CERC – Re-designing of Real Time Electricity Market in India
The existing DSM mechanism and AS
(RRAS) are frequency-dependent imbalance handling tools, not to be used as markets. The design of RTM as a balancing market must
ensure participation and reduce dependence on AS (RRAS) and DSM for real time energy needs.
A time gap of 10 minutes is required between
gate closure and opening of bid (auction) for
Distribution utilities should be allowed to
provide demand side ‘up regulation’ and
‘down regulation’ bids to enhance the overall
DSM price vector, currently linked with
prices in DSM, could be linked to the prices discovered in RTM, at a later stage, for reflecting the true cost of deviation.
For participating in RTM, RE generators would have to be well equipped with more reliable generation forecast.
The RTM would require real time exchange of information on congestion, injection/drawl schedules, cleared price, cleared volumes, etc., between power exchange(s), system operators and market participants.Availability of adequate infrastructure in such regards must be ensured in advance.
With the introduction of RTMs, better market
monitoring would be required to avoid the abuse of market power.
CERC – Re-designing of Ancillary Services Mechanism in India
Efficiently designed ancillary services market along with proposed real-time market should ultimately render DSM operation irrelevant.
At the end of the debarment period, an evaluation process should be put in place to strengthen compliance framework for debarred participants to regain entry in the Ancillary Services market. Failure in qualifying the evaluation should lead to extension in the debarment period.
Based on relative technical capability, inter-/intra-state plants/facilities participating in ancillary services market should be classified into Ramp Resources, Ramp Limited Resources and Energy Limited Resources.
MBED of Electricity: Re-Designing of DAM in India – A CERC Discussion Paper.
Expected savings from optimisation over a larger portfolio of procurement contracts need to be weighed against costs associated with the implementation of MBED.
Relevant sections of Electricity Act, 2003 may need to be amended to facilitate the creation of MBED.
The proposed price risk hedging mechanism in BCS is asymmetric – allowing DISCOMs to hedge risk when MCP is greater than the price in the PPA(s), while exposing GENCOs to financial risks if MCP is less than PPA(s) price.
Some generating units may need frequent shut downs, especially in the absence of incentives to generate up to their technical minimum limit, when the system forces low demand or high renewable penetration, thereby affecting the overall market outcome.
The legal implications of termination of PPA(s) may be significant, given the high financial stakes for investors and lenders.
A holistic market design should give due consideration to all segments of capacity market, DAM/TAM, Deviation Settlement Mechanism (DSM), RTM, AS, etc. A capacity market to be developed alongside MBED would help ensure long-term resource adequacy.
The implementation of MBED may witness high fixed costs by GENCOs, with lower variable costs for getting scheduled in DAM. Consequently, technologies like solar photovoltaics (SPV), especially with storage, would be the most viable option.
Proposed Bid (Order) Types in DAM – IEX's petition to CERC
The whole bid system is more favourable to the seller side.
The constant quoted price of MQB and PB would be compared with average and weighted average MCP respectively of the block for selection. This may lead to paradoxical rejection in individual time block(s) of the profile.
Bid types such as PB and FB are specifically designed for renewable power plants, but the planttechnology type of bidder, placing such bids may not be known to the market operator. Also, an optimal solution may not be possible if unintended plants use such bids for their own financial benefit.
Minimum quantity bids and MIC bids are contradictory in nature. The former places a lower bound whereas the latter an upper bound on the selection criterion.
Similar products should be combined for a less complex system to ease the process of market clearing and settlement.
CERC – Pilot on SCED of Inter-State Generating Stations PAN India
Savings on account of SCED implementation, for which methodology is yet to be specified by CERC, should only be apportioned to the respective beneficiaries. Generators, who are otherwise compensated for all the associated cost, should not be a party to such savings.
The variable cost quoted by the ISGS for RRAS is vetted by neither CERC nor POSOCO. Moreover, it is not specified if this variable cost should be based on the previous month's billing or the current month's expected billing, or on the basis of the cost of recent delivery of fuel (in case of coal-based thermal station).
The asymmetry of variable cost used by state utilities and that quoted by ISGS plants (and used for SCED) would lead to over-/under-estimation of benefits.
Procedure for Pilot on SCED for ISGS PAN India
The SCED being implemented is based on variable cost at the generator bus bar, where states consider the landed cost of such power, including transmission charges and transmission losses, while determining the MoD. Hence, the results provided by SCED may be suboptimal for a state sometimes.
In the absence of UC, all the units on bar would be allowed to run up to technical minimum along with heat rate compensation, thus imposing a higher overall cost on the system and ultimately the final consumers, whereas SLDCs can opt for shutdown of a unit as well.
In future, SCED should also consider unit commitment taking into account the strategy of shutting down of a unit, particularly under low-demand conditions.
The concept of retrospective changes in the SCED schedule, in the context of infeasible/nonconvergent solution, may expose the constituent to ‘Unscheduled' DSM penalty/incentives as its treatment is not specified.
The inclusion of URS in SCED optimisation may leave no economics in it.
The objective function used for SCED (as given in the document) is based on an individual block basis and does not consider optimisation feasible across time blocks where ramping constraints would influence the solution.
There is no provision for passing the baton; provisions for roll-over must be provided through the mathematical formulation.
CERC – Deviation Settlement Mechanism and Related Matters (Fifth Amendment), Regulations, 2019
As per clause 4.5 (a) and (b), to meet sign change norm, regional entities (buyer or seller) deviating beyond ±20 MW with reference to schedule need to pay additional charges. This range may be suitable for smaller states. However, for larger states this range may be expressed in terms of percentage of schedule power.
As per provision of clause 4.5 (a) and (b), forced outage of a generating station participating in collective transactions on Power Exchanges are exempted from adherence to sign change norm. Such exemption due to forced outage may be applicable to all generating stations.
As per CERC's DSM 3 Amendment Regulation 2016, there are different methodologies for compilation of deviation charge. Post 3 Amendment to the Regulation in 2016, deviation charges for renewable rich states (states with installed solar and wind capacity 1000 MW) and the rest are differentiated. States like Gujarat, Karnataka, AP, MP, Punjab, Rajasthan, Tamil Nadu, Telangana and UP have reached 1000 MW RE generation capacity and few other states are close to reach this limit. As the number of states qualifying as renewable rich states rises, the asymmetric application of charges may need to be relooked in the future.
Proposed Methodology for Compilation of Coal Price Index
Need for Revision in Methodology for Escalation Index: Variation in the coal prices for different grades, as shown below, clearly highlights the need for more representative coal price index for determining the escalation factor.
Laspeyres Vs Paasche index: As acknowledged in the staff paper the Lespeyres index uses base year rates to derive changes in the Price index in a current period. It is suggested that the Paasche index would be more suitable as it uses current period weights. Since the coal cost burden is on account of the current period's coal purchases, Paasche index would provide a better picture of the cost escalation of the coal being consumed in the current billing period.
Weights used for Index: The proposed methodology suggests use of value (price x quantity) as weights to derive the Price index. Adoption of value as weights would overestimate the Price index as costly coal grades would automatically have higher weights. Use of quantities as weights would be more appropriate.
Geometric Average for Base Year Price Index: Geometric mean of monthly prices for the coal price may lead to under-estimation of the true cost of the coal basket.
Deriving Annual Rate from 6 monthly rate (Step 3 clause 8): It would be more appropriate to account for compounding rather than doubling the six-monthly rate to derive annual rate.
Price Index for Captive Coal Mines: Price escalation in coal prices published by CIL are a reflection of its inefficiency. In the case of captive coal mines operated by efficient private or public sector generators, one would expect the operations to be more efficient and should not warrant for a similar level of price escalation.
Proposed Framework for Real Time Market (RTM) for Electricity
Because of uncertainty related to short-term load forecasting, a liquid RTM would allow DISCOMs to reduce grid imbalances. Further, this will also assist greater RE integration across states.
Enhanced liquidity for Real Time Market (RTM) would also provide better value to electricity available across different hours of day.
A two-hour ahead forecasting would provide a much reliable RE generation forecast specifically for RE sources like wind and solar.
RTM price signals should be used by the DISCOMs for designing more effective TOD/TOU tariff.
Although recent regulatory developments are leading to more efficient and competitive price discovery, the regulatory framework does not provide for appropriate signals for investment in capacity addition. A long-term objective should be to introduce a capacity market with active participation of the distribution utilities.
Revenue sharing mechanism for additional revenue realization by ISGS generators by participating in RTM needs to be specified, such a mechanism should reduce overall cost of power procurement of distribution utilities.
Market monitoring framework needs to be significantly strengthened to ensure that participation across various market segments and those made available through PPA are not gained for the detriment of the procurers, making a long-term dent on the efficacy of the implemented power market design.
As the share of DAM and Short-Term Market increases, the rule of transmission charges for long-term and short-term needs to be revised to ensure that long-term beneficiaries are not overburdened with transmission charges due to increase in share of short-term transaction.
Same DSM framework should be applicable for Conventional and Non-conventional generators with a smaller margin to RE generators in deviation from scheduled power. A deviation of 5% is fairly acceptable.
Proposed Framework for Real Time Market (RTM) for Electricity
Alternate Auction Design - Since fixed cost for all the ISGS generators is borne by the beneficiaries, an alternate auction design, wherein their URS capacity is mandated to bid at their VC (plus 7 paise margin),
can be considered. Merchant capacity can bid as per their economic value. Discovery of market price
would thus become more competitive, and would help recover loss of consumer surplus (see figure
below), thus benefitting the DISCOMs and the final consumers.
Active participation of generators and DISCOMs is crucial to the vibrancy of RTM. The current incentive structure across market segments especially the URS and the RRAS, which provides for
recovery of associated fixed charges, may need to be finetuned. Initial experience with RTM may further
help assess the need and direction for the same.
A high proportion of sell side liquidity (as compared to buy bids) in the Day-ahead contingency and Intraday transactions is observed (Refer to TAM charts on page 5). RTM, a competitive auction mechanism
by design, should be able to attract participation of DISCOMs to ensure that there is sufficient buy side
liquidity, further enhancing the competitiveness envisaged through RTM.
Revised Procedure for Security Constrained Economic Despatch (SCED)
The revised procedure provides for violation of ramping and transmission constraints for obtaining the optimal solution to avoid infeasible or non-convergent cases. Impact of such violations, if recurrent,
should be scrutinised and addressed appropriately.
From a modelling perspective, violation penalties should at least be equal to the highest VC. Higher penalties are generally recommended. In any case, the highest VC (used in this context) should be rounded to the next Rupee rather than the nearest one, thus ensuring a more optimal outcome.
Opposing ramping requirement across two regions, as mentioned in the revised procedure, should generally assist a solution unless the transmission links connecting the two regions face a constraint.
State beneficiaries are to be billed by their respective generator on the basis of RLDC schedule issued prior to SCED optimisation. SCED settlement provides for adjustment towards part load compensation
due to decrement issued to the SCED generators. Such an 'adjustment' should also be provided against
'reduction' in part load operation post increments issued to the generators. Otherwise, beneficiaries face
unsymmetrical settlement thereby causing higher burden to the end consumers.
As SCED is closer to the delivery period (in comparison to DAM), in the event of a communication failure in providing the SCED schedule to the generators, the applicability of/waiver from the resultant DSM charges should be clarified.
The framework for allocating transition corridor for RTM
proposes to allocate transmission capacity across the Power Exchanges based on their share of volume in
DAM. Clarification with respect to its applicability on a block-wise basis needs to be provided.
A mismatch between the allocated transmission capacity (as per the share of DAM) and potential clearing volume in RTM may lead to a situation wherein transmission resources allocated to one of the power exchanges having lower RTM volume vis-a-vis DAM may remain unutilised while the other PX may face a shortage of allocated transmission capacity. A similar problem would be encountered on account of 'minimum 10%' allocation of transmission capacity, even if share in DAM (or potential volume in RTM) was less than that. Such sub-optimal allocation of transmission resources would also lead to inefficient outcome of RTM in terms of cleared volume and prices.
Further, transmission charges for the allocated but unused transmission capacity would be borne by the users who finally use the transmission capacity. POSOCO should evaluate the impact of the allocation scheme and identify the pattern of underutilisation of allocated transmission capacity and seek suggestions to address the same.
The theoretical best solution would be to have common market clearing across the power exchanges, thereby achieving the most efficient market outcome. However, alternate mechanism should aim to mimic that outcome as far as possible.
Definition of Net Gains and Bids below Variable Cost (VC)
The procedure provides for sharing of
'net gain' by the participating generator with the beneficiary. However, there is ambiguity in terms of its
definition. A situation may arise wherein a generator's net VC, after accounting for gains from PLF, is
lower than the approved VC. A generator may thus be willing to bid below its VC. Further, a generator
may also do so to avoid ramping constraint for the plant. In such a situation, the provision for sharing of
'net gains' should not be construed to be 'netted' against the 'under recovery' from RTM, when a cleared
bid being lower than the approved VC. However, this needs to be addressed through Regulatory provisions rather than through scheduling procedure.
'Determination' of Intra-State Transmission/SLDC Charges
In the case the intra-state transmission charges or the SLDC system operating charges have not been determined by the respective SERC, the procedure specifies such charges to be applicable. Legal aspects of such a 'determination' should be reviewed to avoid any issues later.
Standing Clearance by DISCOM/ISGC Generators
DISCOMs, as beneficiary to a generating plant,
can bid for their share in a generator. A generator can also trade the URS post schedule revision window.
Theoretically, same generation capacity can be traded by either of the entity, the DISCOMs and the
generator, in a sequence. Procedure to update the final quantity available with ISGS for trade under RTM
and limiting their transactions under RTM to such extent should be clearly specified. Further, an entity
can submit its bid on both power exchanges to the extent of standing clearance. Since standing clearances
are not exchange specific there is a possibility of final trade for an entity on both exchanges together,
being more than the standing clearance, and thereby possibility of schedule over and above the capacity
of the generator. There is no process laid out to handle such situation.
Communication Failure and Follow-up Procedure
As the time available for communication between
power exchanges and RLDC is limited, the update of power exchange's schedule should be promptly
available on RLDC website for crosschecking by power exchanges. In case of communication failure, a
small window of 3-5 min for follow-up communication can thus be utilised so that there is no adverse
impact on the market outcome and the participants.