DRAFT FOR DISCUSSION
A More Diverse, Secure, and Sustainable US Power Supply – the Role of State RPS Programs
Executive Summary
 Renewable energy in America has been growing strongly. In 2012 the US will generate over five
percent of its electricity from non-hydro renewable sources – compared with less than two
percent in 2001. As a result of this rapid growth, the US now generates more non-hydro
renewable electricity (on an absolute basis) than any other country in the world.

In addition to creating US jobs, deploying low/zero-marginal cost renewable generation provides
a critical hedge against future increases in fossil fuel prices while bettering the environment.

While federal incentives such as the Production and Investment Tax Credits have bolstered the
supply of renewable energy, support for renewable energy demand has come chiefly from states
in the form of Renewable Portfolio Standard (RPS) mandates for utilities to procure minimum
amounts of electricity from renewables sources. Currently in place in 29 states, RPS mandates
have driven creation of one-third of current US non-hydro renewable electricity.

Curtailment of federal incentives would leave RPS mandates as the chief medium-term driver of
new investment in renewable energy. This paper finds, however, that annual new installed
renewable generating capacity needed to meet RPS mandates through 2030 amounts to 3.25
GW (for 61.5 GW of new installed generating capacity in total); this level of “RPS demand pull” is
slightly below the average for 2008-2011 and is equal to only roughly one-third of total new
installed US renewable generating capacity in 2011 (9 GW) - which was supported on the supply
side by federal incentives. Hence, going forward RPS programs will continue to make a valuable
but limited contribution to deployment of new renewable generating capacity in the US.

Increasing cost-competitiveness with conventional generating capacity combined with
remaining incentives will enable continued deployment of renewables in line with “RPS demand
pull.” Without introducing RPS mandates in new states or strengthening existing mandates,
however, RPS-driven demand will plateau – suggesting that policy support for investment in
renewable energy will be stagnating just as America’s need for the energy diversity and security
benefits of renewable energy is increasing (due to investment in new gas-fired generation and
growing exposure to volatile fossil fuel prices).

To diversify America’s energy mix and hedge against uncertainty in the price of fossil fuels (in
particular natural gas), state policymakers can increase long-term support for renewable energy
demand. Promising measures to consider include strengthening existing RPS targets, procuring
more renewable electricity through reverse auctions (for large-scale projects), and introducing
more local incentives such as CLEAN (Clean Local Energy Accessible Now) programs (for smallto-medium size projects). Provided that they protect the energy diversity and local economic
benefits of distributed generation, policies to broaden interstate trade in Renewable Energy
Credits (RECs) may be another option to consider.

In the shorter term, federal policymakers can complement state-led efforts by extending supplyside incentives such as the Production Tax Credit and Investment Tax Credit beyond their
1
DRAFT FOR DISCUSSION
current expiration/reduction dates.1 Going forward, coordinating transitional, supply-focused
federal tax incentives with longer-term, demand-focused RPS programs should be a key element
of America’s renewable energy strategy.
Introduction – Diversified and hedged energy system
Renewable energy in the US has been booming. In 2011 the US generated nearly 5 percent of its
electricity from non-hydro renewable sources – up from less than 2 percent in 2001.2 Over the last
decade the number of states generating more than 5 percent of their electricity from non-hydro
renewable sources has quadrupled – from five states in 2001 to 20 states in 2011.3 As a result of this
growth, in absolute terms the US now leads the world in generation of electricity from non-hydro
renewable sources.4 The US has seen massive increases in both wind power (with annual wind
electricity generation increasing 17X since 2001) and solar power (with annual new installed solar PV
capacity increasing 20X since 2008). Over just the past five years deployment of renewable generating
technologies has attracted over $100 billion of new investment.5 Increased US deployment has helped
to accelerate dramatic reductions in the cost of solar PV and other renewable generation technologies.6
Figure 1 Non-hydroelectric renewable share of total net generation by state
Source: Energy Information Administration (EIA), 2012
1
For more discussion, see our companion US PREF paper “Clean Energy and Tax Reform.”
Non-hydro renewable sources include wind power, solar PV, solar thermal, biomass, and geothermal. EIA
reference
3
"Cleaner Energy," New York Times editorial, Monday May 28, 2012
4
EIA The US produces about 70% more than Germany, the next largest non-hydro renewable electricity producer.
5
Bloomberg New Energy Finance
6
Among other causes, such cost reductions have come as a result of economies of scale in production, learning-bydoing that facilitates technological progress.
2
2
DRAFT FOR DISCUSSION
The benefits of deploying renewable energy sources include jobs for American workers7, a cleaner and
healthier environment, and, especially, – by reducing exposure to volatile fossil fuel prices - a more
diverse and secure US energy supply. Indeed, the current extremely low spot price of US natural gas
makes the energy security dimension of renewable energy particularly valuable. As a low natural gas
price spurs another “dash to gas” – more than half of all new US electric generating capacity to be
built between 2012-2015 will be gas-fired8 – the US economy risks increasing its vulnerability to fuelprice shocks just as new sources of demand for natural gas (from the industrial, transportation, and
export sectors) threaten to ratchet gas prices upward. Even amid higher gas prices, however, new gasfired plants will likely remain more economic than new coal-fired plants for the rest of this decade and
beyond.9 This underscores how diversifying America’s energy supply away from gas toward zeromarginal cost, renewable resources provides a hedge against future increases in the price of fossil
fuels.10 Hedging against fossil fuel price shocks is a compelling reason to ensure sustained investment in
developing domestic renewable energy sources.11 Moreover, the decline in the costs of renewable
energy technologies continues to enlarge the scope of feasible near-term investment in US renewable
energy.
Federal and state policies have been instrumental in enabling America to realize the benefits of clean
energy. On the supply side, incentives such as the Production Tax Credit, Investment Tax Credit, and
1603 Treasury Cash Grant program have helped to attract capital into the sector. On the demand side,
state-level Renewable Portfolio Standards (RPS) that require utilities to procure minimum percentages
of electricity from renewables sources12 – the focus of this paper – have provided critical “demand pull”
to promote deployment of new renewable generating capacity even amid sluggish growth in overall
power demand.13
7
See DB Climate Change Advisers paper, “Repowering America: Creating Jobs,” October 10, 2011,
http://www.dbcca.com/dbcca/EN/investment-research/investment_research_2396.jsp
8
EIA/EPA
9
This is largely because the capital costs of new gas-fired combined-cycle units are 30-50% lower than those of
new coal-fired units. For comparison of the economics of new gas and coal-fired units, see DB Climate Change
Advisers paper, “Natural Gas and Renewables: the Coal to Gas and Renewables Switch is on!,” October 10, 2011,
http://www.dbcca.com/dbcca/EN/investment-research/investment_research_2395.jsp
10
Wiser et al. estimate that deployment of renewables…..
11
For more detail, see the companion US PREF paper “Clean Energy and Tax Reform”
12
Most RPS standards specify a minimum percentage of electricity that must be procured from renewable sources;
Texas and Iowa, however, have “capacity-based” standards that simply require addition of a minimum amount
(MW) of renewable generating capacity. See DSIRE
13
For more description of policies affecting the US power market, see Appendix I.
3
DRAFT FOR DISCUSSION
Figure 2 Supply and Demand for Renewable Energy and Relevant Federal/State Policies
Clean Energy Manufacturers
Clean Energy Developers
Capital
Equipment:
End Market:
Clean Electricity Users
Clean
Electricity:
Federal Government Programs:
• 48c Manufacturing Tax Credit (Wind turbines,
PV solar cells,
– EXPIRED at end-2010
etc.)
• 1703/05 DOE Loan Guarantee
Program – EXPIRED in 2011
- Currently a lack of federal
Cash Payment:
policy support for renewable
manufacturers
Federal Government Programs:
(Meets RPS
• Investment Tax Credit – for
demands)
solar, valid through 2016
• Production Tax Credit –
EXPIRES at end-2012 (wind) and
Investment
end-2013 (other technologies)
Grade Cash
• 1603 Cash Grant – EXPIRED at
Flows:
end-2011
(Provided by
(Made possible - Soon to be a lack of federal
PPAs; critical for
through project policy support for renewable
project
project developers (esp. wind)
financing)
financing)
Federal Initiatives Under
Discussion
• Clean Energy Deployment
Administration (“CEDA”)
Federal Initiatives Under
Consideration:
• National transmission policy
Transmission
Federal & State Government
Programs:
• Renewable Portfolio Standard
– present in most (29) states (and
DC and PR) – key tensions
between RPS enforcement
measures & cost caps
• Procurement by government
entities
Other Drivers:
• Overall economic
attractiveness – including supplyside policy drivers
Federal Initiatives Under
Consideration:
• Clean electricity standards
(“CES”)
Source: US PREF analysis
Just as the national benefits of deploying renewable energy are set to increase, however, the level of
policy support provided to the sector is set to plateau or decline – creating substantial uncertainty in the
near and medium-term outlook for renewable energy. Combined with similar cuts to other programs,
expiration of the 1603 Treasury cash grant program (at year-end 2011) and scheduled expiration of the
Production Tax Credit for wind power (at year-end 2012) will reduce federal spending on renewables
from $44 billion in 2009 to $11 billion in 2014;14 planned reduction in the Investment Tax Credit for solar
power from 30 percent to 10 percent (at year-end 2016) will further reduce federal support for
renewable deployment.
Retrenchment on the federal level will leave RPS mandates in 29 states as the chief medium-term policy
driver for new investment in renewable energy. In this paper, we will be focusing on the role of State
Renewable Portfolio Standards (RPS) in the supply-demand dynamic in the US as these policies have
been the main driver, in terms of demand “pull”, of clean energy deployment to date. The key question
is how much more demand state RPS’ can generate, as currently defined, and how these policies can
interact with the supply side forces given that policy has been a key driver of renewable energy supply
to date through economic incentives, and is starting to phase out. In terms of structure, we provide: (i)
a description of the current status and structure of Renewable Portfolio Standards in the US; (ii) a
detailed “sizing” of the RPS market out to 2030 using projections by Bloomberg New Energy Finance
(BNEF) and Lawrence Berkeley National Laboratory (LBNL)15; and the necessary capacity build-out to
meet projected demand; (iii) a discussion of how and to what extent the state’s RPS requirements will
be met (including a discussion of the various compliance and enforcement mechanisms utilized in each
14
For detail on federal spending, see Brookings “Boom and Bust” paper
15
4
DRAFT FOR DISCUSSION
RPS); and (iv) discussion of policies to maximize the impact of RPS programs on the growth of the US
renewables industry.
Demand: State of RPS Initiatives
A Renewable Portfolio Standard (RPS) is a state-level policy intended to increase the generation of
electricity from renewable sources. Though no two states have exactly the same RPS program – ability
to tailor to state-specific conditions is one of the strengths of RPS policies - the core of aspect of an RPS
program is a mandate that electric utilities within a state must procure a minimum percentage or
absolute amount of electricity from renewable sources by a specific date.16
As of May 2012, 29 states (plus Washington DC) have enacted RPS programs that include such timebound mandates for procurement of renewable electricity (with an additional 7 states having enacted
RPS policies that set voluntary goals for renewable electricity procurement). Such programs often
include “set-asides” or “carve-outs” specifying minimum percentages of electricity to be generated from
particular technologies; for example, the figure below illustrates RPS policies in 17 states to include setasides for solar PV.
Figure 3 Renewable portfolio standards by state, listing the mandated % of electricity to be procured from
renewables and the targeted date
WA: 15% by 2020*
(Xcel: 30% by 2020)
MI: 10% + 1,100 MW by
ND: 10% by 2015
OR: 25% by 2025 (large utilities)*
5% - 10% by 2025 (smaller utilities)
2015*
SD: 10% by 2015
WI: Varies by utility;
CO: 20% by 2020
IA: 105 MW
(IOUs )
UT: 20% by 2025*
OK: 15% by 2015
WV: 25% by 2025*
VA: 15% by 2025*
(IOUs)
10% by 2018 (co -ops & munis )
10% by 2020 (co-ops)
DE: 20% by 2019*
DC: 20% by 2020
29 states
HI: 40% by 2030
& DC
& PR have an RPS
State renewable portfolio standard
Minimum solar or customer -sited requirement
*†
7 states have goals
☼
Extra credit for solar or customer -sited renewables
Includes separate tier of non -renewable alternative resources
Source: US Database of State Incentives for Renewables and Efficiency, Goldman Sachs
16
PA: 18% by 2020†
NJ: 22.5% by 2021
PR: 20% by 2035
TX: 5,880 MW by 2015
Solar water heating eligible
RI: 16% by 2020
MD: 20% by 2022
NC: 12.5% by 2021
NM: 20% by 2020 (IOUs)
State renewable portfolio goal
(Class I Renewables)
CT: 23% by 2020
KS: 20% by 2020
MO: 15% by 2021
AZ: 15% by 2025
NH: 23.8% by 2025
MA: 15% by 2020
OH: 25% by 2025†
IL: 25% by 2025
10% by 2020 (co-ops & large munis)*
ME: 30% by 2000
New RE: 10% by 2017
+ 1% annual increase
NY: 29% by 2015
10% by 2015 goal
NV: 25% by 2025*
CA: 33% by 2020
VT: (1) RE meets any increase
in retail sales by 2012;
(2) 20% RE & CHP by 2017
MN: 25% by 2025
MT: 15% by 2015
For more detail on the structure of an RPS regime, see Appendix II.
5
DRAFT FOR DISCUSSION
Summing across states (and, where necessary, excluding exempted entities), Figure 4 below illustrates
50% of the total US electrical load to currently have some form of RPS mandate – with the RPS-covered
share rising to 56% upon full implementation of all RPS standards.
Figure 4 Percent of total US electrical load with active RPS mandates
Note: Investor-owned utilities (IOUs), publicly-owned utilities (POUs), and energy service providers (ESPs)
Source: LBNL
RPS as Strong Drivers of the Growth of US Renewable Generation
Of the 200,000 gigawatt-hours (GWh) of non-hydro renewable electricity in 2011, one-third represents
new renewable electricity spurred by implementation of RPS mandates (“cumulative RPS-driven new
GWh)”.17 In other words, this is renewable generation not in existence at the time a given state RPS
mandate was passed, but that has since come into existence and is counted toward fulfilling the RPS
mandate. The figure below also illustrates “cumulative RPS-supported GWh”; this includes generation
that was in existence at the time a given state RPS mandate was passed, but whose continued existence
has been supported by the need to fulfill the state’s RPS mandate. Taking this pre-existing generation
into account, “cumulative RPS-supported GWh” are equal to roughly two-thirds overall non-hydro
renewable electricity in 2011 (i.e. 133,000 GWh).
17
LBNL
6
DRAFT FOR DISCUSSION
Figure 5 Impact of RPS programs on growth of US renewable power supply, 1998-2011
250,000
200,000
GWh
150,000
100,000
50,000
0
1998
1999
2000
Cumulative RE GWh
2001
2002
2003
2004
2005
Cumulative RPS-supported GWh
2006
2007
2008
2009
2010
2011
Cumulative RPS-driven new GWh
Note: “Cumulative RE GWh” includes generation from wind, solar, biomass, and geothermal, but excludes conventional
hydroelectric power. “Cumulative RPS-driven new GWh” refers to renewable generation not in existence at the time a given
state RPS mandate was passed, but that has since come into existence and is counted toward fulfilling the RPS mandate.
“Cumulative RPS-supported GWh” this includes generation that was in existence at the time a given state RPS mandate was
passed, but whose continued existence has been supported by the need to fulfill the state’s RPS mandate.
Source: LBNL, DBCCA analysis, 2012
Given that RPS mandates have supported creation of new renewable electricity generation, they by
definition have supported installation of new renewable electric generating capacity. The figure below
demonstrates, for 2006-2011, the portion of total US new renewable generating capacity that was
needed to meet RPS mandates for that year. From 2008-2011, new RPS-driven capacity averaged 3.5
GW per year while total new renewable capacity additions averaged 9.5 GW per year (in both cases,
wind turbines accounted for the majority of new capacity added). Hence, from 2008-2011 RPS “demand
pull” accounted for 36% of total additions of new renewable generating capacity in the US; installation
of the other 64% (i.e. 6 GW per year) reflects chiefly decreasing capital costs for renewable technologies
and the impact of supply-side federal tax incentives such as the Production Tax Credit and Investment
Tax Credit.18
18
This calculation simplifies matters slightly, as some portion of the 6 GW per year reflects new capacity added to
meet RPS mandates in future years. That said, willingness of developers to build capacity in advance of RPS
obligations reflects in part the economic impact of federal tax incentives. As noted above, developers are eligible
for such tax incentives irrespective of whether they are selling power/RECs into RPS markets.
7
DRAFT FOR DISCUSSION
Figure 6 Impact of RPS programs on growth of US renewable generating capacity, 2006-2011
12.0
10.3
10.1
10.0
9.1
8.4
GW
8.0
6.3
6.0
6.0
3.9
4.0
2.9
2.0
2.7
1.0
1.1
0.9
0.0
2006
2007
annual new RE capacity
2008
2009
2010
2011
annual new RPS-driven RE capacity
Note: RE capacity figures includes generation wind, solar, biomass, and geothermal capacity, but excludes conventional
hydroelectric capacity. Source: LBNL, DBCCA analysis, 2012
While the totals have been far smaller, RPS carve-outs for solar generation have been similarly strong
drivers of the growth in solar generation and installation of new solar generating capacity.19
RPS-driven Incremental Demand for Renewable Electricity and Generating Capacity to 2030
RPS mandates should be thought of as providing a floor on deployment of new renewable generating
capacity. In the absence of a national carbon price or clean energy standard, state-level RPS programs –
mandating that electric utilities procure minimum percentages of electricity from renewable sources by
specific dates - will throughout the rest of the decade remain the chief policy driver of demand for
renewable generation. Recognizing this raises questions such as (1) in states with RPS mandates, how
much must generation of renewable electricity increase in order to satisfy RPS targets through 2030?;
and (2) how much additional generating capacity must be built in order to enable this increase in
generation?
Mind the Gaps
A state’s “RPS generation gap” for a given year will be equal to the difference between its share of
renewable generation for that year and the share of renewable generation needed to fulfill its ultimate
RPS target. The figure below illustrates that, as of 2010, the size of such gaps varied from one
percentage point in Pennsylvania to more than twenty percentage points in California. Broadly
19
For figures illustrating the impact of RPS solar carve-outs on the growth of solar generation and capacity in the
US, see Appendix III.
8
DRAFT FOR DISCUSSION
speaking, however, as of 2010 most states – and particularly larger states with more ambitious RPS
targets – were less than halfway toward meeting their RPS goals.
Figure 7 Renewable generation as a % of retail electricity sales (2010)
33%
Renewable generation
25%
24%
Targeted renewable generation
23%
20%
16% 15%
13% 12%
10%
8%
17%
13%
7%
10%
5%
CA
OR MN
IL
5%
NY
9%
NH
9%
5%
CT
9%
9%
NJ
10% 9%
8%
3%
2%
HI
NM CO NV
0%
2%
UT MD DE DC
RI
1%
1%
8%
12%
7%
1%
1%
9%
7%
6%
5%
VT
WI
MI
ME PA
3%
MT WA MA MO AZ NC VA
SD
Note: Exemptions or lower mandates for certain utilities (e.g. publicly-owned municipal utilities and co-ops) and “credit
multipliers” for certain classes of generation (i.e. 2X for in-state generation) will in many states reduce the actual RPS target
below the figure shown above. As a result, the existing gap between renewable generation and the target level will be smaller
than that shown above. Source: EIA, SNL, AWEA, Goldman Sachs Research estimates.
We base the state-by-state analysis below on projections from Bloomberg New Energy Finance and
Lawrence Berkeley National Laboratory. In the aggregate, these are similar to projections from the
Union of Concerned Scientists.
Taking 2012 as a base year, the figure below depicts estimates from Bloomberg New Energy Finance of
the growth in renewable generation (by state or power market region) required for all states to meet
their end-state RPS targets.20 Surveying across states suggests that (1) achieving RPS targets through
2030 will require generating roughly 155,000 GWh of new renewable electricity, and (2) the need for
new renewable electricity to meet RPS targets is allocated fairly broadly across California, the midAtlantic, New England, and the Midwest.
9
DRAFT FOR DISCUSSION
Figure 8 GWh gaps (as of 2012) – incremental renewable electricity generation required for states to meet their
RPS targets by 2030
40,000
2012-2030 RPS gap = 155,824 GWh
35,000
30,000
25,000
GWh
20,000
15,000
10,000
5,000
(5,000)
(10,000)
Note: States/regions in green comprise 80% of total. For states with carve-outs just for solar, excludes generation needed to
meet solar carve-out targets. Excluding North Carolina, the PJM states with binding RPS targets include Delaware, Maryland,
Michigan, New Jersey, Pennsylvania, and the District of Columbia. The NEPOOL (New England Power Pool) states with binding
RPS targets include Massachusetts, Rhode Island, New Hampshire, Connecticut, and Maine. Excluding Illinois, the MRETS
(Midwest – Renewable Energy Tracking System) states with binding RPS targets include Iowa, Minnesota, Montana, North
Dakota, Ohio, and Wisconsin. Excluding California and Nevada, the WREGIS (Western Renewable Energy Generation
Information System) states with binding RPS targets include Colorado, New Mexico, Oregon, Utah, and Washington. ERCOT is
the Electric Reliability Council of Texas.
Source: Bloomberg New Energy Finance, DBCCA analysis 2012.
Solar carve-outs
While most required incremental RPS generation can be met by one of several eligible technologies, in
many states a portion of RPS mandates are “carved out” to support generation of electricity from
particular technologies. The most common such carve-outs are for generation from solar power and/or
from distributed generation (with rooftop solar PV being the most common distributed generation
technology).21 Drawing on data from Lawrence Berkeley National Laboratory, the figure below shows
incremental generation needed to meet solar carve-outs in 17 states through 2030; the cumulative
21
States define such carve-outs differently – with some states specifying just solar, others solar electric, others
customer-sited distributed generation, and others customer-sited solar PV.
10
DRAFT FOR DISCUSSION
figure - 14,000 GWh – is roughly equal to total estimated US solar-generated electricity in 2012.22 Just
six states (shaded in yellow below) account for over 80% of the new solar generation needed to meet
RPS carve-outs through 2030. Note, however, that as solar technologies become increasingly costcompetitive with conventional generation – and as solar generation in states such as Arizona and
Colorado begins to exceed minimum carve-out levels - states with the most ambitious solar carve-outs
will not necessarily have the strongest demand for solar.23
Figure 9 Solar electricity generation needed to meet solar set-aside targets by state, 2012-2030
7,000
2012-2030 solar carve-out gap = 14,984 GWh
6,000
5,000
GWh
4,000
3,000
2,000
1,000
0
NJ
IL
AZ
MD
OH
PA
CO
NM
DE
MA
DC
NC
MO
NV
NY
OR
NH
Note: Addition of solar electricity generation in excess of RPS solar carve-out targets in years prior to 2012 may reduce required
incremental solar generation through 2030 below the 14,984 GWh figure above. States in yellow comprise 80% of total. For
states with carve-outs just for solar, amounts shown above are not reflected in the total renewable generation figures shown
above. AZ, CO, NM, and NV assumed to meet some portion of required solar generation via concentrating solar power (CSP); all
other states assumed to meet 100% of required solar generation through solar PV.
Source: Lawrence Berkeley National Laboratory, DBCCA analysis 2012
National impact of RPS programs on generation of electricity from non-hydro renewables
22
Due to additions of new solar electric generating capacity in excess of current-year solar carve-out requirements
in years prior to 2012 (e.g. in Colorado and Arizona), the actual addition of new solar generation and generating
capacity needed to meet solar carve-out targets through 2030 may be below LBNL projections. Hence, given
current RPS mandates, the LBNL forecasts set an upper bound on the incremental new solar generation and solar
generating capacity that RPS solar carve-outs will support.
23
For example, California currently accounts for about half of the total US market for solar PV. While the state has
other incentives to spur demand for solar (i.e. net metering and California Solar Initiative rebates), the state’s RPS
has no carve-out for solar generation.
11
DRAFT FOR DISCUSSION
To put the above state-level figures in a national context, the figure below illustrates how closing the
GWh gaps (inclusive of solar carve-outs) will increase total RPS-supported renewable generation from
3.6% of total US generation in 2012 to 7.9% in 2020 and 9.6% in 2030. Hence, over the two decades RPS
mandates will enable a substantial but limited increase in generation of electricity from non-hydro
renewables.
Figure 10 Closing all GWh gaps increases total RPS-supported demand to 9.3% of total generation by 2030
4400
4200
9.3%
TWh
4000
7.9%
3800
3.6%
3600
90.7%
92.1%
3400
96.4%
3200
2012
2020
All other US generation
2030
Total RPS-supported demand
Note: “Total RPS-supported demand” includes demand to meet solar carve-outs. “All other US generation” includes non-hydro
renewable generation that is not covered by RPS mandates. In 2012, this will amount to ~2% of total US generation.
Source: Bloomberg New Energy Finance, Lawrence Berkeley National Laboratory, EIA, DBCCA analysis 2012
The figure below compares the average annual increase in non-hydro renewable generation required to
meet RPS targets through 2030 with the actual annual increase in non-hydro renewable generation in
2011. The comparison shows that meeting RPS mandates through 2030 requires increasing generation
of non-hydro renewable electricity each year by just one-third as much as non-hydro generation
increased in 2011. Again, the conclusion is that – on a national basis - RPS compliance will make only a
moderate contribution to the growth of renewable electricity in the US.
12
DRAFT FOR DISCUSSION
Figure 11 Projected RPS-driven growth of RE and solar generation vs. total new generation in 2011
2011 new US non-hydro renewable electricity generation
27,820
avg annual new renewable generation to meet RPS targets, 2012-2030*
8657
2011 new solar electricity generation
602
avg annual new solar generation to meet RPS targets, 2012-2030
832
0
5000
10000
15000
20000
25000
30000
GWh
Note: “Avg annual new renewable generation to meet RPS targets” excludes generation needed to meet solar carve-outs.
Source: Bloomberg New Energy Finance, Lawrence Berkeley National Laboratory, EIA, DBCCA analysis 2012
Building the Capacity to Close GWh Gaps
Boosting the share of non-hydro renewables to meet RPS targets will require adding new wind, solar,
biomass, and geothermal electric generating capacity. Inferring from above that closing America’s
collective RPS gap will as of 2012 will require 155,824 GWh of extra renewable electricity, how many
gigawatts (GW) of new capacity will be required to generate this extra electricity will depend on (1) the
mix of technologies used to generate new renewable electricity; (2) the average capacity factor24 of new
generation; (2) the impact of set-asides for particular technologies; and (3) at the level of an individual
state or region, how much of each state’s RPS gap can be met via imports of electricity from neighboring
states.
In forecasting required capacity, BNEF assumes a 33% average capacity factor similar to that of a US
onshore wind farm (heretofore the dominant renewable generation technology in the US). BNEF also
allows for states to meet their RPS requirements via imports of electricity from other states. Below are
the BNEF estimates for the required additions of overall RE capacity to meet RPS targets (note that, for
24
Explain cap factor
13
DRAFT FOR DISCUSSION
states with carve-outs just for solar, the estimates below omit capacity required to meet these solar
carve-outs).
Figure 12 New renewable capacity needed to meet RPS targets, 2012-2030
14.00
2012-2030 RPS build = 48 GW
12.00
10.00
GW
8.00
6.00
4.00
2.00
-
Note: States/regions in green comprise 80% of total. Assumes that new capacity has a 33% capacity factor (i.e. similar to that of
a US onshore wind farm). For states with carve-outs just for solar, capacity needed to meet solar carve-out targets will not be
included in totals shown above. Excluding North Carolina, the PJM states with binding RPS targets include Delaware, Maryland,
Michigan, New Jersey, Pennsylvania, and the District of Columbia. The NEPOOL (New England Power Pool) states with binding
RPS targets include Massachusetts, Rhode Island, New Hampshire, Connecticut, and Maine. Excluding Illinois, the MRETS
(Midwest – Renewable Energy Tracking System) states with binding RPS targets include Iowa, Minnesota, Montana, North
Dakota, Ohio, and Wisconsin. Excluding California and Nevada, the WREGIS (Western Renewable Energy Generation
Information System) states with binding RPS targets include Colorado, New Mexico, Oregon, Utah, and Washington. ERCOT is
the Electric Reliability Council of Texas.
Source: Bloomberg New Energy Finance, DBCCA analysis 2012.
Since solar carve-outs must be met by a specific type of capacity (i.e. solar PV or, in some cases, CSP),
the figure below draws on LBNL projections to illustrate required capacity additions to meet solar carveouts through 2030.
14
DRAFT FOR DISCUSSION
Figure 13 New solar capacity needed to meet solar set-aside targets, 2012-2030
6
2012-2030 solar carve-out build = 13.5 GW
5
GW
4
3
2
1
0
NJ
IL
MD
AZ
OH
PA
DE
CO
MA
DC
NC
NM
NY
MO
NV
NH
OR
Note: Addition of solar generating capacity in excess of RPS solar carve-out targets in years prior to 2012 may reduce required
incremental solar generation through 2030 below the 13.5 GW figure above. Values converted from AC to DC assuming 77%
conversion ratio. AZ, CO, NM, and NV assumed to meet some portion of required solar generation via concentrating solar
power (CSP); all other states assumed to meet 100% of required solar generation through solar PV.
Source: Lawrence Berkeley National Laboratory, DBCCA analysis 2012
National impact of RPS programs on additions of new renewable generating capacity
The figure below (1) projects average annual additions of renewable and solar generating capacity need
to meet RPS targets and solar carve-outs from 2012-2030 and (2) compares these projections with total
new installations of renewable and solar generating capacity in 2011. The chief takeaway is that
through 2030 RPS mandates will collectively support addition of only 3.25 GW of new renewable
generating capacity per year (with 0.7 GW of this total linked to satisfying solar carve-outs).25
Comparing with figure 6 above, this level of RPS-supported demand represents a decline from the level
25
The 3.25 GW figure reflects the sum of 2.55 GW per year of new renewable generating capacity to meet Tier 1
(i.e. non-technology specific) RPS targets (excluding solar carve-outs), and 0.7 GW per year of new solar generating
capacity (mostly solar PV) to meet solar carve-outs.
15
DRAFT FOR DISCUSSION
of RPS-supported demand during 2008-2011.26 The secondary takeaway is that (including new
capacity to fulfill solar carve-outs) average annual RPS-supported capacity additions through 2030 equal
only one-third of total new renewable capacity added in 2011. This suggests that, going forward, RPS
programs will make a valuable but limited contribution to deployment of new renewable generating
capacity in the US.
Figure 14 Projected RPS-driven new additions RE and solar capacity vs. total new additions in 2011
2011 Total New US RE Capacity
9.08
avg annual new RE capacity to meet RPS targets, 2012E-2020E*
2.8
avg annual new RE capacity to meet RPS targets, 2021E-2030E*
2.1
2011 Total New US Capacity (all solar PV)
1.79
avg annual new solar capacity to meet carve-outs, 2012E-2020E
0.82
avg annual new solar capacity to meet carve-outs, 2021E-2030E
0.61
0.00
1.00
2.00
3.00
4.00
5.00
GW
6.00
7.00
8.00
9.00
10.00
Note: *RE capacity figures exclude capacity needed to meet solar carve-out targets. RE capacity figures assume 33% capacity
factor (similar to that of a US onshore wind farm). A portion of new solar capacity to meet carve-outs is projected to come in the
form of concentrating solar power, rather than solar PV.
Source: Bloomberg New Energy Finance, Lawrence Berkeley National Laboratory, DBCCA analysis 2012.
Note that a plateau in RPS-driven demand – particularly related to solar carve-outs – does not mean that
investment in such technologies will necessarily cease to grow. Increasing cost-competitiveness with
conventional generating capacity combined with remaining incentives will enable continued deployment
of renewables in line with “RPS demand pull.” In the case of solar, the most active market (California)
does not have a specific carve-out for solar generation27; moreover, in key carve-out states such as
Arizona and Colorado, solar generation has begun to exceed minimum levels specified by RPS carve-outs
26
While demand supported by solar carve-outs is projected to continue to grow after 2011, the sum of Tier 1 and
solar-specific demand declines after 2011. As discussed below, since in many states solar installations have
already begun to exceed carve-out minimum levels, for solar the more relevant number may be the level of RPSsupported demand for renewables overall, rather than for solar in particular.
27
California’s main policy support for solar deployment – the California Solar Initiative, a “buy-down” rebate
program – is totally separate from the state’s RPS program.
16
DRAFT FOR DISCUSSION
– suggesting that in future years annual new additions of solar capacity will by no means be limited to
0.7 GW per year.
The plateau in RPS-driven demand for renewables overall, however, does suggest that policy support for
investment in renewable energy will be stagnating just as America’s need for the energy diversity and
security benefits of renewable energy are increasing as more new gas plants are built and so exposure
to unsure long term fossil prices will continue. That the plateau in RPS-driven demand will coincide with
scheduled expiration and reduction of key federal incentives makes the potential negative impact on
growth of renewables particularly significant.
How does an RPS Drive New Supply to Meet the Demand?
The above section establishes that meeting RPS mandates through 2030 will require addition of at least
3.25 GW of new renewable generating capacity per year (with at least 0.7 GW per year of this capacity
coming in the form of solar – chiefly solar PV – generating capacity). Analysis now turns to the question
of what mechanisms are available to promote creation of a new supply of renewable generating
projects to meet this demand.
Means of RPS Compliance
Broadly speaking, there are three ways for a utility or unregulated distributor to comply with an RPS
mandate:
1. Contract for the specified quantity of renewable electricity
2. In lieu of contracting for the delivery of actual electrons, purchase renewable energy credits
(RECs) representing the specified quantity of renewable electricity
3. Purchase neither physical electricity nor RECs, and instead pay a $/MWh Alternative Compliance
Payment (ACP) for each MWh needed to meet the RPS target
Given their central role as a means of RPS compliance, it is worth examining further how supply and
demand for RECs operates.
Renewable Energy Credits
To varying degrees, 27 states allow utilities and distributors to meet RPS obligations through purchases
of Renewable Energy Credits (RECs). A REC is a tradable certificate that represents 1 MWh of qualified
renewable energy generation; procuring and retiring a REC can demonstrate compliance with one or
more RPS requirements.
RECs can be either “bundled” or “unbundled” from the underlying renewable electricity. A REC that is
packaged together with the underlying electricity in a power purchase agreement (PPA) between a
renewable generator and a utility/distributor is considered to be bundled; a REC that is sold separately
from the underlying electricity is considered to be unbundled. Whether a developer is compensated
implicitly (via a higher PPA price) or explicitly (via offers into the REC market), revenue receives from REC
sales will supplement revenue received from federal incentives such as the Production Tax Credit and the
Investment Tax Credit.
17
DRAFT FOR DISCUSSION
As competing means of fulfilling an RPS mandate, a state’s ACP sets a de facto ceiling on the price that
its utilities/distributors will be willing to pay for unbundled RECs. For non-technology specific RECs, ACP
levels set a generalized ceiling of $50-$65/MWh (considerably lower in some states). High variability in
REC prices across states reflects a combination of (1) variation in ACPs; (2) variation in demand for RECs
as a means of demonstrating RPS compliance; and (3) various geographic or technology-specific
eligibility requirements that limit interstate trade in RECs. As discussed below, minimizing barriers to
interstate REC trades represents a highly promising route to lowering the cost of RPS compliance.
Figure 15 Trends in REC prices, 2008-2011
Source: Spectron
Enforcement and Cost-Control – How likely is it that states will meet RPS mandates?
What distinguishes mandatory state RPS targets from merely voluntary or aspirational goals is that
mandatory targets are (1) codified as legal obligations; (2) backed by sanctions or penalties that serve to
encourage compliance. In deciding what level of compliance to achieve, utilities will evaluate the
marginal cost of compliance against the marginal benefit of compliance. The marginal cost of
compliance is equal to the difference between the $/MWh price of renewable generation and the
$/MWh price of non-renewable generation (or, in certain states, the corresponding REC price); the
marginal benefit of compliance is equal to the penalties that the utility avoids by means of procuring an
additional MWh of renewable generation.
The table below lists the penalties that the 12 states that account for 80% of incremental RPS-related
electricity generation may levy against utilities whose procurement of renewable generation falls short
of prescribed RPS levels. In eight of the states, utilities that in a given year fail to reach quantitative RPS
targets incur a cost of $40-$50/MWh for every MWh by which they are short (and a significantly higher
cost for every MWh by which they fall short of solar-specific targets); New Jersey, Maryland, and others
formalize this cost in the regime of an Alternative Compliance Payment (ACP), while California and
18
DRAFT FOR DISCUSSION
Arizona and Oregon empower their Public Utility Commissions (PUCs) to impose the fines. As a means
of promoting compliance with RPS targets, however, the per-MWh fines provide roughly equivalent
incentives across all four states. The magnitude of the fines is also significant for setting an upper bound
on the premium utilities will be willing to pay to procure renewable generation (a topic discussed
below).
Table 1 Compliance/Enforcement Mechanisms in the 12 states that account for 80% of incremental RPS-related
electricity generation through 2030
State
ACP
specified monetary penalties
$/MWh fine
California
Illinois
addiitonal penalties that PUC may impose
suspend/revoke license
additional fines
$50/MWh, up to $25MM per utility
N/A
Ohio
$45/MWh ($450/MWh solar)
New Jersey
$50/MWh ($640/MWh solar)
N/A
N/A
N/A
x
x
Minnesota
x (not to exceed cost of needed RECs)
Washington
Maryland
Massachusetts
$50/MWh
$40/MWh ($300/MWh solar)
x
x
Arizona
x
PUC discretion
Oregon
x
PUC discretion
North Carolina
Missouri
x
PUC discretion
x
Note: ACP values shown are for 2013; in the case of solar-specific ACPs, ACP values are set to decline sharply from 2013-2030. In
Massachusetts and New Jersey utilities/distributors can automatically recover the cost of ACP payments in retail rates;
Maryland and Oregon allow cost recovery only if the PUC deems ACPs to have been the least-cost compliance option. Ohio does
not allow cost-recovery of ACPs. Washington and Arizona only in some cases allows the cost of discretionary penalties to be
recovered in retail rates. Missouri and California do not allow automatic recovery of the cost of $/MWh fines. All columns N/A
for Illinois because Illinois relies on a state administrative agency to procure renewables on behalf of the state’s utilities.
Source: DSIRE, Union of Concerned Scientists, LBNL DBCCA analysis 2012
Whereas per-MWh fines have a high probability of being imposed but a limited impact, the additional
penalties outlined on the right-side of the above table are the reverse – potentially very high-impact, but
with an uncertain probability of being imposed. Legislation in New Jersey and Massachusetts empowers
the PUCs in these states to penalize chronic RPS violators by prohibiting rate-based recovery of eventual
compliance costs, barring a utility from accepting new customers or, in some cases, even suspending or
revoking a utility’s license to operate. While very forceful if implemented, assessing the “bite” of these
measures is difficult since (1) implementation is at the discretion of the PUC; and (2) no case has yet
occurred in either state (or elsewhere) to test a PUC’s willingness to merit out such stiff penalties.
The ‘additional fines’ listed in the final column of the above table fall somewhere in between the two
categories described above: potentially more severe than a $40-$50/MWh fine, but also more likely to
be imposed than suspension or revocation of a utility’s operating license. Vagueness as to the
magnitude of these fines (except in Minnesota, where they cannot exceed the cost of purchasing
19
DRAFT FOR DISCUSSION
needed RECs or procuring the needed amount of renewable energy), however - as well as a lack of cases
demonstrating PUCs inclination or disinclination to impose them – again complicates the task of
assessing just how strongly they influence utilities’ attitude toward RPS compliance.
Cost Caps
Extending the reasoning that a utility’s calculus for RPS compliance will reflect chiefly economic
considerations, embedded in RPS legislation is frequently a state’s calculus of how much it is willing to
invest to increase the generation of electricity from renewable resources. The two middle columns of
the table below enumerate cost caps that, in eight of the twelve 80% states, constrain either the total
dollar amounts to be spent on RPS compliance. Note that these caps apply to the “incremental” cost of
complying with an RPS target – that is, the cost of purchasing required renewable MWhs (or RECs) over
and above the cost of purchasing an equivalent amount of non-renewable energy.28 Such caps can apply
either to costs for consumers or to retailers (as noted above, an ACP or prescribed per-MWh fine serves
as a de facto cap on how much a retailer will spend on incremental RPS compliance). Seven states in the
table below specify the precise level a cost cap is take (whether as a $/MWh amount, a per-account
amount, or a percentage of the total electric bill); Arizona, on the other hand, leaves it to the discretion
of its PUC to determine whether ratepayer surcharges in support of RPS compliance are “just and
reasonable.” In all cases, however, these caps impose some threshold on the amount to be spent on
renewable energy.
28
While states define “incremental” in different ways, there is some uniformity across states. Washington state’s
RPS statute, for example, defines the incremental cost of an eligible renewable resource is determined by
calculating “the difference between the levelized delivered cost of the eligible renewable resource, regardless of
ownership, compared to the levelized delivered cost of an equivalent amount of reasonably available substitute
resources that do not qualify as eligible renewable resources, where the resources being compared have the same
contract length or facility life.”
20
DRAFT FOR DISCUSSION
Table 2 Cost-Containment Policies in the 12 states that account for 80% of incremental RPS-related electricity
generation through 2030
State
Consumer
Rate Payer Surcharge
Retailer
de-facto cost cap
Delay/Escape clauses
CALIFORNIA*
ILLINOIS
Annual requirement may be lowered if annual cost
cap met
2.015% of the 2007 rate
OHIO
$45/MWh ($450/MWh solar)
NEW JERSEY
$50/MWh ($640/MWh solar)
MINNESOTA
PUC discretion for two-year delay
WASHINGTON
MARYLAND
$40/MWh ($300/MWh solar)
MASSACHUSETTS
ACP
ARIZONA
caps compliance costs at 3% premium above cost
of non-renewable electricity
PUC discretion
if incremental compliance costs exceed 4% of
annual retail revenue requirement
If cost of purchasing non-solar Tier 1 RECs
exceeds 8% of annual electricity sale revenues in
Maryland; for solar, if cost of purchasing RECs
exceeds 1% of annual revenues
PUC discretion for two-year delay
if incremental compliance costs exceed 4% of
annual retail revenue requirement
OREGON
NORTH CAROLINA
$12.00/account
MISSOURI
1% of avg retail rate
Ratepayer surcharge cap, and PUC discretion
Note: * SB 2 (1X2), signed by California’s governor in April 2011, eliminated the state’s existing cost caps; new cost-containment
mechanisms are in development and have not yet been enacted.
Source: DSIRE, LBNL, Union of Concerned Scientists, DBCCA analysis 2012
Delay/Escape Clauses
By limiting the annual or marginal cost of RPS compliance, a cost cap may reduce the amount of
renewable generation that a state procures in a given year - potentially delaying achievement of annual
RPS targets. Illinois, North Carolina, and Missouri explicitly provide that, if a utility’s actual or projected
cost of meeting annual RPS targets exceeds the state cost cap (e.g. $12.00/residential account in North
Carolina, or 2.015% of the 2007 residential rate in Illinois), the state PUC may lower the utility’s annual
RPS target to the level necessary to stay within the cost cap.
21
DRAFT FOR DISCUSSION
While capping costs for the retailer rather than the consumer, Maryland, California, Oregon,
Washington, and Ohio similarly empower their PUCs to reduce annual RPS obligations if compliance
costs exceed prescribed thresholds. In Maryland the relevant threshold is a percentage of the cost of a
state’s annual electricity sale revenues in the state (e.g. 8% in 2013); in California, annual costs of RPS
compliance for the three investor-owned utilities (IOUs) are constrained by (1) the balance in the state’s
“virtual” RPS fund (currently $770 million); and (2) PUC-approved rates that the IOUs may charge their
customers to defray any above-market costs of renewable generation. Should the contents of the
“virtual” fund plus PUC-approved rates be insufficient for an IOU to procure its RPS-prescribed quantity
of renewable energy, the IOU may be relieved of the obligation to contract with any renewable
generators whose costs exceed those of non-renewable generators.
Finally, while not prescribing specific thresholds, Minnesota and Arizona empower their PUCs to
temporarily suspend RBS obligations should the cost of compliance exceed a “just and reasonable” level.
The cost caps described above set an upper limit on the incremental cost of new renewable electricity to
meet RPS targets. While examining the likelihood that every individual cost cap will prove binding is
beyond the scope of this paper,29 in general the costs of new renewable electricity are sufficiently below
the caps embedded in RPS mandates that most states are highly likely to meet their RPS obligations and
deadlines out to 2030. Evidence in support of this judgment comes from the success that several states
wind-rich states (i.e. Texas, Iowa, Oregon) have had in either meeting their end-state RPS targets or
complying with such targets well ahead of mandated deadlines. As declines in the cost of solar
technologies broaden another means for cost-effective RPS compliance (already in wide use in California
and other western states), the likelihood that states will meeting existing RPS targets without delay or
interference only increases.
How to do More – Stronger RPS targets, RAM/FiT, Transmission, RECs
This paper has so far sought to establish that (1) in the aggregate, RPS mandates through 2030 will
support 3.25 GW of new renewable generating capacity per year – a valuable but limited amount; and
(2) that – given the incremental costs of RPS compliance and the mechanisms promoting compliance –
such mandates are highly likely to be fulfilled.
For America to realize the full long-term economic, environmental and energy security benefits of
benefits of renewable energy – as well as the more immediate benefits of a vital US renewables industry
- policymakers will have to ramp up and sustain support for renewable energy demand. Four promising
measures to consider include: stronger RPS targets, best-practice procurement mechanisms, support for
transmission development, and, potentially, broader interstate REC trading.
Strengthen and broaden RPS targets
29
Given the broad latitude that many states accord to their PUCs in determining exactly what these levels are, this
suggests that the robustness of a given RPS target depends largely on (1) the cost competitiveness of the state’s
renewable resources; and (2) how willing the state’s PUC is to integrate RPS compliance into its traditional “leastcost” mandate. For more detail on potential outcomes for an RPS program, see Appendix IV.
22
DRAFT FOR DISCUSSION
Since existing RPS mandates appear highly likely to be satisfied (in many states, ahead of schedule),
states ought to examine how to make their RPS targets more robust. A state might do this by either
raising an RPS target for an existing compliance year, coupling a longer compliance timeframe with
higher end-state targets, or extending the RPS to cover entities previously omitted.
There is precedent for states undertaking such action. Perhaps the best known example is in California,
where in 2009 Governor Arnold Schwarzenegger issued an executive order increasing California’s RPS
target from 20 percent by 2010 to 33 percent by 2020. In Colorado, the state legislature in 2007
modified the state’s RPS program (which emerged from a 2004 ballot initiative) to include a higher
target; the 2007 modifications also added separate renewable energy requirements for electric
cooperatives, which previously had been omitted from the state’s RPS mandate.30 In 2010, the Colorado
legislature again increased the state’s RPS target, to its current level of 30% by 2020.
Efforts to increase existing RPS targets are currently underway in several states – notably Michigan,
where a 2012 ballot proposition seeks to raise the state’s RPS target (currently 10% by 2015) to 20% by
2025. Supporters of the Michigan ballot proposition point to the neighboring Canadian province of
Ontario – which already generates 25% of its electricity from non-hydro renewables – as evidence that
the 20% by 2025 goal is achievable.
Given the impressive progress many states have so far made toward meeting existing RPS targets, in
many states the time may be ripe to consider increase or broaden existing targets. Note that
broadening targets – via either including entities currently omitted, or increasing targets for entities
whose current targets are below the state average – may be a particularly appealing way to boost the
demand-pull of RPS programs.
Moving away from states that already have mandatory RPS programs, another option is to make existing
voluntary programs mandatory. For example, states such as Virginia and Utah have voluntary
renewable energy targets that they are still some ways from meeting.31 Making such programs
mandatory – hence introducing the economic incentives for compliance outlined above – would
significantly boost demand for renewable energy in these states.
Finally, whether by statute, ballot initiative, or administrative action, implementing new, binding RPS
targets in any of the 14 states that currently lack either a binding RPS target or voluntary goal would
serve to increase demand for renewable energy in these states.
Enabling access to the highest-quality resource: Financing Needed Transmission
PUCs can affect the actual cost of new renewable generation that comes online. One strategy for PUCs
to do this is to allow cost-recovery regimes that encourage interconnection of the highest-grade
renewable resources. In many states the sites with the highest-class renewable resources (particularly
for wind and solar) are remote from load centers and unconnected to the bulk transmission grid. Under
30
In 2010, the Colorado legislature again broadened the reach of the state’s RPS program. For investor-owned
utilities, the current target is 30% by 2020; the state’s 30 municipal electric utilities and electric co-ops must meet
a target of only 10% by 2020.
31
Conversely, North Dakota and South Dakota have voluntary targets that largely have already been met.
23
DRAFT FOR DISCUSSION
typical cost-recovery rules, new generation projects must pay to construct their own interconnection
(called a “tie-line”). For location-constrained renewable sites, however, the cost of such lines can be
very substantial – deterring new investment. Developers are reluctant to build project with no
guaranteed transmission; transmission owners are reluctant to build new lines without assurance of
demand from generators.
California has pioneered a solution to this chicken-and-egg problem with its “Location Constrained
Resource Interconnection Facility” program. Essentially, this allows the state’s three IOUs to build new
transmission lines to designated resource-rich areas and recover the costs from ratepayers on terms
similar to which they recover the costs of typical “reliability” or “economic” transmission investments
(i.e. upgrades that benefit the bulk power system generally rather than a single generator). As
renewable projects come online, they are allotted a pro rata share of the transmission costs. By
enabling development of projects that otherwise would be uneconomic, California’s LCRIF program
offers a creative way to support development of renewable resources at the lowest cost.
Other states might adopt similarly innovative programs to support interconnection of locationconstrained renewable resources.
Adopt best-practice procurement mechanisms
Renewable energy projects of different sizes require different procurement regimes. To encourage
continued cost reductions in large-scale projects (i.e. 20 MW and above), more states might procure
renewable energy contracts via reverse auction mechanisms (RAMs), such as the ones in place in
California and other states.32 To stimulate growth of smaller, distributed generation projects (i.e. 1-20
MW), more states might enact new feed-in tariff (FiT) or Clean Local Energy Accessible Now (CLEAN)
programs.
Encouraging access to the highest-quality resource: Reverse Auction Mechanisms
Assuming innovative mechanisms to finance the needed transmission, there remains the question of
how to encourage developers to build projects in the highest-capacity regions. In states with centralized
RPS procurement, one approach involves a so-called Reverse Auction Mechanism (RAM) – where
utilities solicit developers to bid in projects at the lowest $/MWh price. International experience
suggests that (1) RAMs are successful at encouraging developers to build in the highest-capacity
locations; and (2) RAMs – particularly if implemented without adequate pre-screening criteria – may
succeed in elicit low-cost bids, only to see many of these bids fail to be built as the contract prices leave
developers without sufficient incentive to build the project to completion.
For more discussion of the pros and cons and RAMs, see the attached case studies on Brazil and
California.
Broadening Interstate REC trading
32
Note that the name of the actual program in California is the renewable auction mechanism, rather than reverse
auction mechanism.
24
DRAFT FOR DISCUSSION
Expanding inter-state trade in Renewable Energy Credits (RECs) may be another cost-effective means to
meeting higher RPS targets. Each state has the discretion to choose what level of RPS compliance it will
allow through out-of-state RECs. Given the potential impacts of increase interstate REC trading on local
distributed generation, however, implementing this option may require coordinated regional or even
national action. Expanding interstate REC trading is likely to succeed only if pursued in concert the
critical energy diversity and local economic benefits of RPS programs. Hence, if pursued, greater
interstate REC trading ought with stronger carve-outs for distributed generation technologies (in
particular, rooftop solar PV).33
RPS programs and renewable resources such as wind and solar resemble each other in that they are all
location-specific: as an RPS mandate imposes responsibilities only on electric utilities within a defined
geographic jurisdiction, so too wind and solar generators will produce cost-competitive electricity only if
placed in specific locations. Regrettably, these locations do not always coincide. While large states such
as California may have diverse and plentiful resources to support pursuit of RPS goals, many smaller
states have less ability to meet RPS targets with in-state resources. Moreover, the table below
illustrates that the cost of developing site-specific renewable resources varies widely across the US.
Whereas utilities in Massachusetts and Delaware have contracted for electricity from first-of-a-kind
offshore wind projects at a cost of $185-200+/MWh, bids from onshore wind projects in Kansas’ most
recent RPS solicitation reached as low as $30/MWh.
Recognizing that in-state economic development has motivated support for adoption of RPS standards
in a variety of states, meeting the goals that have been adopted will for many states require more, not
less, interstate trade of RECs. Different states impose different (1) limits on the portion of RPS
obligations that may be used through out-of-state RECs; and (2) limits on the portion of RPS obligations
that may be met through unbundled RECs.34 The rules for REC procurement, sale and retirement vary
substantially by state, with some states only allowing RECs to cover a portion of the RPS requirement,
some disallowing out-of-state RECs, some allowing RECs to be “banked” for future years, some requiring
that RECs are bundled or only a portion can be un-bundled, and many other state-by-state variations.
The bundling vs. unbundling rules have received considerable attention as these help determine the
liquidity of a state or region’s REC market, and also the cost of both renewable power and RECs within
that market.
The majority of states have adopted relatively flexible REC procurement policies, allowing RECs to
qualify for compliance so long as the associated renewable power generated is delivered either within
the state’s relevant regional transmission organization (RTO) or independent system operator (ISO)
territory. This facilitates intra-regional REC trade – between neighboring states that are part of the
same RTO or ISO – with a goal of delivering the lowest cost renewable power to market. It is unusual,
however, for a state to allow the import of RECs from another region (outside its RTO or ISO), or for it to
allow all RECs to be unbundled (typically requiring a maximum portion of unbundled RECs), so as to
ensure that not all the employment and economic benefits of RPS-driven renewable power
33
34
Point out that we not support the Nunez bill in Congress?
For state-by-state rules on REC trading, see Appendix V.
25
DRAFT FOR DISCUSSION
development are being exported out-of-state. Currently then, the US REC market tends to fall along the
lines that define the US grid – as demonstrated in the figure below.
Figure 16 US REC Import Flows Relative to RTO/ISO
Source: “US RPS Markets and Utility Strategies”, Emerging Energy Research, 2010
Despite these state-specific requirements, there has been a general trend among RPS states towards
greater flexibility regarding regional trading of RECs. California, for example, in March 2010 decided to
allow utilities to use tradable RECs (TRECs) and unbundled renewable power (from out of state) to
satisfy the state’s RPS, up to a certain proportion of overall renewable power supply. Among other
reasons, The state was concerned it could not meet its ambitious targets35 without allowing greater
flexibility, and the policy change also intended to control the costs of renewable power by facilitating
greater REC trading within the. While over the next few years California’s RPS program will increase the
share of power that must come from in-state resources, its 2010 action is serving to stimulate broader
trading of RECs within the Western Electric Coordinating Council (WECC) states.
Currently, a lack of public information combined with multiple criteria within RPS states (e.g. technology
carve outs) and different criteria among RPS states (e.g. with regard to Alternative Compliance
Payments; allowable banking periods, etc.) exacerbates the illiquidity and fragmentation of US REC
markets. There is substantial price disparity among REC markets in the US, suggesting that such markets
are fragmented and beset by high transaction costs. This finding is supported by an analysis of bid-ask
35
Utilities are required to have 33% of retail sales derived from eligible renewable energy resources by 2020, with interim
targets of 20% by the end of 2013 and 25% by the end of 2016
26
DRAFT FOR DISCUSSION
spreads in US REC markets, which are found to be excessively high in order to cover illiquidity risks. This
is a particular problem in states that do not publish regular information on REC market conditions,
making market visibility difficulty, and sometimes resulting in consistently high REC prices that are not
necessarily reflective of market fundamentals – or how close a state is to meeting its standard without a
need for RECs.
Provided that it is implemented in a manner that protects carve-outs for local distributed generation,
increased interstate trading may help to reduce illiquidity and market “thinness”; if implemented
effectively this may help states to achieve RPS goals more cost-effectively. However, to be effective,
interstate trading would require timely and detailed public information on renewable generation, RPS
requirements, level of banking, etc. in participating states – this would enable market participants to
infer REC market conditions and minimize excessive transaction costs. Note also that implementing
expanded REC market trading may take coordinated regional or national action, and is likely to take
years to come about.
Other state and local incentives to stimulate demand for new renewable electricity
In addition to the policies described above, there are other ways for states and localities to promote
demand for renewable electricity (particularly from distributed generation sources such as solar PV).
Recent initiatives in California highlight two such measures: net metering and CLEAN (Clean Local Energy
Accessible Now) programs.
 Net metering: this policy allows owners of distributed generation systems (such as rooftop PV)
to sell excess power back to the grid, generally for the full retail price. More than 40 states have
some form of net metering, and these policies have contributed substantially to the growth of
residential solar in the US. Recently, the California Public Utilities Commission (CPUC) voted to
change the state’s “net metering cap” (which limits the amount of electricity that may be sold
back to the grid); analysts predict that the change may double the amount of distributed solar
power that is eligible for net metering (i.e. from 5 to 10 percent of California’s aggregate peak
load).36
 CLEAN programs: CLEAN programs (also known as feed-in tariffs) offer standard, fixed price,
long-term power purchase agreements; while the offered price in such programs is usually
determined up-front, it may then later be adjusted as the market responds. Such programs are
particularly promising for promoting the growth of “wholesale distributed generation,” meaning
distributed generation of 1-20 MW in size. Following passage of California Senate Bill 32, the
CPUC has recently released details of a new CLEAN mechanism in California. The mechanism,
known as Renewable Market Adjusting Tariff (Re-MAT) will be available for systems up to 3 MW
in size; the Re-MAT programs links payments to owners of renewable energy systems to the
weighted average contract price that California’s three investor-owned utilities recorded in their
Nov 2011 reverse auction.37 For more detail on CLEAN programs in general and the specifics of
California’s new program in particular, see Appendix VI.
36
37
http://www.cpuc.ca.gov/PUC/energy/DistGen/netmetering.htm
http://docs.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/167679.pdf
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DRAFT FOR DISCUSSION
Complementary Federal Policies: Extending the PTC and ITC
Since more ambitious RPS targets and new procurement mechanisms are unlikely to emerge rapidly,
federal policymakers can complement these longer-term, state-level initiatives with more targeted
transitional efforts.38 Specifically, extending the Production Tax Credit and Investment Tax Credit
beyond their current expiration/reduction dates is a promising way to support new investment in
renewable energy.39 Going forward, coordinating the interaction between shorter-term, supply-focused
federal tax incentives and longer-term, demand-focused RPS programs should be a key consideration for
design of the overall renewable energy policy framework in the US. Understanding more clearly how
these two sets of policies interact can help to inform policymakers as to what an appropriate synthesis
will look like. Requesting entities such as the National Renewable Energy Laboratory and Lawrence
Berkeley National Laboratory to examine federal-state policy interaction on renewable energy may
therefore be a wise investment.
Figure 17 Volatility of US wind installations in years surrounding PTC renewal, 1999-2012 (MW)
12,000
Annual Wind Capacity Additions (MW)
Production Tax Credit Expiration Years
Wind market likely
to drop off in 2013
Forecast / Estimate (with PTC extension)
10,000
Forecast / Estimate (no PTC extension)
8,000
6,000
4,000
92%
Drop
76%
Drop
76%
Drop
2,000
0
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Sources: AWEA, 2012; Bloomberg New Energy Finance, 2012
Conclusion
This paper finds that fulfilling RPS mandates through 2030 will support addition of 3.25 GW of new
renewable generating capacity in the US. This represents a slight decrease from the level of RPSsupported new capacity additions in 2008-2011, and amounts to roughly only one-third of total new
38
For a full discussion of federal policies, see the companion US PREF paper “Clean Energy and Tax Reform”.
28
DRAFT FOR DISCUSSION
renewable generating capacity added in the US in 2011 (9 GW). These comparisons inform a central
finding of this paper that RPS mandates will make a valuable but limited contribution to demand for new
renewable electricity in the US.
Given that deploying renewable generating capacity benefits America’s economy, environment, and
energy security, US policymakers ought to consider ways to enhance demand for renewable electricity.
Promising measures to consider include strengthening existing RPS targets, procuring more renewable
electricity through reverse auctions (for large-scale projects), and introducing more local incentives such
as CLEAN (Clean Local Energy Accessible Now) programs (for small-to-medium size projects). Provided
that they protect the energy diversity and local economic benefits of distributed generation, policies to
broaden interstate trade in Renewable Energy Credits (RECs) may be another option to consider.
In the shorter term, federal policymakers can complement state-led efforts by extending supply-side
incentives such as the Production Tax Credit and Investment Tax Credit beyond their current
expiration/reduction dates.40 Going forward, coordinating transitional, supply-focused federal tax
incentives with longer-term, demand-focused RPS programs should be a key element of America’s
renewable energy strategy.
Taking the actions outlined above will inject a healthy dose of competition and innovation into the US
power sector. Additionally, they will enable the US to continue to reap the benefits of large-scale
renewable energy deployment – including lower long-term costs, greater technological diversity,
utilities, businesses and consumers, and increased protection from the economic and security risks
inherent in fossil fuels.
Primary Authors:
Mark Fulton, Reid Capalino, and Camilla Sharples - Deutsche Bank Climate Change Advisers (DBCCA).
40
For more discussion, see our companion US PREF paper “Clean Energy and Tax Reform.”
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ABOUT US PREF
US PREF is a coalition of senior level financiers who invest in all sectors of the energy industry, including renewable energy.
Members educate the public sector to assure renewable energy finance legislation impacts the market as efficiently and
effectively as possible, with the goal of helping to unlock capital flows to renewable energy projects in the United States. US
PREF is a program of the American Council On Renewable Energy (ACORE), a Washington, DC ‐ based non‐profit organization
dedicated to building a secure and prosperous America with clean, renewable energy.
30
DRAFT FOR DISCUSSION
Appendix I: Market Structure and Relevant Policies of US Clean Energy Industry
Like nearly all other energy markets, the clean energy market in the US operates as a function of supply
and demand – with supply being provided by clean energy manufacturers and project developers, and
demand coming from users of clean electricity.
In this appendix we lay out the fundamental
components of both the supply and demand ends of the market, and explain at a high-level the
dynamics between the two.
Supply Chain
On the supply side there is a clean energy supply chain that can be split into 3 segments: the upstream,
midstream and downstream. The upstream consists of manufacturers of materials or components for
clean energy products (e.g. solar wafers), while the midstream consists of manufacturers of finished
clean energy products (e.g. solar modules). The downstream refers to clean energy project developers –
those who actually build and operate clean energy projects in the US – with debt and equity financing
sourced from a range of market players (e.g. private equity investors, banks and utilities). These
projects can range from large, utility-scale projects (e.g. wind or solar farms), to small, residential scale
projects (e.g. rooftop solar), with the former entering into Power Purchase Agreements (PPA’s) – usually
with utilities – for fixed terms and prices. This collection of sub-industries can be referred to as the
clean energy supply chain, and it is a market segment that is driven by both a combination of
government incentives and manufacturing or project economics.
Demand Pull: Wholesale vs. Retail
On the other side of the market there exists the demand “pull” created by actual users of clean power,
and these users can be either wholesale or retail. Wholesale refers to large-scale users such as utilities,
who purchase power direct from project developers (be it coal, gas or clean energy power projects)
under long-term PPA’s, thereby achieving relatively low (and fixed) prices (the “wholesale market”).
Retail, by contrast, refers to smaller-scale users, such as residential (i.e. individual households),
commercial or industrial consumers (the “retail market”). These types of buyers typically purchase
power from utilities, and the power prices paid by retail users are nearly always higher as they include
the costs of transmission and distribution (T&D), as well as a return earned by the utility for providing
these services. In addition to these price differentials between wholesale and retail markets, there are
also substantial price differences by electricity market (state and/or regional) in the US, depending on
various factors including the power mix, age of the distribution system, local taxes, and many others.
Role of Policy in the Supply-Demand Dynamic
Underlying US power markets are various policies and regulations that are designed to secure a stable
energy supply and fair pricing for consumers. In the case of clean energy, policy support has been
particularly crucial as these technologies are relatively new and are still experiencing steep cost declines
as the technologies mature and economies of scale are achieved. Figure 2 in the introduction of this
document shows the interdependent and complementary nature of clean energy markets in the US –
from manufacturers to developers to end consumers – and the main federal and state policies (both
current and expired) that underlie these market segments. In this paper we assume policy to continue
as currently scheduled: the PTC expiring at the end of 2012 for wind (or 2013 for some other types of
31
DRAFT FOR DISCUSSION
renewable power), the ITC for solar expiring at the end of 2016 (although a 10% tax credit will remain in
place beyond this date), and the already expired 1603 Treasury Cash Grant, DOE Loan Guarantee
Programs, and Manufacturing Tax Credit (MTC)
32
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Appendix II: Structure of an RPS regime and frameworks for procurement
Enactment and fulfillment of an RPS policy involves five sets of players: state legislatures and governors,
electric utilities/electricity suppliers, Public Utility Commissions (PUCs), renewable energy developers,
and utility ratepayers.
State Legislatures and Governors
Of states that have adopted binding RPS policies, most of these policies have emerged as statutes
drafted and signed by state legislatures and signed by state governors.41 The state legislature is where
the framework of an RPS program is set and its details decided; given this, efforts to amend existing RPS
programs generally must originate from and be passed by a state’s legislature.
Electric Utilities and Electricity Distribution Companies
With a very few exceptions (to be discussed below), these are the entities responsible for complying
with RPS obligations. As described below, exact methods for complying with RPS obligations vary
depending on whether the entity operates as a regulated utility monopoly or as an unregulated
distributor of electricity in a market with retail electric competition.
Public Utility Commissions (PUCs)
As the leading regulatory authorities for state electric power sectors, PUCs are the entities responsible
for ensuring that utilities and electricity suppliers meet their RPS obligations. Members of a state’s PUC
are typically appointed by and accountable to the state’s governor. The structure of the state electricity
market (i.e. regulated versus competitive) will determine how involved a PUC in overseeing the actual
procurement of renewable electricity. Most RPS statutes also empower PUCs to levy penalties on
utilities and suppliers who fail to meet their RPS targets; similarly, many statutes empower PUCs to
suspend or delay RPS compliance if the costs of such compliance exceed specified thresholds. There is
potential tension between a PUC’s role in enforcing RPS-compliance and its traditional responsibility to
protect ratepayers by ensuring procurement of least-cost generation; how PUCs manage this tension
may in certain states strongly affect how much incremental renewable deployment RPS policies support.
Developers of Renewable Energy Projects
With the exception of cases where vertically-integrated utilities build their own generation, private
developers of renewable energy projects (i.e. independent power producers) are the entities to actually
finance and install new wind turbines, solar modules, and other technologies for renewable electricity
41
Exceptions include Arizona, Colorado, and New York. Colorado's original RPS came out of a ballot
proposition (Amendment 37
http://www.renewableenergyworld.com/rea/news/article/2004/11/colorado-voters-pass-renewableenergy-standard-17736 ) while the most recent version of CO's RPS - HB 1001 passed last year came out
of the legislature, the original one came from the ballot. Arizona’s RPS was implemented by the Arizona
Corporation Commission (ACC), Arizona’s public utility commission
( http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=AZ03R&re=1&ee=1). In New York
the RPS emerged as an executive order.
33
DRAFT FOR DISCUSSION
generation. Interstate trade in electricity and Renewable Energy Credits (RECs)42 enable utilities in most
RPS states to meet their RPS obligations partly through contracting with developers outside their own
state.
Utility Ratepayers
As the ultimate source of funds for operation of the electric power sectors, utility ratepayers reap any
benefits or costs from the implementation of RPS programs. As discussed below, most RPS programs
limit the annual incremental costs of RPS compliance to a maximum percentage of annual retail
electricity sales.
Frameworks for RPS Procurement
Surveying the structure of state RPS policies, Ryan Wizer and Galen Barbose of Lawrence Berkeley
National Laboratory (LBNL) diagnose three distinct models for how renewable electricity is procured to
meet RPS targets.43
1. Retail competition model: In states where there is competition to supply electricity to retail
customers, distributors typically are able to choose how best to meet their RPS obligations. For
example, a distributor might contract to buy the electricity from a renewable generation project
via a Power Purchase Agreement (PPA); alternatively, a distributor might meet its obligations
via purchases of Renewable Energy Credits (RECs) that are “unbundled” from the underlying
electricity supply (a topic explained in more detail below).
2. Regulated procurement model: In states where electricity is supplied to retail customer via
utility monopolies, utilities typically procure electricity and RECs to meet their RPS
requirements under the oversight of regulators. An example of such a regulated, centralized
procurement scheme is the Reverse Auction Mechanism (RAM) used by California’s three large
IOUs.
3. Centralized administrative procurement model: Two states – Illinois and New York – have
transferred authority for RPS procurement to specially designated state agencies. These
agencies collect ratepayer funds and distribute incentive payments to support pursuit of RPS
goal
42
A REC is a tradable certificate that represents 1 MWh of qualified renewable energy generation; procuring and
retiring a REC can demonstrate compliance with one or more RPS requirements. See subsequent discussion for a
fuller discussion of RECs.
43
LBNL reference
34
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Appendix III: Impact of RPS Solar Carve-Outs, 1999-2011
35
DRAFT FOR DISCUSSION
Appendix IV: Potential outcomes for RPS targets – meet, delay/reduce/suspend, modify, or miss
When a state imposes RPS targets on its electric utilities, at least four outcomes can emerge. The
paragraphs below briefly examine each one.
Meet the target
With respect to the prospects for clean energy, the most promising outcome is for a state’s electric
utilities to meet the target. While Texas is so far the only state to meet a binding RPS target44, Figure X
above shows electric utilities in many states to be approaching target levels of renewable generation.
Owing to impressive additions of wind generating capacity over the past decade, utilities in Oregon
appears likely to meet their RPS targets within one or two years – making Oregon the first state to fulfill
an ambitious RPS standard. While pursuing less aggressive targets, utilities in Vermont, Wisconsin,
Michigan, and Maine also will likely fulfill their RPS targets in the near future. If this occurs, these states
would join Iowa, Texas, and North and South Dakota (all of which impose voluntary goals) in the “meet
the target” group.
Delay/reduce/suspend the target
A second outcome is that the PUC or other state officials may elect to delay, reduce, or suspend the RPS
target. Table X above shows most of the major RPS programs to include provisos outlining criteria and
mechanisms by which RPS targets may be delayed or temporarily reduced. In all cases program cost is
the key criterion for delay or suspension, with many programs also according PUCs additional discretion
to determine if a delay in implementation is warranted. As of now, cases of a PUC or other state body
intervening to delay RPS compliance have been very limited.
Modify the target
A third outcome is that state legislators may intervene to modify the RPS target. If delay involves
changes to questions of when and how much, then modification involves changes to questions of how.
The most likely route to modifying an existing RPS target is to broaden or narrow the eligible generation
technologies.45
Miss the target
A final outcome is that a state’s electric utilities may simply miss the target. At this point, depending on
the state’s enforcement clauses (and, most likely, the discretion of its PUC), the electric utilities may or
44
Note about uniqueness of Texas target
For example, on the floor of the California State Assembly was recently a bill to expand the definition of
“renewable sources” in the state’s RPS law to include hydropower plants over 30 MW. Legislative analysis of the
bill suggests that adding output from large-scale hydro facilities would immediately raise the share of “renewable”
electricity for California’s three large IOUs to 32.6% (versus 17%, excluding large-scale hydro, in 2010) – by itself
almost closing California’s GWh RPS gap. While California legislators overwhelmingly rejected this bill, it illustrates
how legislative intervention can make RPS obligations a “moving target.”
45
36
DRAFT FOR DISCUSSION
may not incur penalties such as per-MWh fines or, in extreme cases, prohibition against acceptance of
new customers.
In general, by 2030 we do expect the US to meet the demand pull from combined state RPS’, barring
some potential close misses, or downward revisions of standards. This is largely due to the robustness
of nearly all state’s RPS compliance rules (ACPs, REC trading, etc.), the relatively small amount of new
annual installations necessary, and remaining (if diminishing) policy support – in particular, the ITC for
solar which runs through the end of 2016.
37
DRAFT FOR DISCUSSION
Appendix V: Geographic Eligibility and Delivery Requirements for Renewable Energy Credits (RECs)
Sources: NREL 2010, DSIRE 2011, Wiser and Barbose 2008
38
DRAFT FOR DISCUSSION
Appendix VI: CLEAN (Clean Local Energy Accessible Now) Programs
Clean Local Energy Accessible Now (CLEAN) Programs, also known as feed-in tariffs (FiTs) offer standard,
fixed price, long-term power purchase agreements where the offered price is determined up-front, but
is then adjusted for later projects as the market responds.
Experience with longstanding CLEAN Programs, such as Germany’s EEG, suggests that a well-designed
policy can drive down costs with competition for supplying energy and the rapid learning curve that
comes with significant market scale. By providing developers with Transparency, Longevity, and
Certainty (TLC), well-designed CLEAN Programs may be able to help fulfill RPS requirements in a timely,
cost-effective manner.
CLEAN Program design has been evolving recently as more countries, states and cities gain experience in
implementing their programs. The latest example of a statewide policy design is California’s Senate Bill
32 (SB 32) clean energy law. This law mandates that the state’s three largest invest-owned utilities
(IOUs) provide a CLEAN Program for any RPS-eligible generation project up to 3 MW in size. The
California Public Utilities Commission (CPUC) approved its interpretation of the law in May.
In this interpretation, the CPUC sought to address the key risk of CLEAN Programs – setting the power
purchase price “wrong”. If the price is too low, no projects are developed, but if the price is too high,
ratepayers are harmed. A variety of price setting and adjustment mechanisms have been used across
the world, such as regular recalculation and automatic annual decreases, but SB 32 choose a market
response mechanism that has been gaining popularity: price changes based on pre-defined subscription
volume levels.
The mechanism consists of pre-defined capacity “buckets” that limit how many contracts can be
executed at a given price. The price offered to developers then changes based on subscription to each
bucket. If the bucket is filled, the price then decreases for the next bucket. If the there is minimal
response to the offered price, the price is increased. Ultimately, however, the CPUC chose to link
payments to the results of auctions by California’s three large investor-owned utilities. Payments will
initially be linked to the results of the Nov 2011 auctions.46
Since the California SB 32 program has yet to be launched, its potential to set a successful policy
example that helps meet RPS goals is unknown. Other recent programs that may serve as examples of
effective design include Ontario, Canada; Sacramento, CA; Gainesville, FL; Palo Alto, California, and Long
Island, New York. The Sacramento CLEAN program has resulted in 100 MW of solar projects in a twoyear period, all of which is interconnected to the distribution grid for serving local load (i.e., all of the
100 MW avoids all costs associated with transmission grid, which is equal to roughly 3 cents/kWh). Note
that 100 MW in Sacramento is equivalent to 2.5 GW across the State of California – suggesting that, if
adopted statewide, a CLEAN program could stimulate rapid, widespread deployment of solar in
California.
46
Described in more detail in the companion US PREF case study, “The California RAM Program”
39