IEEE Power & Energy Magazine - January/February 2021 - 82

Institutional capacity is at the core of achieving good results
of many market reforms in the power industry
of the developing world.
Highly inflexible PPAs force inefficient coal units to
run at 55-70% minimum loading, although 62% or ~127 GW
of the existing coal capacity has operating costs greater
than those of new renewable projects as of 2018. As coal
PPAs dominate generation, the day-ahead market (DAM)
has extremely low liquidity of 4% after nearly 12 years of
operation. There has been no participation of solar/wind
in the market. There are close to 50 GW of hydro in the
system, but the larger storage units are multipurpose projects with restrictions on their ability to provide ancillary
services. There is limited flexibility in the system and no
ancillary services market set up to incentivize entry of
new capacity.
The interstate transmission system is very robust, with
more than 100 GW of capacity already in place, including
±800 kV of HVdc and a 1,200-kV HVac line under construction. However, intrastate transmission capacity has been a
bottleneck, and renewable curtailment in some states, especially wind in the south, has been triggered by such constraints. Regional electricity trade has been well below 1% of
the annual regional electricity demand consistently for more
than a decade, making it one of the least connected regions
in the world.
Going forward, here are suggestions for possible solutions to address these issues.
✔✔ A structured coal plant retirement program needs to
be developed by expanding on the 25-GW coal plant
retirement (by 2027) slated in the current government
plan. Coal plants can be repurposed wherever possible
to retain or even enhance the dynamic reactive power
and inertia services, e.g., through conversion of the
generator to a synchronous condenser. There is also
the possibility of using part of the site to install RE
generation (e.g., solar PVs) and battery storage. The
World Bank is currently developing an accelerate coal
transition facility to develop these ideas and finance
these projects initially in India and South Africa.
✔✔ The average solar and wind contract prices have fallen
below US$0.044 per kWh (₹3/kWh) since late 2019,
making them lower than the operating cost of many of
the existing coal plants. Our analysis of 15-min wholesale spot prices in the DAM over the past five years
suggests that solar and wind would have been competitive in the market. It would make sense to bring solar
and wind-at least part of the new VRE projects-to
bidding in the market to enhance liquidity. It would
also be important to develop a market-based mecha82

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nism (e.g., contract for differences) to bring some of
the thermal capacity currently on long-term PPA into
the market. These issues are being actively discussed
by the Ministry of Power in India as part of a road map
to redesign the future electricity market. India needs a
minimum of US$10 billion of new investment in solar
and wind annually over the next decade to meet its
renewable policy targets by 2030. Active market participation in a liquid DAM and real-time market that
started on 3 June 2020 is expected to facilitate such
investments to be led by the market mechanism.
✔✔ An ancillary services market, co-optimized with the
energy market, is also recognized as a critical component to ensure new-storage hydro, pumped-storage
hydro, open-cycle gas turbine, and battery storage can
all be developed in a market-oriented way. A World
Bank analysis of historic DAM prices suggests that a
combination of ancillary services payments at US$2/
MWh and arbitrage in the DAM would render a battery electric storage system moderately attractive, and
at US$4/MWh, it would be a reasonably strong business case.
✔✔ Finally, the regional dimension of the market is also
critically important, as India can catalyze faster development of hydro in Nepal (with an economic potential
of 42 GW) and Bhutan (25 GW) than it can import to
support solar/wind. In turn, India can also export power
to countries like Bangladesh and Sri Lanka that have
limited primary energy supplies. Given the complexity
of developing large-scale hydro in India, regional hydro
projects can be a potent option. One of our analyses indicates that every gigawatt of hydro, even with limited
storage, can support the variability of at least 4 GW of
solar and wind in India through the provision of spinning reserve. We also find that a combination of crossborder hydro, complemented by battery storage for additional frequency-control ancillary services, can be an
important part of the decarbonization strategy in the region. Developing additional cross-border transmission
infrastructure rapidly would be a core part of this strategy, and this will require up to US$2 billion in the short
to medium term until 2030, followed by additional investments to form a deeply integrated ac network. There
is a thriving economic case for these projects supported
by multiple studies conducted by the World Bank, U.S.
Agency for International Development, and the Asian
Development Bank.
january/february 2021

IEEE Power & Energy Magazine - January/February 2021

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