Near-term surpluses of renewable energy, a sharper focus on costs and heightened concerns over environmental impacts are the new realities in the California market for utilityscale renewable power.
California’s largest investor-owned utilities are expected to slow the rate at which they procure renewable energy in the near term as they meet or draw near to meeting their regulatory mandates under the state’s renewable portfolio standard.
As the cost of renewable resources has fallen, regulators and utilities have both sharpened their pencils when it comes to new projects, and only projects that are competitive
with the new market realities are winning in utility solicitations.
Finally, regulators are more rigorously evaluating the environmental impacts of largescale solar and wind projects, and projects with significant environmental impacts face an
uphill battle to win regulatory approval.
California is not turning away from renewable energy, but developers are likely to
find a more competitive marketplace in the near term. Projects that can offer a cost
or technology advantage will fare better in this tight market. Looking farther out,
demand could rebound once regulators and legislators define the post-2020 renewable
portfolio standards. Meeting the 33% RPS Mandate
California’s renewable portfolio standard of 33% renewable
power by 2020 has led to a decade-long boom in renewable
energy project development. However, the state’s largest utilities — Pacific Gas and Electric, Southern California Edison and
San Diego Gas and Electric — have over-procured renewable
power for the near term and claim to have enough projects
under contract to meet most or all of the 2020 RPS mandate.
Presently, the utilities are exceeding annual renewable
energy targets and are banking or selling off their surpluses to
draw upon in later years. PG&E anticipates that it will not need
to draw on its banked RPS credits until 2019 and will have
enough banked credits to meet a 33% RPS requirement through
late 2023. To continue meeting a 33% annual RPS target beyond
2023, PG&E forecasts that it will need an average of 9,500 additional GWh per year from 2024 through 2030 (see Figure 1 on
page 4). SDG&E similarly anticipates that it will continue to contribute surplus RPS credits to the bank through 2019 and that,
between ongoing contracts and banked RPS credits, it has
enough contracted resources to meet a 33% RPS requirement
through 2025. SDG&E estimates that it will need an average of
2,000 GWh of incremental renewable power each year from
2026 through 2030 (see Figure 2 on page 4).
Southern California Edison’s surplus is not as large as PG&E’s
or SDG&E’s. SCE anticipates tapping into its banked reserves by
2017, exhausting its balance in 2020, and needing an additional
continued from page 1
7,300 GWh of renewable energy in 2020 to meet the 33% RPS
requirement for that year. SCE forecasts an increasing procurement deficit post-2020, with a need, on average, for an additional 13,000 GWh of renewable procurement per year to meet
a 33% RPS requirement from 2021 through 2030 (see Figure 3
on page 4).
The utilities’ assessments suggest limited contracting opportunities for renewable projects coming on line before 2020.
However, these numbers do not tell the whole story because
uncertainty associated with the utilities’ forecasts may increase
or decrease the forecasted need for additional renewable procurement. These uncertainties affect both the demand and
supply sides of the equation.
On the demand side, the primary uncertainty is the level of
future electricity sales. If sales (i.e., consumption) are higher
than anticipated in the RPS assessments, then RPS requirements will be correspondingly higher and the utilities will draw
down banked credits more quickly. The need for new procurement would occur earlier than currently anticipated. This is a
symmetrical risk, as lower electricity sales would reduce the
RPS requirement and delay the
need for new procurement.
In addition to the utilities’
preferred RPS procurement
forecasts presented above, the
utilities also developed alternate forecasts that use sales
assumptions from the California
Public Utilities Commission.
Under the alternate sales forecasts, PG&E would have less
need for incremental renewable
procurement than in its preferred forecast (with PG&E’s RPS
procurement deficit delayed
from late 2023 to 2025), and SCE would have greater need for
incremental renewable procurement than in its preferred forecast (with SCE’s RPS procurement deficit starting in 2019
instead of 2020).
On the supply side, there is the risk that some contracted
projects will fail to achieve commercial operation or will be
delayed. Projects under development face any number of
hurdles in financing, permitting, interconnection and completion of construction. Delays and cancellations are not uncommon. Historical project failure rates have been as high as 30% to 40%. While failure rates appear to have fallen significantly in
recent years, project delays and failures remain a concern.
Many of the projects included as existing contracts in the
utilities’ procurement plans remain under development. For
example, as of December 2013, only about half of the 74
renewable energy projects included in SDG&E’s plan to meet
its 2020 RPS were operational, with nine projects under construction and 27 projects in the pre-construction phase.
SDG&E has acknowledged that some of these projects are
experiencing project development-related issues that may
affect their ability to meet commercial operation deadlines or
even to come on line.
Development risk is accounted for in the utilities’ procurement plans to varying extents. SDG&E assigns a probability of
success to each individual project, with an average success rate
of 75% for approved projects that have not yet begun delivering
energy. SCE uses project-specific, risk-adjusted success rates for
large, near-term projects that are not yet on line and a success
rate of 50% for projects with commercial operation dates more
than three years out. PG&E assigns a success rate of 0% to highrisk projects and assigns a success rate of 100% to all other projects. PG&E defines high-risk projects as those that have failed
to meet contractual deadlines or have certain known issues
that place them at risk for doing so, as well as projects that
were operating in the past but have ceased operation.
Accordingly, it appears that PG&E would assign a success rate
of 100% to a newly-contracted project that had not yet
received CPUC approval as long as that project had no known
financing, permitting or interconnection issues. To the extent
that this assessment or the other utilities’ risk assessments
underestimate project failures and delays, there may be a need
for additional renewable procurement to replace contracts that
do not deliver as planned.
There is a possibility, as well, that the CPUC will modify the
risk assessment approach that is used in the calculation of
need for new renewable procurement. The CPUC is concerned
that the utilities’ assumptions of project risk are insufficient.
The utilities’ confidential assessments have not been benchmarked against actual project success, and the utilities have
been unwilling to provide data publicly that would allow such
In February 2014, the CPUC staff proposed formal benchmarking of utility risk assessments through an independent
analysis of projects under development using a public methodology that assesses a project’s risk based on the following weighted project viability categories:
project technology (10%), the developer’s experience (15%),
site control status (25%), permitting status (25%) and interconnection progress (25%).
Under the proposal, the CPUC staff would assign each
project a viability score based on a standard rubric that assesses
each of these elements using pre-determined metrics. (This
rubric would be a simplified version of the existing “project viability calculator.”) For example, the score for developer’s experience would be assessed as follows: 50 points for no
demonstrated experience developing renewable energy projects, 75 points for any demonstrated experience developing
renewable energy projects, 90 points for demonstrated experience developing renewable energy projects of similar size and
technology, and 100 points for demonstrated experience developing renewable energy projects of similar size and technology
in the utility’s service territory. The CPUC staff would use the
project viability score to adjust a utility’s entire portfolio of RPS
projects under development for risk. Staff would then benchmark the staff’s risk adjustment scores against each utility’s
own risk adjustment to determine if there are any outliers that
the utility would be required to justify in its annual RPS plan.
The CPUC is expected to issue a decision on this matter in
the second quarter of 2014. It is too early to predict whether
the decision will increase contracting opportunities.
Additional contracting opportunities could also emerge if the
utilities sell some of their surplus renewable power to third
parties with near-term need for renewable energy credits. For
example, if an entity with the need for RECs in 2015 purchases
some of PG&E’s banked RECs, PG&E’s need for new power contracts could advance by several months or more in the early
2020s when it currently anticipates relying on banked credits to
meet its RPS requirements. This situation would open up new
opportunities for competitively-priced renewable energy projects that are not already operational (i.e., projects that could
not meet the near-term REC need directly but could meet the
replacement power need in the early 2020s). The utilities have
said that they will sell banked credits only if the sales price is
higher than the replacement power cost. This is possible given
the steep decline in renewable prices in recent years; however,
opportunities are likely to be limited.
Focus on Price
The cost of the renewable energy contracts that make up the
current RPS portfolio has prompted both concern and optimism in California.
The concern is that expensive renewable energy will lead to
higher retail electricity rates for consumers at the same time
that other factors are already driving up power costs. For
example, Energy and Environmental Economics, Inc. forecasted
in 2012 that rates in 2020 will be 8% higher than they would be
under an all-gas scenario due to the 33% RPS, while prices will
be more than another 11% above 2011 rates in real terms for
non-RPS reasons such as the need to replace aging transmission
and distribution infrastructure, pay for Smart Meter projects,
and repower or replace generators to comply with oncethrough cooling requirements. On the other hand, there is room for optimism due to the
decline in renewable energy prices over the last few years.
While the weighted average price of bundled renewable contracts approved from 2003 through 2011 was 12.2¢ per KWh
for PG&E, 10.1¢ per KWh for SCE and 11.6¢ per KWh for SDG&E
(in nominal dollars), bundled renewable contracts approved in
2013 had declined on average to 6.7¢ per KWh for PG&E, 8.9¢
per KWh for SCE and 7.5¢ per KWh for SDG&E. This decline
reflects lower bid prices in the 2010 to 2012 RPS solicitations,
consistent with industry-wide cost reductions.
Given these cost reductions, regulators are now able to exercise some cost discipline and greater selectivity in approving
modifications to existing contracts, knowing that modifications to contracts from past solicitations that are denied are
likely to be replaced by lower-cost contracts in future solicitations. So far, however, the CPUC has been very selective
in exercising this option, with the rejection in October 2012 of
three of BrightSource’s proposed solar thermal projects being
the notable exception.
Despite the downward trend in prices, legislators have
expressed concerns with the upward pressure on retail electricity rates resulting from RPS procurement. As part of the 2011
legislation that increased the RPS from 20% to 33%, the CPUC is
required to implement a “procurement expenditure limitation”
in order to impose some cost discipline on the RPS procurement
process. The CPUC is currently considering methods for establishing such a limitation. The CPUC staff has proposed a
method that would establish a ratio of RPS procurement
expenditures to a utility’s total revenue requirement over a
10-year period. The ratio would provide a benchmark to indicate whether the forecasted
RPS procurement is likely to put
upward pressure on retail electricity rates. Other parties have
proposed alternative methods.
According to an illustrative
example provided by CPUC
staff, SCE’s annual “procurement expenditure limitation”
ratios under the staff’s proposed methodology would
range from 14.6% to 21.2% over
the 10-year period from 2014
through 2023. The ratio would
essentially set an overall budget
for SCE of $26.9 billion to spend on procuring RPS-eligible
energy in that time frame. In 2013, SCE spent $1.4 billion, or
11.9% of total revenue requirement, to achieve an RPS level of
23.2%. Adjusted to account for the higher 2014 to 2023 RPS
requirement, this level of expenditure — $17.4 billion over the
10-year period — would still remain well within this illustrative
budget. While these results are merely illustrative since a final
methodology has not yet been adopted, given this outcome, it
remains to be seen whether the procurement expenditure limitation methodology will impose real price discipline or will
serve only as a high ceiling price.
Regardless, price discipline will continue through competition
among renewable energy developers. Market competition and
reduced project costs have driven down the cost of newly-approved renewable contracts by more than 25% since
2011 and are likely to continue putting downward pressure on
prices, particularly if new contracting opportunities remain
limited in the near term.
Minimizing Environmental Impacts
Environmental concerns over the impacts of large-scale renewable energy projects are moving to the foreground as well. This
reflects to some degree the knowledge and experience gained
as the initial wave of renewable projects complete construction and begin operations.
In December 2013, a California Energy Commission siting
committee released a proposed decision recommending that
the CEC deny BrightSource Energy’s application to convert the
proposed 500-MW Palen project from a solar thermal parabolic
trough project to a project that uses BrightSource’s solar
thermal power tower technology, in large part due to concerns
over avian mortality.
The Palen project’s power tower system would create steam
by using a field of 85,000 elevated mirrors known as heliostats
to focus the sun’s rays onto a steam generator that sits atop a
750-foot tower near the center of the heliostat field. As proposed, Palen would consist of two adjacent 250-MW fields.
The CEC previously approved a different BrightSource
power tower project, the 377-MW Ivanpah project, which
consists of three 459-foot power towers and 173,500 heliostats. The CEC approved the Ivanpah project in September
2010 and concluded that the clean energy benefits of the
project outweighed its significant impacts on cultural, visual
and environmental resources, and that no feasible site or
generation technology alternatives to the project existed
that would reduce or eliminate the project’s significant environmental impacts.
Concerns about the impact of power tower technology on
avian mortality began to surface during construction of
Ivanpah, when BrightSource’s monthly compliance reports filed
with the CEC listing avian deaths indicated possible increased
mortality, particularly during the migratory months.
BrightSource reported 23 avian deaths at Ivanpah in January
2014, up from the 13 deaths recorded in December 2013 and
11 reported in November 2013, but still less than the 52
reported in October 2013.
In the proposed decision denying Palen, the CEC siting committee, consisting of Commissioners Douglas and Hochschild,
concluded that, as proposed, Palen would result in significant, unmitigable impacts on local environmental, visual and cultural resources, and that the solar flux generated from the project’s solar towers would probably harm birds.
The committee said the original solar trough project or a conversion to photovoltaic technology would be the preferred
options for the project site. In an effort to avoid a CEC decision
denying the project, BrightSource requested that the commission postpone voting on the proposed decision until at least the
spring of 2014, to allow the company more time to present
additional data on avian mortality being gathered at Ivanpah
and from other projects employing alternative solar
technologies. The difficulties faced by BrightSource are, to a certain extent,
technology specific and are not indicative of a wholesale
change in sentiment against large-scale solar. At a January 2014
conference on the proposed decision regarding Palen, the CEC
noted that BrightSource still has the option to build Palen as
the solar thermal parabolic trough project that has already
been approved or to propose a different project on the site.
Commissioner Hochschild specifically asked concerned parties
not to read the proposed decision as a strike against solar
thermal and emphasized the benefits of the technology, stating
that he believed it has a role to play as California expands its
clean energy portfolio.
That same month, the CEC also demonstrated that significant environmental impacts will not necessarily undermine a
renewable project, as it unanimously approved an amendment
to modify the proposed Blythe project from a 600-MW solar
parabolic trough project to a 485-MW solar PV plant, even
though significant environmental impacts were identified. The
CEC concluded that the project would result in benefits that
outweighed these impacts and that there were no feasible
alternatives to the project that would reduce or eliminate any
of the impacts.
Environmental impacts are also a concern with wind projects, and avian mortality issues in particular have come to the
fore in this context as well. The US Department of the Interior
recently began granting wind developers eagle “take” permits
lasting up to 30 years that, under the Bald and Gold Eagle
Protection Act, shield projects from liability for unavoidable bird
deaths at wind plants. (In the past, the Interior Department
only issued take permits that lasted for up to five years.) To be
eligible for these extended
permits that will be subject to
review every five years, wind
plant operators must agree to
regular monitoring and adaptive
conservation measures. This
approach provides greater certainty for renewable energy
developers while offering some
measure of protection to threatened species.
These decisions, both at the
CEC and the Department of the
Interior, show how government
agencies are trying to find a
balance between renewable energy development and environmental protection. The agencies are still trying to find the right
balance, and this creates risk for developers. While most projects that are thoughtfully sited are not likely to be rejected on
environmental grounds, as BrightSource found, the risk of rejection is all too real, particularly for less-tested technologies.
Potential New Opportunities
Despite the slowing growth in demand for renewable energy
projects, downward price trends and more stringent reviews of
environmental impacts, opportunities for new utility-scale
renewable projects still exist in California.
The utilities’ assessments of when they will need to ramp up
procurement of renewables and how much to procure are
based on a 33% RPS mandate. The likelihood is quite high that there will be a need for a greater level of renewable resources
after 2020 as California continues to pursue its goal of reducing
greenhouse gas emissions to 80% below 1990 levels by 2050.
As part of that effort, the California Air Resources Board has
recommended that the RPS target for 2030, expected to be
above 33%, be set in 2016 to allow enough time for contracting
In addition, the state legislature recently granted the CPUC
the authority to require utilities to buy more renewable energy
than required under the RPS requirement. While the CPUC has
not indicated its intention to do so on a universal basis, this
could open up opportunities in specific circumstances. For
example, a March 2014 decision that directs Southern
California Edison and SDG&E to procure 40% (600 megawatts)
of the power needed to replace the closed San Onofre nuclear
power plant from preferred resources may lead in the near
term to opportunities for new renewable power development
above the RPS-driven requirements.
A similar opportunity would likely emerge in the event that
the PG&E Diablo Canyon nuclear power plant licenses are not
extended beyond their current expirations in 2024 and 2025.
The CPUC has already put PG&E on notice that the utility will
need to justify the economic costs and benefits of the large
nuclear plant before the CPUC authorizes any ratepayer funding
for a federal relicensing application. Should the plant not be
relicensed, the carbon-free power that Diablo Canyon currently
generates is likely to be replaced to a large degree from renewable resources and other preferred resources.
Additional opportunities could also open up in the near term
due to utility load growth (which triggers the need for additional RPS procurement since the RPS target is a percentage of
load), unanticipated contract failures, a change in the methodology for predicting contract failure rates, or utility sales of
banked RPS credits to third parties. These opportunities are
likely to be limited.
Renewable projects that incorporate energy storage technologies may have an advantage in upcoming solicitations.
California faces a significant challenge in balancing the increasing share of variable energy resources on the grid, and the CEC
and the CPUC have both made it clear that they are looking to
storage as part of the solution. For example, CEC Commissioner
Douglas indicated that the addition of thermal storage capability would greatly strengthen BrightSource’s application for the
Palen project. Similarly, when the CPUC rejected three
BrightSource solar thermal contracts in part on economic grounds, the CPUC at the same time
accepted an uneconomic BrightSource contract for a solar
thermal project with accompanying storage and even accepted
a second uneconomic BrightSource contract for a solar thermal
project on the grounds that the project was needed to lay the
groundwork for a more advanced project with storage to be
financed and built.
Renewable projects with storage may be eligible to bid in the
solicitations that the utilities are preparing to issue by
December 2014 to procure additional storage capacity toward
meeting a CPUC-mandated target of 1,325 MW of storage by
the end of 2024.
Thoughtful project siting will also remain key. The US
Department of Energy and the US Bureau of Land Management
jointly established the solar energy zones program in 2012,
which identified 17 solar energy zones in the western US,
defined as areas with few impediments to utility-scale production of solar energy where BLM would prioritize solar energy
and associated transmission infrastructure development. In
addition to the 285,000 acres in the 17 solar zones, BLM identified roughly 20 million acres outside of the zones that are available for right-of-way or lease applications if developers apply
for a “variance.” Projects in these zones will have permitting
advantages over projects located outside of these preferred
Laura Norin, Julia Getchell and Heather Mehta