Transmission Pricing

CERC notifies draft regulations for sharing charges

The Central Electricity Regulatory Commission (CERC), after deliberating on the contentious issue of transmission pricing for a couple of years, released the draft Sharing of Inter-State Transmission Charges and Losses Regulations, 2019, in October 2019. Once notified, these regulations will replace the extant CERC regulations (notified in 2010), which have been in effect since July 2011. In March 2019, the CERC-appointed taskforce, formed in July 2017 and led by former CERC member A.S. Bakshi, submitted its report to review the “Framework of Point of Connection (PoC) Charges”. In the report, the task force examined the existing PoC mechanism and suggested modifications.

Thereafter, to formulate the draft regulations, CERC constituted a committee under IS Jha, member technical CERC in May 2019. This committee submitted its report in August 2019 with the proposed draft regulations.

The draft regulations, formulated based on the recommendations of the two committees, were initially open to stakeholder comments up to December 2, 2019. Subsequently, the CERC extended the deadline to December 31, 2019. Further, it also published the explanatory memorandum, which accompany draft regulations but were missing previously to lend clarity to the intent of various provisions.

Reportedly, some stakeholders have also requested the regulator to conduct workshops to get greater clarity on the subject. Several workshops were conducted when the existing regulations were introduced in 2010.

Power Line presents a background of transmission pricing in India as well as the key highlights of the CERC’s draft regulations…

Background

Over the past seven to eight years, the power sector has witnessed significant changes. With the rapid growth in generation and transmission infrastructure, India has transitioned from being a power deficit country to a power surplus one. The interstate transmission system (ISTS) has grown from yearly transmission charges (YTC) of Rs 100 billion in 2011 to Rs 360 billion in 2019. This has led to an increase in transmission charges for almost all entities, in varying degrees, depending on the allocation of charges, which are determined based on utilisation. Since the introduction of the prevailing PoC mechanism, several states have raised issues and sought improvements in it. The main aim of the CERC’s 2010 regulations was to make the sharing of interstate transmission charges sensitive to distance, direction and quantum of flow as required by the Tariff Policy. Overall, it has been observed that the POC mechanism has served its purpose, that is, enabled the power market and helped reduce congestion.

The current PoC mechanism is ex-ante, under which the allocation of charges is decided in advance, based on the projected load/generation for the next quarter. As a result, the states can project lower load and higher generation (which will lead to lower PoC charges) as there is no penalty for incorrect projections. In line with the recommendations of the task force constituted to review transmission pricing, the computation of transmission charges in the draft regulations has been proposed to be carried out ex-post every month, based on the actual all-India peak scenario of the month. The monthly transmission charges (MTC) will be considered under separate components defined in the proposed regulations. It may be noted that the CERC has refrained from using the term PoC in the draft regulations.

CERC draft regulations: Key features

The new regulations will apply to all designated ISTS customers (DICs), ISTS licensees, National Load Despatch Centre (NLDC), regional load despatch centres (RLDCs), state load despatch centres (SLDCs) and regional power committees (RPCs). NLDC is the implementing agency (IA) for the computation of apportionment of transmission charges at various nodes or zones.

The basic principle of sharing of transmission charges among the DICs is to ensure that the YTC and related adjustments to the YTC are fully recovered. The computation of charges for each DIC will be based on the technical and commercial information provided by DICs, ISTS, NLDC, RLDCs and SLDCs to the IA.

Sharing of transmission charges

The transmission charges are proposed to be divided into four parts – national component (NC), regional component (RC), transformer component (TC) and AC system component (ACC). The NC will be the sum of two sub-parts – NC-renewable energy (NC-RE) and NC-high voltage direct current (NC-HVDC). The RC includes RC-HVDC and reliability elements while the TC includes charges for interconnecting transformers planned for drawal of power by a state. These charges will be borne by the state. Finally, the ACC is divided into the AC-usage based component (AC-UBC) and the AC-balance component. The latter includes the balance charges for the AC transmission system after apportioning the charges for AC-UBC (see Figure).

Hybrid methodology

It is applied for determining usage-based transmission charges. The existing PoC charges are also calculated using the hybrid method. A usage-based method aims to identify how much of the power that flows through each of the lines in the system is due to the existence of a certain network user in order to charge it according to the adopted measure of utilisation (average or marginal). The hybrid methodology for transmission pricing is a combination of the marginal participation (MP) method and the average participation (AP) method. Under this method, the slack buses are selected using the AP method and the transmission charge on each node are computed using the MP method. (The injection/demand at each bus needs to be counter-balanced by a corresponding increase in demand/generation at certain buses, called the slack buses.) The AP method selects geographically and electrically proximate buses instead of slack buses dispersed all over the network under the MP method.

The steps involved in the method are data acquisition, computation of the load flow on the basic network, identification of slack nodes, determination of transmission charges and sharing of such charges.

Determination of sharing of transmission charges

The MP factors will be computed, based on the AC load flow, to determine transmission system utilisation on account of marginal injection/drawal at each generating station/demand node. The YTC of each line based on modified line wise YTC will be attributed to injection/ drawal for the peak block. This YTC will be allocated to each agent in the proportion of change in flow in the network branch affected by that agent. Then, the AC-UBC charges will be calculated based on the hybrid methodology, and as per the following steps:

  • Two files need to be taken – a modified YTC file for the month and a base case file
  • The base case file (BCF) will be imported in software
  • A load flow analysis will be conducted to obtain a marginal flow (MF) file
  • The MF file will be modified in the following ways – for generators/sellers with identified buyers, the MF will be reduced to zero; for generators with part long-term access (LTA) to a target region and part tied up capacity, the MF for injection corresponding to the tied capacity will be reduced to zero; for generators with LTA to a target region, MF values will be retained
  • Negative marginal factors to be made zero
  • MP factors less than 0.0001 to be taken as zero
  • MF file to be normalised so as to make the total MF 1
  • Multiply the modified MF file with MTC file
  • Node-wise charges will be calculated (Therefore, the current method of defining the charges under nine slabs will be replaced. Instead, there may be several rates depending on the number of ISTS grid players.)

Transmission charges based on the hybrid method will be computed for each DIC every month. The charges allocated to each demand node will be grouped together within each state. Usage-based charges for billing towards LTA/ medium-term open access (MTOA) will be calculated only on drawal nodes and for generating stations with LTA to a target region corresponding to the untied power. The transmission charges for generating stations with no LTA or MTOA will be calculated as injection charges (like above generators with untied capacity) under the AC-UBC component. The charges for other DICs, for whom AC-UBC charges have been computed, will be scaled up to the extent of charges attributable to such generators.

Transmission charges for special cases

Transmission charges and losses for the use of ISTS will be waived in the following special cases:

  • Solar projects commissioned from July 1, 2011 to June 30, 2017
  • Solar or wind projects that have been awarded through competitive bidding;
  • Solar projects that have declared commercial operation between July 1, 2017 and February 12, 2018, and wind projects that have declared commercial operation between September 30, 2016, and February 12, 2018;
  • For which PPAs have been executed with distribution companies for RPO compliance

For projects that meet all these criteria, transmission charges will be waived for 25 years from the date of commercial operation date (COD)

  • For the solar or wind projects:
  • That have been awarded through a competitive bidding process as per the guidelines issued by the central government
  • That have declared commercial operation between February 13, 2018 and March 31, 2022
  • For which PPAs have been executed with all entities including distribution companies for RPO compliance

For such projects, transmission charges will be waived for 25 years from the CoD

  • Long-term and medium-term open access are exempted for computation of transmission charges for cases mentioned above.
  • If the COD of a project is delayed and the associated transmission system has achieved commercial operation as scheduled, the YTC for the transmission system has to be paid corresponding to the capacity of generating stations/ units that have not achieved COD.
  • If the project has achieved COD and the transmission system is delayed, the concerned transmission licensee will be required to make an alternative arrangement for the evacuation of power. Until such an alternative arrangement is made, the transmission licensee will have to pay the charges proportionate to LTA to the transmission system that is delayed.
  • If LTA to the ISTS is granted to a project based on existing margins and the commercial operation of the project is delayed, then the transmission charges at the rate of 10 per cent of state transmission charges will have to be paid.
  • Generating stations drawing start-up power will have to pay transmission charges at the transmission deviation rate for the state in which they are physically located.
  • When a generating station is connected to both the ISTS and the intra-state transmission system, the ISTS charges and losses will be applicable only to the quantum of LTA and MTOA connected through the ISTS, and STU charges and losses will not be applicable to such capacity connected through the ISTS.

Sharing of transmission losses

The drawal schedule of DICs will be worked out as per the provisions of the Indian Electricity Grid Code, after taking into account the transmission losses of the previous week, which are calculated by the IA as follows…

The all-India average transmission losses of the ISTS for each week = {(Sum of injection into the ISTS at regional nodes for the week) minus (sum of drawal from the ISTS at regional nodes for the week)} ÷ Sum of injection into the ISTS at regional nodes for the week x 100 per cent

It may be noted that no transmission loss for the ISTS will be applicable while preparing the schedule for injection nodes including that for collective transactions over the power exchanges.

Accounting, billing and collection of transmission charges

  • The IA will notify the total transmission charges payable by DICs for a billing month in terms of Rs per MW for each state by dividing the total transmission charges payable by the state by its quantum of LTA and MTOA.
  • Regional transmission accounts for all DICs will be prepared by the respective RPCs based on the total transmission charges, DIC-wise transmission charges for the month received from the IA, and meter readings received from RLDCs from special energy meters (SEMs) for the computation of deviation from LTA and MTOA for every time block.
  • The CTU after raising bills for transmission charges, collects it from DICs and disburses the same to the ISTS and intra-state licensees whose assets are included in the YTC. No transmission charges will be levied for the ISTS in respect of STOA.
  • At least one month prior to the date of operationalisation of LTA/MTOA, each DIC must execute a payment security mechanism through a letter of credit (LC) in favour of the CTU to be made operative from a date prior to the due date of its first bill and it shall be renewed annually.
  • The due day for the payment of bills is 45 days from the date of raising of the bill.
  • In case of payment defaults of over 60 days, the CTU will serve a proper notice for the resolution of the default within 60 days. If not resolved, the defaulter will cease to be a customer and its membership will be terminated by the CTU.

Conclusion

It is acknowledged that transmission cost allocation is a contentious issue worldwide. However, experts opine that transmission pricing must be kept as simple and easy to understand as possible. There is also a view that with the transition of India’s power sector to general network access, policymakers could consider moving from cost allocation based on zonal pricing to that based on access to the network where every grid participant, generators and drawing utilities, is liable to pay an entry and exit charge.

For now, grid participants have to focus on decoding the latest draft regulations in order to understand the details of the proposed methodology and their likely impact on the transmission charges payable by them. n

Swarna Kesavan

GET ACCESS TO OUR ARTICLES

Enter your email address