Honourable Central Electricity Regulatory Commission
CERCs‟ Discussion Paper on Terms and Condition of Tariff
November 12, 2003
• Backdrop for Tariff Fixation
• Goals for Tariff Setting
• Part I: Broader Issues of Tariff Setting
• Part II: Views/Recommendations on Specific Issues
Backdrop for Tariff Setting
Capacity Addition Required and past performance
• Huge capacity Addition Required to realize the vision of power for all by 2012: 100,000 MW
• Estimated investment in all sectors: Rs. 900,000 Crs
30000 70% Achievement
7th Plan 8th Plan 9th Plan
• The Achievement % in 9th Plan is lowest for all plans
• The need based targets for 8th and 9th Plan were 44,000 MW and 57,735 MW respectively. The
Planning Commission reduced the target considering feasibility/resources constraints etc.
• The Xth Plan target for utilities is fixed at 41,110 MW.
• Considering the status of various projects identified for commissioning in this period, it is unlikely
that this target would be achieved, even to a reasonable extent
• Accordingly, the shortages are likely to increase substantially
Structure Before Electricity Act- 03 (Post Reforms)
GENERA- TRANS- DISTRI- CONSUMER
Bulk Power Purchase for Licensees)
TION MISSION BUTION
TRANSCOs (eg. Delhi Transco)
Discom 1 Licence
TRANSCO (Licensee 1) Area 1
Discom 2 Licence
PGCIL (Licensee 2) Area 2
Captive Pvt. Discom n Licence
Utilities (Licensee n) Area n
? Regulator‟s Role
No Choice to Generating Co./Consumer, Limited Competition
Changing Structure: Emerging Structure: Post EA 03
Generating Own Captive Generation
Companies Generation Facilities
Transmission Network (Immediate Open Access)
Licensee 1 Licensee 2
Distribution Network (Gradual Open Access)
Own Distribution System
Power Traders would
also be involved in some
of the transactions
Competitive, Flexible Structure enabling Choice to Consumer
Goals for Tariff Setting
Goals of Tariff Setting
• Huge investment required (Rs. 900,000 Crs) to realize the vision of
„Power for All by 2012‟
• Investment in Power Sector to compete for investment in other
sectors in terms of
– Returns offered
– Climate for investment: Stable policies, regulatory and fiscal framework
• The policy of allowing an attractive return profile may be adopted
for say the next 9-12 years and when the critical mass of
investments which can meet the 2012 vision is achieved, Govt.
may review it
– This has happened in this country as well as abroad whenever Govts
want to attract investments in certain sector.
• Thus tariff-setting principles need to distinguish between two
stages - Stage I is the immediate period for the next 9 – 12 years
when large investments would be required to meet the capacity
requirements of the sector and Stage II would be the period
Goals of Tariff Setting (contd.)
• The need for attracting investments in Stage I is more acute
compared to Stage II and at the same time more difficult
– State of the sector today, from investment point of view, is less
favourable due to the various ills affecting the sector.
– Conditions likely to improve in the next 9 – 12 years as reforms are
accomplished and critical mass is achieved
• Case for more favourable returns in Stage I to attract investments.
– Normalized returns in Stage II
• Even in Stage I, a staggered approach to returns should be
followed i.e., keeping in view the immediate need of funds, a
higher return should be allowed for the next say 5 year period. The
returns may then decrease in subsequent 5 year period and further
Goals of Tariff Setting (contd.)
• Stable tariff policy framework in various stages and in
inter-stages intervals, keeping in account large gestation
period of power projects
– Clearances have a long lead time (for ex. MoEF clearance itself
requires anywhere from 18 – 24 months).
• Apart from ensuring the basic function of adequate cost
recovery, it should ensure that there is enough revenue
generation in the sector itself to partly meet the funds
• Ultimately, tariff setting should aim at helping the sector in
its journey of reforms & restructuring and should facilitate
the emergence of a financially strong, vibrant, competitive
and investor & consumer friendly sector.
Tariff Setting: Broader Issue
Tariff Setting: Broader Issues
• Existing Practice: Cost plus System
– Discourages efficiencies
– Micro Management
• Detailed scrutiny of technology
• Technology/Equipment selection vetting
– Many time even capacities of sub-systems are analyzed
• Highly time consuming, taking lot of Commission's time and resources
– Not tuned to changing/dynamic structure
• Enhanced participation of private sector players
• Faster approvals (tariff etc.)
Pressing Need to move away from ‘Cost plus System’
Tariff Setting Across the Chain: Transition
Existing: All independently determined
Generation Transmission Distribution
Regulated Regulate Regulated
on Cost d on Cost on Cost
Plus basis Plus basis Plus basis
Input Power Cost
is taken as „given
Generation Transmission Distribution
ted, due Regulated
to on Price
on Managing Input
Power Cost is left
1. Existing Structure: Takes Time, lacks drivers to improve efficiencies
2. Desired Structure would ‘take time’ to evolve
Need for interim Structure to cut down the time and promote efficiencies
Tariff Setting: Interim Structure (Generation)
Regulated on Regulated on
Cost Plus Normative
Steps Involved Steps Involved (one time
(in each case) activity)
1. Cost Scrutiny/approval 1. Determination of
2. Financing Plan Normative Cost
scrutiny/approval 2. Arriving at Normative
3. Scrutiny of interest rates Financing Plan
3. Fixing Normative O&M
4. Arriving at Normative
Take time and Leads to Faster approval process,
separate tariff for similar uniform tariff for similar
type of projects projects
Interim Structure to realize the Vision and promote efficiency
Views/Recommendations on Specific Issues
1. Rate of Return: Approach
– Tariff setting needs to move from a cost-plus approach to a
normative performance based approach.
• Cost-Plus approach requires detailed analysis of the different loans,
their repayment schedules and other terms & conditions.
• It does not provide incentive to utility to lower cost of borrowings as
even higher rates are passed through in tariff.
– Adoption of a Return on Capital Employed (ROCE) approach
would incentivise utilities to adopt more efficient means of
financing so as to reduce its cost.
• The ROCE may be calculated each year with normative cost of
equity, debt and the debt-equity ratio.
ROCE Approach to be Adopted
2. Rate of Return: ROCE- Cost of Debt
– The interest rate may be taken as lending rates for “A” rated borrower
(minimum investment grade rating below which Banks/FIs generally do
– This may work out to a spread of 3% to 3.5% over the base PLR, which
for simplicity, may be taken as SBI‟s Long Term PLR for Infrastructure
• A provision also need to be made for factoring in other costs of raising debt-
finance viz. upfront fees, etc.
– Generally, lenders stipulate a call option in the loans which entitles them
to review the rates of interest at regular period of time after
disbursement of the loan (say every 5 years). No corresponding put
option to the borrower.
– If interest rates in the economy go up, lenders may require
enhancement of the interest rate applicable to the loan also.
• It would pose significant interest rate risk for the borrower which no borrower
is in a position to take.
– Accordingly, there should be a provision for a mid-term review of tariff
should the interest rates in the economy rise by say more than 3%.
SBI PLR + 3.5% (on pre-tax basis), with provision for Mid-Term
Review to be Adopted
3. Rate of Return: ROCE- Cost of Equity
– Pressing need to attract investments in the sector and generate internal
resources for huge capacity additions
– Returns, adjusted for Risk profile, to be attractive vis-à-vis competitive
sectors for investments of the desired amount to flow in.
– The returns available to the investors should therefore be the
opportunity cost of funds to the investor and not linked to interest rates
in the economy.
– Against competing investment avenues, a cost of equity lesser than 16%
would be definitely unattractive.
– In developed economies where there is no acute investment program,
returns are linked to interest rates.
– Taking 16% as the base minimum ROE required, CAPM model may be
used to see if a higher equity return is justifiable.
– The higher of ROE derived through the CAPM model and 16% should be
used as the cost of equity.
ROE of 16% (post-tax) to be continued … at least for Xth
and XIth Plan Period
4. ROCE- Debt: Equity Ratio
– The generally followed a debt-equity norm of 70:30 in the past needs to
be relooked in view of changing structure.
• From long-term assured off-take arrangements and elaborate payment security
structures to liberalized & competitive market place
• Less possibility of payment security structures and even if it is, experience of
IPPs under operation shows how ineffective they are in actual practice.
– This would have the effect of slightly raising the risk profile of the
investments. Additionally, the amount of investments required in the
sector in the next 8-9 years also has to be seen.
– Considering the above, lenders may not be willing to lend at the same
70:30 debt-equity ratio and may insist on a better debt-equity ratio.
– Moreover, credit profile of the borrower would also determine the debt-
equity ratio being offered to him. For a majority of SEBs with poor
financial health and a track-record of defaults on debt obligations,
lenders may definitely like to insist on better equity cushion.
• Having determined these norms and approved tariff based on these norms,
Commission should not look into what is the actual debt-equity ratio or the cost
of borrowings for the company and the same should be left to the investors.
For Calculation of ROCE, Debt:Equity Ratio of 50:50 to be adopted
5. ROCE to be fixed or dynamic and fixed every year?
– The investment decision is taken based on principles of ROCE
allowed at the approval stage
– Changing principles of ROCE every year would lead to
regulatory etc. uncertainties, which needs to be avoided
– If principles of ROCE norms is required to be changed, the
revised norm should not be made applicable for fully
developed/under construction or operation projects.
– In competitively bid project, the tariff offered by the bidder
remains the same through the project life irrespective of
change in tariff norms thereafter
It principles should be fixed for project life
6. Tax: ROE to be Pre or Post Tax or increase ROE by 0.5%
to avoid pass through of Income Tax?
– In order to attract investment in the sector etc. 16% ROE to be
on Post Tax Basis.
– However, to avoid regular/yearly scrutiny, ROE can be
specified on pre tax basis by suitably grossing it by effective
tax rate over the project life
• Effective Tax rate to be computed by considering Section 80 IA
benefit and MAT rate and initial depreciation shield.
• At current tax laws, the effective tax rate for a coal based power
plant with a life of 25 years is 21.13% and that for a gas based
station is 16.41%.
– The ROCE would thus need to be enhanced by the above
effective tax rates to make it on a pre-tax basis.
• To be adjusted for change in law/rate rates
ROE to be Post Tax or to make it pre-tax, suitably grossed
up to effective tax rate
7. Whether Additional Capitalization to be allowed?
– Capital costs for stations various type of power plants should
be based on laid down norms i.e, a fixed amount for various
type of projects and considering the size of plant, economies of
scale, etc. Thus for a gas based project, a normative cost of Rs.
3 crores/MW may be approved whereas for a coal based
station, Rs. 4 crores per MW may be stipulated as the norm for
– Once these norms are set, all cost components in tariff should
be calculated w.r.t. these norms and there should be no linkage
with the actual capital cost of the plant.
– All cost over-runs/savings w.r.t. this normative cost should be
to the account of the developer
Provision for mid-term review, if during construction stage, there is
significant variation in tax laws impacting project cost
8. Rate Base to be from assets side or liability side?
– The calculation of rate base should ensure that the tariff allows
a return component which covers both ROE as well as interest
cost of debt.
– There are various options for calculating the rate base from the
asset side & liability side.
– The most prudent option would be one which allows flexibility
to the developer, adequately covers his returns & interest cost
of debt and at the same time does not lead to a sharp increase
in retail tariffs.
– As suggested earlier, Normative Approach should be adopted in
this case also.
– The rate base, should take into account its reduction due to
repayment of loan etc.
1. Initial Rate Base Should be Normative Capital Cost
2. This may be decreased by 5% p.a., up to 50% of
original, in view of debt-equity ratio of 50:50
9. Basis of Capital Cost: Normative or Actual
– Taking actual cost as on COD would lead to different tariffs for
– Further, it would increase the steps required to fix the tariffs
1. It should be on normative basis (due consideration to
type of project, technology, economies of scale etc.)
2. There should be provision for mid-term review to account
for any change in law/tax rates
10. Treatment of Initial Spares in Project Cost
– In the existing tariff-setting methodology, initial spares are
included as a part of the project cost.
– Further, there is a linkage between initial spares and
calculation of maintenance spares for working capital
1. Existing practice of including cost of initial spares in
project cost to be continued. Normative project cost to
be suitably adjusted for initial spares
2. There should not be any linkage between initial spares
and calculation of maintenance spares
11. Foreign Exchange Variation
– In a normative based tariff setting methodology, actual mode
and mix of financing would not be of any issue
• Developer to optimize the financing package
In view of suggestion for normative parameters for tariff
fixation and return on ROCE, this issue does not arise
12. Working Capital Issues
– Existing norms are based on prudent principles and well
– Giving Interest on Working Capital along with ROCE would lead
to its under recovery due to reduction in capital base over the
– Interest rate needs to be uniform (charged to “A” rated
1. Existing Norms to be retained
2. Interest on Work. Cap to be separate component of tariff
3. Interest Rate to be SBI PLR + 3%
13. O&M Expenses (Normative/Actual? & escalation)
– O&M cost should be on a normative basis as a given percentage
of the normative project cost.
– Linking O&M expenses to actual project cost/expenses leads to
wide variation for similar type of projects.
– The actual O&M expenses (including Insurance) are found be
more than allowed in existing norms, particularly for gas
– As regards year-on-year escalation factor, a suitable weighted
average of WPI and CPI may be used (say 60% WPI and 40%
O&M expenses (first year) allowed should be 4.25% for Gas
Stations and 3% for Coal Stations of Normative Project Cost
14. Depreciation Rate
– Depreciation does not serve the purpose of loan repayment
only. It also serves to generate additional resources which can
be used for future creation of capacity.
– Realizing this, Govt. of India had also increased rates of
depreciation in March, 1994.
– However, in a normative ROCE model, linking of depreciation
rates to loan repayment exactly may not also be possible as
there is no concept of actual equity or debt separation in the
Retain Depreciation Rates as notified by MOP in 1994 (7.84% for
coal & 8.24% for gas stations, at least for X th and XIth Plan period
15. Depreciation – Other Issues
– The calculation of depreciation amount every year should be
done on the basis of historic normative project cost (Not on
– Further, sector needs huge investment for capacity addition.
– Internal resource is key source of investment financing
Depreciation to be calculated on normative cost and should
generate some surplus (over loan repayment) for further
16. Operational Norms for Thermal Stations
– The fixation of operational norms (station heat rate, secondary
fuel consumption and auxiliary consumption) should take into
account the relative performance of a wide cross-section of
utilities in the country from both central & state sector as well
as the private sector so that the norms are achievable by all
utilities which put in reasonably efficient efforts.
– The norms so fixed should also act as reasonable benchmarks
for utilities to improve whose performance is below the norms.
– The existing practice of comparing norms against actuals and
allowing the lower of the two discourages efficiency
– During stabilization period, norms should be relaxed.
Norms to be based on performance of wide-section of
utilities and tariff to be based on normative parameters only
17. Norms for Target Availability
– The norms should take into account the relative performance of a wide
cross-section of utilities.
– The average operating PLF/availability for all generating stations put
together in the country stands at about 72%, against stipulated norm of
• Wide-gap between the norms and the actual ground level performance
– The norms for target availability should thus be fixed at the national
average plus say 2%-3%.
– Alternatively, if the threshold availability level is being raised to 80%,
then the ROE should also be enhanced from 16% suitably to reflect the
higher risk carried by the project company.
Target Availability should be 75% for recovery of fixed
charges including ROE @ 16%
18. Incentive (Linked to availability or PLF? )
– PLF depends on despatch of the plant, which is dictated by
customer beneficiaries and not the developer
– Maintaining high availability is important for grid stability and
should be rewarded
– Further, linking of incentives to PLF has a number of other
• „Non-merit‟ operation of grid
Incentive should be linked to Availability
19. Development Surcharge
– Development Surcharge was allowed in tariff to central sector utilities as
a means of gathering surplus funds for future capacity additions.
– In a competitive market place, there is no reason why Govt. owned
utilities should derive an advantage of securing cashflows for future
investments by way of statutory levies/surcharge.
– If the Govt. so desires, the funds required for setting up new capacity
should be given by way of planned budgetary allocations rather than
collect the same by way of a surcharge.
– The surplus funds for future capacity addition can be generated through
a higher rate of depreciation etc. which would then be uniformly
available to all utilities and not to central sector utilities only.
Development Surcharge should not be specific to fund
investment program of Central Generating Stations
Transition Period Support – Need for Cess/Surcharge
• Distribution Sector: Transition Phase – Need for Support
– Low retail tariff elasticity
– Need to keep retail tariffs affordable for all consumer categories
– This may be ensured by
• Reducing losses
• Tariff rationalization
• Operational/organizational efficiency improvement
– However, these measures would take time
– During this period sustainability of the utility to be ensured
– Therefore support required to bridge the gap – Actual tariff minus
• Most State Govts do not have resources to bridge this gap – major
constraint to distribution privatization & reforms
• CERC requested to recommend to Central Govt. to levy a cess on all
power sold in the country to meet transitional period support
• Surcharge Collection to be administered by the Excise Machinery.
Transition Phase – Need for Support (contd.)
Revenue Gap – Govt. Support
Without reforms – perpetual
drain on Govt. resources
Reforms to release Govt. funds for priority sectors
20. Tariff Norms Review Period
– Tariff policy framework should be stable enough for a reasonable period
• keeping in view the development period of projects
– However, periodic review is necessary
• Changes in cost levels in economy, technology, equipment prices
– Revised norms to be applicable for new projects only
• For fully developed/set-up projects, tariff principles once set, should continue
for the entire life of the plant.
– The investment decision and financing is based on prevalent norms
– The apprehension of customers that escalation component (viz. O&M
cost) may become very high compared to actuals can be taken care of
better by suitably determining the escalation factor with weights linked
to various indices of costs in the economy.
Tariff norms may be reviewed once in 5 years, to be applicable for
new projects only. No change for fully developed/operating projects
21. Regional Tariff (i.e. Pooled Tariff for CPSU)
– The need for pooled generation tariffs is not clear.
– Generation tariffs should be on station-wise basis and not
– Pooled tariff concept is generally applicable for distribution
utilities when they procure bulk power and not for generation
– The pooled tariff concept for generating companies can work
specifically in a short-term/spot sales scenario.
– In case of long-term contracts, it would become very difficult
to implement a provision whereby tariff gets upwardly revised
every time a new incremental capacity is set up.
Tariffs should be stationwise
22. Peak/Off Peak Tariff in Bulk Generation
• Views (whether should be introduced?)
– The concept is in the right direction.
• Compels distribution companies to manage load curves in a more
• Ensures higher availability of generating capacity during peak hours
• reduce congestion on transmission lines to some extent
– However for it to be really effective, differential tariffs based on
time of day etc. should also be implemented at the downstream
level i.e., transmission & distribution business.
– If this is not the case, the distribution licensee/supplier would
end up getting squeezed by the higher peak bulk tariff rates
which he would not be able to pass to the retail consumers.
– There should be a clear road-map for appropriate TOD
metering/retail tariff fixing, etc.
Differential Tariffs should be introduced
23. Declared Capacity & Auxiliary Consumption
• Views/Basis for Recommendation
– Existing definitions are well accepted and understood in the
No need to change the definitions
Goals for Tariff Setting: Other Issues
Need for Intra State ABT
• Currently applicable only to Central sector generators and
beneficiaries who are directly connected to and are a player on the
regional grids (Inter State only).
– The advantages not being completely utilized by the entire power sector
• On the intra-state level, a significant surplus capacity exists with
various generating companies & CPPs which at present is not
being optimally utilized.
• Moreover, a number of state generating stations still have single
part tariff, which is not in line with merit order regime. Such
generating stations would be asked to back down even though on
a variable-cost based merit order system they would have been
• It is also necessary that the distribution utilities become more
accountable in their load management processes by assessing
consumer demand more accurately and planning their load
shedding schedules judiciously.
Need for Intra State ABT
• Unbundling of SEBs would increase no. of players managing
the load in the system.
• Unless a mechanism is put into place at the intra-state
level to cover these distribution companies also under ABT,
the loop would not be closed and the actual
implementation of ABT would not be complete.
• Thus, implementation of ABT at the intra-state level would
free up idle generating capacity leading to meeting of more
consumer demand, ensure better load management by the
distribution companies, boost bilateral trading, etc.
• ABT with a self contained discipline mechanism would
enable better and reliable grid operations
Advantages of Intra State ABT
• The experience of implementing ABT in the country till date has
shows following major advantages:
– The UI charge in ABT results in better grid discipline and grid security by
limiting grid frequency excursions within a manageable range.
– Improvement in grid voltage levels leading to reduction in transmission
losses and enhancement of transmission capacity.
– Maximization of generation during peak-hours and backing down of
generation during off-peak hours as per merit order. ABT facilitates
Merit Order Dispatch as the fixed cost payable based on capacity
allocated becomes a sunk cost and dispatch of plants is based on
– The two-part tariff concept of ABT presents an inherent platform for
– Improvement in performance of power plants by reducing trippings and
long term damage.
– Improvement in commercial dealings with reduction in year-end adhoc
adjustments and consequent disputes.
Summary: Tariff Setting Goals
• Tariff setting to take into account changing structure of
• It should lead to faster approval process
– Normative cost etc. approach
• It should promote efficiencies