Should there be assured returns in the power sector?

DEABTE

Jagdish Sagar
Former principal secretary,
Power, Govt of NCT of Delhi

The question, as posed, will seem like red rag to some, suggesting rents for inefficient performance. In real life in the power sector "" and most certainly in the distribution business under prevailing conditions in India "" there is no such thing as an "assured return" in that sense.

Admittedly, the template for tariff-fixation has been a "cost-plus" model, in which a return is fixed, which must have some relation to the assets employed; and such returns are invariably included in the costs allowed to the utility in tariff orders.

There were time-honoured formulae for the "reasonable return" under the Electricity Supply Act, 1948, which the Electricity Regulatory Commissions Act, 1998 (and generally the different State Reform Acts) retained as guiding principles for tariff fixation, although without making them compulsory.

In the Delhi reforms, the policy directions issued by the government required the commission to ensure that until the end of 2006-07, the discoms earned at least a 16 per cent return on equity and free reserves (subject to achieving the annual efficiency improvement targets that were fixed through the bidding process).

Reportedly, the N K Singh committee has suggested a similar 16 per cent return in the distribution business, and 14 per cent in generation.

It does not follow that utilities batten on the consumer through these "assured returns". For when such utilities are incurring heavy losses because of their inefficiency, there is no way regulators will let them pass on the full burden of inefficiency to the consumer.

The tariff is, therefore, invariably based on a targeted reduction of transmission & distribution (T&D) and aggregate technical and commercial (AT &C) losses losses; and very few utilities actually achieve the targeted reduction.

The returns fixed for generation and transmission are also subject to normative efficiency standards, besides being further subject to a serious payment risk.

Regulators also disallow other major costs "" usually by applying normative standards, but sometimes quite unpredictably "" in order to keep the tariff down: that happened in Delhi last year.

In practice, thus, all tariffs tend to become normative, and are incentive-based to the extent that, to actually profit from the supposedly-assured return, the utility must achieve some efficiency improvement and cost reduction.

Indeed, without incentives for over-achievement (which we have in Delhi) the prescribed return actually works more like a cap on profit.

The overwhelming need is to attract investment into the sector, particularly in distribution, which means that: (i) we must ensure the prospect of reasonable profit to an investor who performs well, with incentives to perform even better, while (ii) mitigating all risk factors, including regulatory risk, which will not be in the investor's control, yet (iii) minimising the possibility of excessive profit or windfall gains.

Some form of multi-year tariff is, therefore, desirable; it would also mitigate uncertainty from the consumer's point of view; and it is absolutely necessary if we want to privatise an existing state electricity board or government-owned discom.

The Electricity Act, 2003, mandates multi-year tariffs as a guiding principle. This reflects a welcome shift in thinking. In early 2001, in order to facilitate privatisation, the Delhi Vidyut Board (DVB) proposed the first five-year package, envisaging formulae for fixing each of the cost components with reference to the base year.

The idea was shot down amidst howls of uninformed protest, and a much-attenuated package (limited to loss-reduction targets) had to be adopted. The subsequent lesson of this experience has been the need for a more comprehensive package as originally envisaged.

Given the present state of information and experience, such multi-year tariffs are likely to be constructed by projecting the major costs, targeting some efficiency improvements for the "controllable" costs (notably system losses) and perhaps allowing for mid-course or annual correction. In constructing such tariffs, it will remain useful to adopt a benchmark for the utility's return as for other costs.

In the distribution business the level of return allowed makes very little difference to the tariff: what matters most is reducing losses and, given the risks in distribution and the paucity of interested investors, the benchmark return for distribution should be higher than in generation. But such benchmarks will never carry an assurance of profit.

J L Bajaj
Distinguished fellow, The
Energy and Resources Institute

The Electricity Act, 2003, has been in place since June 10, 2003, consolidating and replacing several existing laws governing the power sector in India.

The market construct of the Act requires the sector to move progressively towards competitive power markets and away from "cost-plus" regulation. The key question at this juncture is whether a fixed rate of return (RoR), which characterised the "cost-plus" system, is an anachronism in this evolving market construct.

The applicability and the definition of RoR need to be evaluated in the context of the provisions of the Act. Section 62 of the Act requires the appropriate commission to determine the tariffs for supply of electricity by a generating company to a distribution licensee, transmission of electricity, wheeling of electricity and retail sale, unless such tariffs are determined through a transparent bidding process as per provisions of Section 63 of the Act.

Thus, in cases where the tariffs are not determined through bids, the costs of the utilities, including the allowable RoR, will have to be determined by the regulators.

In economic theory, unlike in accounting practice, normal return on investment is a part of the opportunity cost of production. The premise that the tariffs should be market-determined to the extent possible is beyond question.

However, to evaluate whether tariffs can reasonably be determined through market-determined processes, one has to look at the three main segments of the electricity business "" generation, transmission and distribution.

Generation is most amenable to competition. However, distinction needs to be drawn between competitive procurement of power and competitive generation capacity.

In the former, the generator assumes market risks through the life of the project, whereas in the latter, the market risks remain with the buyer by virtue of the power purchase agreement (PPA) mechanism.

As much as the former is desirable, it needs to be recognised that competitive power markets, where sellers take the market risks, is still some time away.

Section 66 of the Act vests the responsibility of market development primarily with the regulatory bodies, who have to evolve the market design and address all relevant issues, including the treatment of stranded costs.

Even for establishment of generation capacity through competitive tariff bidding, it would be applicable only for new generation capacity.

For older generation capacity or for extension of capacity, competitive tariff bidding would not be feasible unless the PPA mechanism is done away with. When the capital cost of the asset is already established or the promoter is identified, there is no opportunity to determine tariffs through competitive bidding.

Hence, there is no alternative to RoR regulation. Also, market participation of existing depreciated plants would in several instances result in unacceptable increase in charges paid to such generators, with corresponding impact on retail tariffs.

The prospect of purely market-based tariffs in transmission and distribution is remoter. Both these segments are natural monopolies and, hence, market-determined tariffs are relatively difficult to evolve.

Limited scope for tariff bidding for new transmission lines does exist. However, the overall tariffs are likely to largely remain regulated.

The supply component of the distribution business is likely to witness competition on account of open access. Even then, the base tariffs of licensees would still remain regulated, based on the RoR approach.

There is also a need to de-mystify RoR regulation, which has been demonised due to poor and unimaginative application. There is a perception that RoR regulation requires establishment of rigid returns to the utilities and entails intrusive regulation of utility operations. This need not be the case.

On the contrary, the tariff-determination approach should envisage as little regulation of input costs as possible beyond the initial tariff setting and should make the utilities responsible for their efficiency or inefficiency.

The need for standard benchmarks for RoR for the individual segments exists and cannot be wished away. Uncertainty on this account can mean significant regulatory risks.

However, benchmark returns used for tariff determination should not be a limiting factor for efficient utilities, which should retain profits beyond the normal returns commensurate with their efficiency levels.

Eventually, the RoR regulation should give way to market-determined tariffs for all business segments. However, the move to entirely deregulated and market-determined tariffs is still some distance away, and till this happens, the emphasis should be on hands-off regulation and greater flexibility to utilities to be efficient and earn higher returns that would not be limited in any manner by benchmark rates.