1. ExpertSpeak
21
February 2016
www.InfralinePlus.com
CEA’s 18th EPS forecast of 3,500 TWh
by 2030. The INDC is not clear on
whether the proposed 40% target for
non-fossil fuel is based on generation
or capacity. For the purpose of this
analysis, we assume a 40% non-fossil
fuel based generation mix is the target
by 2030.
Nuclear and Hydro generation
additions: INDC does not specify
explicit targets for setting up nuclear
and large hydro (storage or run-of–
river or pump storage) generation.
However, it specifies overall potential
for these two generation sources. Given
the long gestation period associated
with nuclear and large hydro capacity,
we assume that India will continue to
add this capacity at a rate similar to
that seen in the recent past. While total
hydro capacity has been capped at 70
GW, nuclear capacity has been capped
at 30 GW.
Load profile: Over the years,
India’s national average load factor
has increased from ~75% in FY11
to ~85% (less peaky) in FY15; this
change is primarily due to changes in
supply availability. We have assumed
that a similar load profile will continue
in the future.
Wind resource: Wind resource
(state wise) potential as indicated by
NIWE at 100 mt hub height and annual
average capacity factor of 22% to 24%
depending on state. Historical wind
generation profiles of respective states
have been used for future forecast.
Solar resource: Solar resource
(state wise) potential of 400 GW has
India has re-iterated its commitment
to install 175 GW of renewables by
2022 in its Intended Nationally Deter-
mined Contribution (INDC) document
released recently. Additionally, India’s
INDC outlines a vision of reduction
of 33%-35% in emission intensity of
India’s GDP by 2030 from 2005 levels
and achieving 40% of generation based
on non-fossil fuels (i.e. Large Hydro,
Nuclear, Small-Hydro, Wind, Solar PV/
TH and Biomass) by 2030. The INDC
document forecasts average annual
electricity demand growth of 6.7% be-
tween 2012 and 2030 and also outlines
various means of reducing electricity
intensity of GDP. These ambitious ob-
jectives are bound to have wide ranging
ramifications for the power system and
across the spectrum of stakeholders.
INDC targets and related
assumptions
Since the specific details of how these
targets will be met are not very clear
right now, our analysis employs some
assumptions to complete the picture.
Electricity demand ~20% lower
than 18th EPS forecast: In 2014,
with per capita consumption of around
900 kWh/person, India’s electricity
consumption stood at 1,060 TWh.
Assuming YoY growths of 6.7% (2014
to 2030), India’s electricity demand is
expected to reach about 3,000 TWh
by 2030 which is ~20% lower than
Gurpreet Chugh, Consulting
Director and Ashish Singla,
Senior Consultant, ICF
International, analyses the
INDCs submitted by India
recently and its implications for
the power sector.
Coal will continue to dominate
power generation at 60% by 2030
Gurpreet Chugh, Consulting Director,
ICF International
Ashish Singla, Senior Consultant,
ICF International
If the government can
support or lower the
capital investment
required in setting up
RE-based capacity
(either by funding
directly through VGF
or by introducing
innovative market
designs), the overall
system cost can be
significantly lower.

2. 22
ExpertSpeak
February 2016
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Modelling Results and
Analysis
While non-fossil capacity share goes
up to 60%, coal still dominates genera-
tion at 60% by 2030
Currently, India is a 270 GW
system, of which 70% capacity is
based on fossil fuels (coal and gas),
hydro and nuclear provide 16%, and
RE provides the remaining 14%. In
order to optimally meet its electricity
demand of 3,000 TWh, the model pre-
dicts that India will become a system
of 844 GW by 2030; the contribution
of fossil fuel based capacity will
reduce to 40% (Figure 1) and renew-
ables will rise to 48%.
Coal will continue to be the dom-
inant source of electricity, although its
contribution to the overall generation
mix will reduce from 76% in 2015 to
60% by 2030 (Figure 2).
Coal based plants bear the brunt – slow
capacity addition, declining capacity
utilization factors (CUFs) and declin-
ing merchant prices
The increased generation by renew-
ables will lead to a reduction in power
sector emissions per unit of GDP by
38% (from 2005 levels). This is in-line
with the cumulative emission reduction
targets mentioned in the INDC. Addi-
tionally, power sector CO2
emissions
per unit of generation will also decline
by 29% in 2030 with respect to 2005
levels. Figure 3 shows total power
sector CO2
emissions (in million tons)
and CO2
emissions by per unit of GDP
(in gram/INR).
With the aggressive addition of
non-fossil fuel based capacity, India
will need to add much less coal based
capacity, about 9 GW per annum
between 2020 and 2030. This is sig-
nificantly lower than the recent track
record of adding 15 GW of coal-based
capacity addition per annum (Figure 4).
Under the INDC scenario, con-
sumption of imported coal is expected
to reduce significantly compared to
the business-as-usual (BAU) scenario.
In fact, it is expected that India could
been assumed by 2030 and average
capacity factor of 19% to 21%
depending on radiation levels of a
state. Historical generation profile
of states has been used for future
projections.
Approach and Methodology
To quantitatively assess the impact
on the power system, ICF’s propri-
etary tool Integrated Planning Model®
(IPM®
) has been used. IPM®
uses a
linear programming-based optimiza-
Figure 1: Capacity Mix (All-India)
Figure 2: Generation mix (All-India)
Figure 3: Emissions from Power Sector
tion approach that simulates least-
cost plant dispatching and least-cost
investments in generation capacity
and interconnections to meet pro-
jected load in a power system. The
results and the analysis have been
derived from the output of IPM®
by
simulating the INDC scenario of 40%
generation coming from non-fossil
fuel by 2030.

3. 23
February 2016
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The overall value of coal based plants
is expected to decrease primarily
driven by reduced capacity factors and
reduced market prices. While capacity
factors of coal based plants would be
produce a surplus in domestic coal
supply by 2030 (figure 5). In fact, if Coal
India achieves its target of 1 billion ton
of coal production by 2022, India might
produce a coal surplus as early as 2022.
to be in the range of 80% to 85%.
However, capacity utilization of inef-
ficient coal-based plants is expected to
be less than 40%.
More gas-based and hydro
capacity will be needed to manage
variability of renewable energy
With integration of significant
solar and wind capacity into the
system by 2030, the Indian grid will
likely need to add 20 GW of storage
based hydro and 25 GW of gas-based
capacity to manage net variability
of system’s demand and supply.
However, if the system’s load factors
were to change from current levels
of 85% to 75%, and demand were
to become peakier, the balancing
capacity requirement will increase
significantly (Figure 6).
However, this gas-based capacity is
likely to have a much lower PLF and
is likely to operate only during peak
times. Overall gas-based generation
is likely to reduce from 44 BUs in
2015 to 31 BUs in 2030. This clearly
requires a suitable policy to enable gas-
based plants to be set up and used as
peakers (open cycle mode). This also
calls for setting up ancillary service
market which might promote open
cycle gas based (or hydro pump storage
or storage based hydro) power plants
which are compensated for providing
such flexibility to the system
With aggressive renewable capacity
addition, system becomes expensive
India is expected to add 400 GW
of RE based capacity by 2030. Due
to high capital costs, these RE-based
capacities have traditionally relied on
government subsidies in one form or
another. Going forward, reliance on
subsidy schemes (such as FiT, VGF,
accelerated depreciation, Renewable
Purchase Obligation, RECs, etc.) is
expected to continue. Wind and solar
may remain expensive options when
compared to coal-based generation
and, depending on economics, policies
to stimulate RE capacity addition may
need to be sustained.
Figure 4: Year-on-Year Coal Capacity Addition (in GW)
Figure 5: Imported Coal Consumption and Domestic Supply
(for Power Sector)
Figure 6: Gas and Hydro Capacity (All-India Total)
under stress primarily due to increased
RE based generation (which will have
must-run status or self-dispatch),
market prices are expected to decrease.
Moreover, the marginal unit of genera-
tion for the entire system will change
from imported coal to domestic coal.
In the medium to long-term, capacity
utilization of efficient (primarily super-
critical) coal-based plants is expected

4. 24
February 2016
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ExpertSpeak
Based on the INDC targets, the
power system will become more
expensive by INR 2,60,000 crores
(as compared to the BAU case). The
increase in system cost would pri-
marily be driven by addition of RE
sources which have higher capital cost
than conventional generating capacity
and higher O&M costs. Although
there would be some savings due to
reduction in fuel costs (i.e., reduction
in coal and gas consumption) and lower
costs of inter-state transmission system,
the increase in capital cost more than
offsets the benefit achieved (Figure 7).
This also means that if the gov-
ernment can support or lower the
capital investment required in setting
up RE-based capacity (either by
funding directly through VGF or by
introducing innovative market designs),
the overall system cost can be signifi-
cantly lower.
Implications for stakeholders
These significant changes will create
opportunities and threats for various
stakeholders. These stakeholders thus
need to understand these implications
and try to realign their strategy to this
new regime, considering many questions:
▪▪ Central planning agencies:
-- How can the demand forecast be
made more systematic?
-- What is more optimal for the
system to add, solar or wind?
-- What are the grid integration/
balancing requirements for systems
where RE additions are primarily
solar versus wind?
-- What policies will best enable use
of existing gas-based capacity in
peaking mode and enable new
plants to be set up in open cycle
mode?
-- In case, India is able to add
significant amount of hydro and
nuclear capacity, how much
Figure 7: Change in Total system Cost (BAU to INDC case) ▪▪ Coal-based capacity
-- How will coal-based assets be
impacted – especially those based
on imported coal and those that
are less efficient?
-- How will closer lender scrutiny of
proposed coal-based capacities,
affect current capacities, the
dispatch levels, and additions?
-- How will EPC majors respond
to slow coal-based capacity
addition?
-- How much coal will we need and
what do we do with the surplus?
▪▪ Gas-based capacity
-- Can the system incentivize gas-
based capacity to operate at very
low utilization to balance the
grid?
-- How will current gas-based
capacity operate?
-- What can change the load factor
significantly, and what impact
will these changes have on gas
demand for power generation?
-- How much capacity is required
for balanced integration of RE
sources and how would it change with
increasing load factors of system,
and for different RE generation
mixes (wind-dominated versus solar–
dominated)?
▪▪ Transmission
-- Which transmission corridors
should be strengthened, and by
how much?
-- How would power flow change
under an RE-dominated scenario
versus the current coal-dominated
scenario?
India’s INDCs represent a sig-
nificant departure from the BAU sce-
nario. Even if these ambitious goals
were not to be fully achieved, the
INDCs have the potential to dramati-
cally shift the India power sector, and
all stakeholders – investors, devel-
opers, EPC players, lenders – need to
review their outlook on the sector and
realign their strategies.
Based on the INDC tar-
gets, the power system
will become more ex-
pensive by INR 2,60,000
crores. The increase in
system cost would pri-
marily be driven by addi-
tion of RE sources which
have higher capital
cost than conventional
generating capacity
and higher OM costs.
Although there would be
some savings due to re-
duction in fuel costs and
lower costs of inter-state
transmission system,
the increase in capital
cost more than offsets
the benefit achieved
The views in the article of the author are personal
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