasibility of implementation for customers. Some of the more
popular include public benefit funds for renewable energy (present in 16
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states) and property-tied financing plans (through the Property Assessed
Clean Energy program present in 31 states).
Many states also offer incentive programs for renewable energy projects or
manufacturing facilities within the state’s borders. Typically this takes the
form of an up-front rebate or an ongoing performance-based payment to
solar energy facilities. Coupled with state net metering programs, incentive
programs have been a major driver for customers to invest in on-site PV.
The majority of these projects have been to support solar PV projects, but
wind has been the largest recipient of funds.
In total, approximately 27 states have some type of cash rebate program
targeting customer-sited renewable energy. In most states, there are also
similar programs on the municipal scale. Program designs, funding sources,
and funding levels vary greatly between states, but most apply a small fee to
retail electricity sales which is then re-administered by a state agency or
utility. Between 2010 and 2017 such charges are expected to collect more
than $7.2 billion for renewable energy, or 2% of estimated total investment
flows.
For example, California’s residential solar sector aims for 3000 MW of
customer-sited PV by 2016. The state aims to achieve this largely by offering
cash incentives on solar PV systems of up to $2.50 per watt, which can cover
up to half of a solar energy system’s total cost. Massachusetts serves as a
more representative example: it offers a 15% tax credit (up to $1000)
against state income tax for the net expenditure of a renewable energy
system at an individual’s residence. Sales tax and value-added property tax
are also waived for renewable energy equipment, and the federal ITC / PTC
still apply.
Other state policies can also help or hinder development
Lastly, it should be noted that since utilities are largely regulated at the state
level, regulations concerning their rate structures have a high impact on the
deployment of renewables within that area. The three most pertinent
structures are interconnection standards, which describe how utilities treat
renewable energy sources wishing to connect to the electric grid; net
metering, which allows customers who generate their own renewable energy
to receive compensation for the electricity they generate; and feed-in tariffs,
which obligate utilities to pay pre-established above-market rates for
renewable power fed onto the grid.
Interconnection standards are processes and technical requirements that
describe how electric utilities treat renewable energy sources that need to
connect to the electric grid. Establishing standard procedures reduce the
uncertainty and delays renewable energy systems can encounter when
obtaining electric grid connection in states without interconnection
standards. As of 2015, 46 states have implemented regulatory requirements
for interconnection standards in order to facilitate development of
renewables and distributed generation.
Net metering enables residential or commercial customers who generate
their own renewable electricity to receive compensation for the electricity
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they generate. Net metering rules require electric utilities in a state to ensure
that customers’ electric meters accurately tract how much electricity is used
on site or returned to the electric grid. When electricity generated on site is
not used, it is returned to the grid; when on site generation is not sufficient to
meet the customer’s needs, the customer uses electricity from the grid. In
effect, excess electricity is returned to the customer at a later time when they
otherwise would have paid for it.
The EPAct 2005 required every public utility to offer net metering to their
customers. Since then, 44 states have authorized net metering, and three
states (Idaho, South Carolina, and Texas) have further implemented net
metering programs. However, though most states and territories have
authorized net metering, the approaches differ with regards to terminology,
capacity limits (ranging from 20 kW in Vermont to 10 MW in Massachusetts
and 80 MW in New Mexico), eligible technology (all include solar, but not all
include other renewables), net metering credit retention (indefinite rollover
in Alaska, one-year rollover in Hawaii, while California offers to pay
customers for unused credits), and REC ownership.
Lastly, feed-in tariffs encourage the development of renewable energy by
obligating electric utilities to pay pre-established above-market rates for
renewable power fed into the grid. These tariffs, which may vary depending
on the type of resource used, provide renewable generators with a set
stream of income from their projects. While most common in Europe, six US
states (California, Oregon, Washington, Maine, Vermont, and Hawaii) have
feed-in tariff schemes mandated by state regulation, and several additional
areas have similar programs voluntarily-provided by utilities.
Large direct subsidies have also been provided to renewables
These quintessential subsidies comprise direct payment of federal funds for
energy-specific purposes totaling $12.9 billion (44% of total subsidies and
support) in 2013, 64% of which was to support renewable energy sources.
The Department of the Treasury provided $8.2 billion of these direct
expenditures (62%), all of which went to support renewable energy under
the American Reinvestment and Recovery Act of 2009 Section 1603 grant
program. The fuel mix of direct expenditures has changed considerably over
the last years: funds provided for renewables increased by 175%, while gas,
petroleum liquids, and nuclear received less support. Support for coal also
appeared to grow, but this is mainly attributable to a large new program for
carbon capture and storage.
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