Experience of some countries related to
Variable Renewable Energy (VRE) and Lessons to be learned
Transmission and Interconnection requirements
Indifferent
and faulty planning has resulted in waste of VRE in many countries. India is
facing a curious problem: too much solar and wind power in some parts of the
country. In July, 2016 for the first time, the southern Indian state of Tamil
Nadu was unable to use all the solar
power it generated. Tamil Nadu, urging
to speed up the construction of an inter-state green energy corridor
that would allow renewable power to be transmitted and used in other states
instead of being wasted. From India to China to Chile, a significant portion of future renewable
energy could go to waste without careful planning.
Solar
and wind only accounted for 3.5 percent of the power generated in India in
2015. But if the government achieves its ambitious targets for renewable energy
deployment, the amount of solar and wind power on the grid could quadruple by
2022. Yet there are already signs that the grid’s ability to absorb these new
power sources could be a major bottleneck for renewable energy growth in India,
jeopardizing the country’s energy and climate goals. .The
problem is, in part, a technical one. Solar and wind power are not as easy to
control as traditional fossil fuel plants, so power grids need to become
flexible enough to handle last-minute changes in power generation.
Distance
is also an issue. In India, six states in the western and southern regions account for 80 percent of all of
the country’s currently installed solar capacity, but only 38 percent of power
demand. For grid operators used to being able to turn fossil fuel plants on and
off at will, these changes can take some getting used to. If new measures are
not put into place to accommodate variable renewable energy sources, a
situation can arise when the physical grid or the grid operator is unable to
use solar and wind power when it becomes available.
Other
countries have already dealt with this problem with varying degrees of success.
Germany and the U.S. have relatively
high levels of solar and wind penetration and low curtailment rates, while China has had major issues with
curtailment as the share of wind and solar in the energy mix increases.
Indeed,
China currently has more wind and solar power capacity than any other country
in the world after scaling up very quickly. In the five years between 2010 and
2015, the share of solar and wind power generated in China quadrupled. Yet in
2015, the U.S. still produced more electricity from wind
than China, despite having only 58 percent of China’s installed wind capacity.
A large reason for this discrepancy is that much
of China’s solar and wind power is wasted: 21 percent of wind power was curtailed in the first half of 2016 (with
Gansu province reaching a 47 percent curtailment rate), and solar curtailment reached 11 percent in the first three quarters of 2015.
Although
China has been able to build out renewable energy capacity quickly over the
past decade, it has taken much longer to develop the transmission
infrastructure and make the institutional changes required to utilize all of
this new power.
India
has undertaken to build the green energy corridor, a series of
transmission lines that will connect states with excess renewable energy to
areas where there is unmet demand. And similar to China, solar and wind
already have “must run” status, meaning that any power they generate should
always be accepted by the grid.
Yet
even these steps may not be enough. A recent survey found that 31
percent of senior corporate leaders in Indian solar companies think that grid
integration will be the biggest challenge for expanding solar in India going
forward.
The
first priority for India, when addressing this issue, is to finish the green
energy corridor and other new transmission lines so that renewable power can be
transmitted where it is needed. There are significant power surpluses in some
states and power deficits in others.
For
instance, Uttar Pradesh has a peak power deficit
of 9.7 percent (meaning 9.7 percent of demand at peak times cannot be met with
the power available in the state), whereas the bordering state of Madhya
Pradesh has a peak power surplus of 8.3 percent. Yet the power connection
between the two states was at full capacity 73 percent of the time in May 2016,
meaning some surplus power in Madhya Pradesh may not have made it to Uttar
Pradesh. Nationally, 10 percent of the power supply available on the short-term markets last year
could not be used because of transmission constraints.
New
investment in inter-state power lines will help balance out such disparities.
It is particularly important for India to attract private investment in these
projects. The green energy corridor will
cost an astounding USD $3.4 billion, and is funded in part by government funds
and partially by a $1 billion loan from the Asian Development Bank and €1 billion loan from GiZ. But the public
sector can only fund so many multibillion-dollar projects, and many state utilities are already in poor financial conditions.
Private
capital is projected to be required for 47 percent of infrastructure investment
in India between 2012 and 2017. India’s planning commission has created a framework for
public-private partnerships for transmission investment, but land acquisition
and permitting are still major roadblocks for private developers hoping to
complete a project on schedule. Reducing the time and cost of land acquisition
will be essential to making infrastructure projects attractive to developers
and unlocking the private capital needed to finance transmission lines.
Second,
focusing on deploying distributed energy technologies like rooftop solar can
help increase the amount of renewable energy in use where new transmission
lines are infeasible or too expensive.
India
hopes to get 40 percent of its solar capacity from rooftop solar by 2022, but
the market has been slow to take off despite a 30 percent capital subsidy from
the government. The barriers to rooftop solar deployment are often more
institutional than technical. In China, slow subsidy disbursement and a lack of
financing have caused rooftop solar deployment to fall short of government targets.
In India, a recent survey found that 93
percent of senior corporate leaders in the Indian solar sector did not think
the country would even reach half of its rooftop solar target by 2022, citing ineffective net metering policy,
unavailable and expensive financing, and consumer awareness as top issues.
Solutions
There
are a number of potential solutions:
Training for distribution utilities unaccustomed to having customers generate
their own electricity; streamlining the application and approval process;
creating certifications to ensure installer quality; and
even allowing rooftop solar systems to serve as backup power when the grid
goes down. Quickly implementing such solutions can allow renewable to grow
without worsening curtailment.
Energy
storage can also play an important role in reducing curtailment. The cost of storage is still a major
barrier to mass adoption, but prices are dropping quickly.
Moreover,
Germany and Texas have achieved low curtailment rates with minimal energy
storage and high renewable energy penetrations through improved grid planning and changes to
the power market structure. Still, India is planning on installing 10
gigawatts of pumped hydro energy storage across the country to
accommodate increased renewable energy penetration (China is taking similar measures to reduce
curtailment). As the price of energy storage drops, it will become an
increasingly compelling complement to variable renewable energy.
Finally,
India can look to other countries to find grid planning and operational
solutions to help manage curtailment as renewable power scales up. One such
change, highlighted in a recent Paulson Institute report
on curtailment, is to create financial incentives against curtailing renewable
energy.
Currently,
Indian solar and wind generators are not compensated for curtailment, and
compensation should not be necessary because renewable have “must run” status.
However, financial incentives can help reinforce such regulations when mandates
alone are insufficient. China has had a similar experience with “must run”
mandates: multiple policies have stated that solar and wind should always
receive priority on the grid, but curtailment continues to be an issue because
there are few penalties for ignoring this regulation.
A
recent regulation released by
China’s National Development and Reform Commission requires that coal plant
owners pay wind or solar plant owners whose energy is curtailed, creating a
stronger incentive for grid operators to fully utilize renewable. An even
simpler solution would be to compensate solar and wind projects for any
curtailed energy at a fixed rate. This not only penalizes grid operators that
choose to curtail renewable, but also provides more certainty for power
producers when trying to forecast revenue.
Even
smaller changes to how the grid is operated can make a difference. In Texas,
grid operator ERCOT shifted from 15-minute dispatch
intervals on the intra-day market to 5-minute intervals, allowing for more
granular planning around variable wind and solar power plants. (India currently
uses 15-minute dispatch intervals.) ERCOT also shifted from targeting 0 percent
curtailment to a maximum acceptable curtailment rate of 3 percent of annual
renewable energy production -- a more cost-effective solution than trying to
utilize every unit of electricity generated at peak times.
Such
institutional changes can provide flexibility to the grid without the high risk
and cost of major new transmission and storage projects. Yet a successful
energy transition will require a broader change in the infrastructure and
institutions that support renewable -- not just targets themselves.
INDIA SMART GRID PROJECT
GE Power’s Grid Solutions business
has commissioned the first leg of a huge grid-stabilization project in India. The company says the project for Power Grid Corporation of
India Ltd (PGCIL) is the world’s largest Wide Area Monitoring System (WAMS)
solution. Sunil Wadhwa, Leader of GE Power’s
Grid Solutions business in South Asia said, “The commissioning of the Wide
Area Monitoring System technology of this scale and size is unparalleled in the
history of power transmission in India. This will prove to be an important
milestone in ensuring supply of uninterrupted, 24/7 high-quality power supply
and integration of renewable energy with the country’s electrical grid.”
The project is part of the Unified
Real Time Dynamic State Measurement (URTDSM) initiative that entails monitoring
and controlling of the electricity supply across the country and has been
executed by GE T&D India, part of GE Power's Grid Solutions business in
India. The commissioned first stage will enable PGCIL to monitor power flow
across 110 substations in the Northern Grid and respond to fluctuations within
a fraction of a second. The northern grid covers nine control centers: Punjab,
Haryana, Rajasthan, Delhi, Uttar Pradesh, Uttarakhand, Himachal Pradesh, Jammu
& Kashmir and Chandigarh.
GE says “this will be critical in
addressing power demand-supply imbalances and ensuring grid stability
benefitting from the integration of renewable energy with the grid” When fully commissioned, this new WAMS solution
will be the world’s largest comprised of 1,184 Phasor Measurement Units
(PMUs) and 34 control centers across India, 350 substations in
the national grid.
GE said the solution obtains input
data 25 times per second from all the PMUs installed, whereas conventional
SCADA sampling occurs once in nearly five seconds.It also offers real time
views on geographic displays, analytical applications and the capacity to store
500 TB of data.
Moreover, it will also fully secure
the grid from any cyber security threat, incorporating the latest firewall
policies. The development and testing of the new software and substation
devices was undertaken by GE teams from India, the UK and USA supported by
PGCIL teams for duration of two years.
GE Power Chief Digital Officer Steven
Martin added: “The digital transformation of the energy sector is one of
the globe’s greatest imperatives today. It’s exciting to see PGCIL harnessing
the benefits of real-time data monitoring, improved decision making, and
stronger cyber protection in order to ensure a steady, resilient power supply.”
Scaling Up Together
In 2015, India joined with France to launch the International Solar Alliance (ISA), a
cooperative endeavor to facilitate the spread and adoption of solar energy. The
ISA, the first international organization headquartered India, is open to 121
countries lying in the sunshine-rich area between the Tropic of Cancer and the
Tropic of Capricorn. Together, these countries — of which 68 have joined the
ISA so far — account for nearly three-quarters of the world's population but
only 23 percent of global solar capacity, and most are poor or middle-income
states. The organization, which held its first summit in March of this year,
will afford India an opportunity not only to demonstrate its knowledge of
scaling up solar power, but also to assert its leadership in the developing
world.
The ISA doesn't require binding commitments of its members, nor
does it aim to disburse large volumes of funding. Instead, it recognizes the
challenges countries, particularly poorer countries, still face in adopting
renewable energy. Financing the construction of solar infrastructure, for
example, remains a major obstacle for developing countries, accounting for up
to 75 percent of total project costs in some cases. The costs of some of the
technology required generating and use solar power, such as storage technology,
also is prohibitive for up-and-coming states, despite a steady decline in
prices. On top of that, the
market for solar energy in smaller states may be too limited to attract
investors, and governments may struggle to differentiate among the array of
technologies and policies to find the best fit for their domestic energy needs.
Designs and certification standards for solar appliances relevant to rural
living — like water pumps and street lights — have significant room for
improvement as well.
To overcome these obstacles, the ISA proposes to pool resources
such as technical expertise and policy know-how, along with demand for solar
power itself, among its members. The organization hopes that the resulting
integrated market will draw $1 trillion in investment and additional solar
capacity of 1,000 gigawatts across member states by 2030. In answer to the
financing problem, the ISA is launching a new initiative called the Common Risk
Reduction Mechanism, expected to come online in December. The mechanism will,
as its name suggests, reduce investor risk — from fluctuating local currency
exchange rates, political change or nonpayment from a new solar utility's
customers — by pooling and securing finance across multiple projects in
multiple countries. Banks, private investors and the Green Climate Fund are
pledging $1 billion to the initiative, and the ISA expects the investments to leverage
an additional $15 billion of private sector funding. All told, the organization
estimates that the Common Risk Reduction Mechanism will lower costs for solar
projects in its poorer member’s states by about half. Other initiatives include
training 10,000 solar technicians and setting up centers in member countries to
focus on innovation, research and development, testing, quality control, and
certification.
Negative Prices
Negative
prices are a price signal on the power wholesale market that occurs when a high
inflexible power generation meets low demand. Inflexible power sources can’t be
shut down and restarted in a quick and cost-efficient manner. Renewable do
count in, as they are dependent from external factors (wind, sun). On wholesale markets, electricity prices are driven by supply
and demand which in turn is determined by several factors such as climate
conditions, seasonal factors or consumption behavior. This helps to maintain
the required balance. Prices fall with low demand, signaling generators to
reduce output to avoid overloading the grid. On the French and German/Austrian
Day-Ahead market and all Intra-day markets of EPEX SPOT, they can thus fall
below zero. In some circumstances, one may rely on these negative prices to
deal with a sudden oversupply of energy and to send appropriate market signals
to reduce production. In this case, producers have to compare their costs of
stopping and restarting their plants with the costs of selling their energy at
a negative price (which means paying instead of receiving money). If their
production means are flexible enough, they will stop producing for this period
of time which will prevent or buffer the negative price on the wholesale market
and ease the tension on the grid. Negative prices are a signal, an indicator
for market participants. If producers decide to keep their production up, they
have calculated that this is the best, most cost-efficient way for them
considering the costs of shutting down and restarting their plants. In
addition, negative prices are an incentive for producers to invest in the
development of more flexible means of production that can react more
efficiently to fluctuating energy supply in order to increase security of
supply and prevent
the integration of large amounts of wind and solar power is a big
challenge for RTOs and electric utilities, since they must keep the power grid
stable (balancing supply and demand) even as highly variable power sources like
wind and solar connect themselves to the grid . Large-scale wind and solar also
pose challenges for electricity markets. Because wind and solar have basically
zero marginal cost (remember that once the plants are built, fuel from the wind
and sun are free at the margin), enough wind and solar power can drive down
prices in the day-ahead and real-time energy markets. The frequency of LMPs
that are at zero or even at negative levels has been increasing in markets with
high levels of market participation by wind and solar energy producers. The
figure below shows the frequency of negative prices in the California ISO
during different hours of the day over the past few years (remember that a
negative price means that a power plant is paying to produce electricity, and
consumers are paid to use electricity). Note that during the daytime (hours 8
through 18 in the figure, which is 8:00 am to 6:00 pm) the price in the
California market was negative more than 10 percent of the time in 2016,
compared to a few percent of the time in 2012 and 2014.
Negative
prices in electricity markets can arise for two different reasons. The first is
operational inflexibility, as a signal that supply is greater than demand.
Suppose that a base-load gas plant with a very slow ramp rate was running at
full capacity to meet electricity demand. At some point, wind energy production
increases rapidly, so that there is more supply on the grid than there is
demand to absorb that supply. The grid operator has two options – production
from the wind can be curtailed (which has happened, as discussed in the Vermont
article) or production from the base-load power plant could be curtailed, which
comes at the risk of damaging the power plant. If the grid operator chooses
neither action, then the price becomes negative. In this case while a negative
price seems strange, there are perfectly good economic reasons for the price to
become negative.
The second reason that negative prices arise is because of
subsidies to wind and solar technologies. Many wind power plants, for example,
receive a subsidy known as a Production Tax Credit for every MWh that they
produce. This subsidy, currently equal to $23 per MWh, gives wind
projects an economic incentive to produce as much electricity as possible. It
is even possible that a wind project would accept a negative price in order to
get the $23 subsidy for each MWh generated. If the plant gets
paid $23/MWh and the price is -$5/MWh, the net revenue
for the plant is still $18/MWh. Thus, some
renewable energy market participants submit supply offers into the day-ahead or
real-time market at negative prices, all but ensuring that their offers will be
the cheapest.
RTOs whose territories cover
areas with a lot of wind and solar production (most notably the California ISO,
the Midcontinent ISO and ERCOT in Texas) have had to adjust their market
protocols to handle large quantities of wind and solar power.
The Midcontinent ISO (MISO) began a program called Dispatchable
Intermittent Resources (DIR) to avoid having to manually shut down large
quantities of wind energy. The DIR program allows wind energy resources to
participate like every other generator in the MISO real-time energy market as
long as a binding production forecast is provided to MISO.
The California ISO faced a
very different problem, as their footprint has seen more rapid growth in solar
energy than in wind energy. High levels of solar PV (without accompanying
energy storage) pose a peculiar problem for grid operators in that it inverts
the traditional daily demand pattern. Grid operators are used to seeing high
demand for electricity in the middle of the day and lower demand at night, with
the shift between high demand periods and low demand periods being rather
gradual. With high levels of solar PV (which produce a lot of electricity during
the day), the needs of the grid flip – fewer other power plants are needed
during the day and more are needed at night. Moreover, the shift between the
daytime and night-time load pattern becomes very sudden.
This is captured in a graphic
known as the “duck curve,” shown above. The duck curve shows the demand for
electricity (net of solar PV production) on California’s grid during each hour
of the day as more solar PV comes on-line. Not only is the electricity demand
in the middle of the day (again, net of solar production) pushed very very low,
but the increase in electricity demand between 6 pm and 8 pm is rapid and very
large in magnitude. The three-hour increase in demand of 10 GW shown in the
figure above is roughly like powering up the entire state of Wisconsin in three
hours.
California’s needs in integrating solar power into its markets are
thus different from MISO’s needs. MISO needed a way to reduce the frequency
with which it had to manually turn off wind energy production. California
needed a way to pay for power plants with short start times and very high ramp
rates, to handle the afternoon increase in non-solar electricity demand.
California’s response was to develop a kind of real-time market that clears
every five minutes, not every hour. This market, known as the Energy
Imbalance Market was designed primarily to attract fast-ramping power plants,
energy storage installations or any other resource that could response quickly
enough to the five-minute market signal.
Conclusions
Induction of
VRE energy into a power grid requires detailed planning. The central issue is
the capacity of the transmission system to transfer large blocks of powers and
to be able to retain integrity with sudden loss of power or sudden availability
of power. Wind and solar do present a challenge to the intergraded grid systems
and this needs to be expensively modeled and
plans needs to be prepared and implemented in time to fully unitize the
benefits of VRE .
