The primary focus of this bill is to open the supply side in distribution to competition in the market.
The State Electricity Regulatory Commissions (SERCs) constituted under state-level legislation in seven states from 1995 and subsequently under the Electricity Regulatory Commissions Act 1998 (since subsumed into the Electricity Act 2003), have failed to uniformly tackle the twin problems of high operational cost and distorted retail tariff structures that do not reflect the cost of supply.
The average technical and commercial loss in distribution (difference between energy input into the system and energy billed) was 21 percent (2019–20) and discoms (licensed distribution and retail supply companies or entities) incurred a loss of INR 867 billion after accounting for support of INR 1.1 trillion from the government. Without government support, the loss would be 1 percent of the net state domestic product. As of 19 August 2022, discoms have accumulated overdue, unpaid bills of INR 1.37 trillion. Since 2000, the fourth attempt to reform discom finances is underway which includes legislative changes to improve the regulatory incentives for reform.
The Union government proposes to infuse some reform momentum by tweaking the existing legislative provisions of the Electricity Act 2003 through an amendment bill tabled in the Parliament on 8 August 2022.
In earlier legislative attempts at reform, the focus was on creating competitive conditions on the demand side of retail supply by, for example, allowing open access (allowing customers to choose their supplier) for large users of electricity. This time around, the primary focus is to open the supply side in distribution to competition in the market.
The monopoly of discoms over retail supply in their licensed areas will end. A multiplicity of suppliers was previously possible as well. The catch, however, was that the incumbent was not obliged to let the newcomers use its network. This made contestation well-nigh impossible because of the implementation challenges (right of way) in laying new networks and the associated time lag. This difficulty is now proposed to be removed by allowing new licensees to use the existing network on payment of a user (wheeling) charge.
However, rationally defining the user charge is not trivial, particularly since the new licensee would wholly depend on the incumbent’s network to fulfill supply commitments. Regulations will be needed to specify non-discriminatory access to network monitoring data for the new licensee, along with sufficiently high deterrent, penal provisions, and compensation for loss of business, due to system outages in addition to compensation for customers.
In a major change, the Central Electricity Regulatory Commission (CERC) will now license applicants for distribution in more than one state. Previously, licensing distribution was purely SERCs function.
Regulations would need to be in place to separate the regulatory mandates of the two commissions. Would the CERC seek a no-objection—which should not be unreasonably withheld—from the relevant SERCs before issuing a license? Both the existing licensees and SERCs need to be heard before the market structure is dramatically altered. If the incumbent discom is privately owned, legal suits could be anticipated if CERC acts unilaterally. It remains unclear which commission could revoke the license. CERC, the licensor, should typically also have the authority to revoke the license. Would CERC operate on the recommendations of the SERC, any other interested party or suo moto?
The amendment specifies that liabilities arising from the existing PPAs of the incumbent discom will be shared proportionately between the incumbent and the new player. Regulations must specify how the actual (not average) costs would be allocated between the two discoms if significant variations in their load profiles generate differential costs of supply.
The new licensee is barred from contracting for additional power, so long as the legacy PPAs are sufficient to meet demand—a sensible provision to avoid over-contracting of supply, but administratively difficult to implement. Would the bar apply to contracting additional renewable power when the national programme is to rapidly increase renewable capacity?Alternatively, what if the new licensee gets new PPAs at cheaper rates than the cost of terminating the existing PPAs? Would it not be economical to do so? Savvy regulations need to specify sensible carve-outs for new power contracts.
There is also concern about how the universal service obligation will be enforced. Both discoms would strive to shed loss-incurring customers and maximise profit-giving customers. Would regulations enforce a minimum share of area-specific, below-cost-tariff customers?
To guard against selective poaching of customers, an associated, new institutional mechanism for sharing the cross subsidies generated is proposed. The “surplus” cross subsidy (the difference between the allowed cost and regulated tariff) collected by any licensee is to be deposited in a cross-subsidy fund managed by a government company nominated by the respective state government. The SERC would determine how to use the balance in this fund. Some could be given back to the originating licensee. The residual could compensate for the second discom, or even be transferred to another needier supply area. Creating managerial uncertainty about cross subsidy, as an assured source of revenue, might result in a focus on efficiency improvement instead.
SERCs will now determine the minimum and maximum tariffs, giving individual licensees free play in charging tariffs within the range. This will encourage efficient licensees to reduce the tariff to gain market share.
The problem is leaner margins linked to high efficiency are also likely to reduce the attractiveness of the business for a second licensee. Secondly, if the cross subsidy is divertible to another area of supply, are we not creating a new class of cross subsidy? How consistent is that with the dictum that tariffs should reflect costs?
SERCs will now determine the minimum and maximum tariffs, giving individual licensees free play in charging tariffs within the range. This will encourage efficient licensees to reduce the tariff to gain market share. Unique discom tariff plans could emerge resembling the telecom model, encouraging customers to choose the plan most appropriate for them.
Another thing to note is that users with a load above 1 MW can now access the interstate transmission system and buy directly from the market or contract with a bulk supplier. Whether SERCs will cooperate by limiting surcharge and wheeling charge to reasonable levels remains critical.
In a welcome move, the primacy of the National Load Despatch Centre over Regional (RLDCs) and State level load despatch centres (SLDCs) has been explicitly established. All constituents of the grid are obliged to comply with the directions of the NLDC. This will help in maintaining grid discipline and stability.
Earlier SLDCs, while functionally subordinate to the NLDC-RLDC, marched to the drum beat of State Grid Codes as their rule book, ignoring real-time actions necessary for grid stability. NLDC will now also be able to enter PPAs, with the government’s permission, to contract in ancillary and backup support instead of having to rely on a daily nomination basis to secure backup support from generators, not likely to be despatched due to higher cost.
Broadening the functioning of the Forum of Regulators to formulate model regulations for SERCs and to monitor utility compliance with corporate governance and performance standards empowers this nascent institution of great relevance for developing esprit-de-corps within regulatory experts.
Top-down intervention by the Union government (UG) has increased. Multi-state SERCs can be created, merely by consulting state governments. Earlier mutual agreements were needed. Sadly, it has also reverted to micromanagement. The UG will define criteria for the areas of supply for cross-state licensees. State governments were so authorised earlier because SERCs were nascent in 2003. But now they and CERC are fully functional. UG will prescribe the payment security mechanism for despatched power. UG would approve the purchase of electricity by the NLDC for stabilising the grid despite the CERC now being authorised to determine the functions of the NLDC. UG officials, not CERC representatives, would sit on the selection committee for SERCs. All these functions could be delegated to the CERC to empower it further and to develop the spirit of cooperative federalism between it and SERCs.
The P word remains taboo, even though privatisation in well-off supply areas, remains the better option for operational improvements versus introducing competition via legislation through multiple licensees.
Nevertheless, using the deterrent power of competition to force improvements in the largest publicly owned distribution and retail supply segment is commendable. The quality of the regulations will determine how well legislative objectives are translated into measurable changes in behaviour and outcomes. The P word remains taboo, even though privatisation in well-off supply areas, remains the better option for operational improvements versus introducing competition via legislation through multiple licensees.
The 2007 amendment to the Electricity Act 2003, deleting the regulatory objective of eliminating cross subsidy, did a great disservice to the sector. Cross subsidy harms the economy and retards carbon mitigation; it must be eliminated. Furthermore, income support should be transferred directly to targeted customers by the state government, allowing them to choose their level of supply, as in telecom. Discoms must operate on a commercial basis, only then will the competition have teeth.
The views expressed above belong to the author(s). ORF research and analyses now available on Telegram! Click here to access our curated content — blogs, longforms and interviews.
Sanjeev S. Ahluwalia has core skills in institutional analysis, energy and economic regulation and public financial management backed by eight years of project management experience ...
Read More +
PREV