Electricity Pricing and Availability Based Tariff for Competitive Electricity Markets
Electricity Pricing and
Availability Based Tariff
for Competitive electricity markets 
Prof. V Ranganathan.
Professor (Retd.), IIM, Bangalore.
Until recently electricity industry throughout the world was a regulated integrated natural monopoly, with generation, transmission and distribution being vertically integrated. The industry was restructured in many advanced countries, US, UK, Europe, Australia and also later in developing countries like India, Pakistan, Nepal, Thailand etc. Competition was the reason for restructuring in the US, where there was a big price gap between States, and the customers in high priced States wanted to shop around for electricity from low priced States, by having wholesale competition through open access. At that time, the gain to customers and efficient producers and the loss to inefficient producers was estimated to be $100 billion, which was the motive force for restructuring. In UK, the driving force was the conviction that business is not the business of the Government, and the consequent privatization drive started with Ms. Margaret Thatcher, beginning with privatization of coal mines, when the miners went on a strike and took the country to ransom. In India, the motivation for reforms was the funds crunch. During the time of Mr.Arif Mohamed Khan as the Power Minister, CEA made the forecast that for the next year the incremental demand would be 50 GW, against the existing capacity for the previous 30 years of only 50 GW. The Government approached the World Bank for funding this expansion, for which the World Bank put the condition that the country should undertake Power Sector Reform. Coincidentally, the World Bank itself was being questioned by the US appointed Meltzer Commission, for its role in duplicating the work of capital markets, instead of sticking to its original mandate of ‘removing poverty’. The operational significance of this criticism was that the World Bank should stop funding power sector hardware by lending for power stations by NTPC etc., and should focus on funding ‘reform studies’.
Notwithstanding the different foci for restructuring in different countries, introduction of competitive markets in electricity became a central theme not only in the US, but also in UK, Australia etc. The main themes were, unbundling the industry into its segments, generation, transmission and distribution, deregulating generation which became amenable to competition and regulating transmission and distribution which were still natural monopolies. The World Bank coined two terminologies, one for the developed world and one for the developing, viz. competition in the market for the West and competition for the market for developing countries. The former was multiple suppliers quoting hourly or half hourly prices for their generation and bidding to the pool or independent system operator; the latter was ‘competitive bidding’ as in India, to supply electricity at fixed price for the next 25 years.
Competition meant that generators could supply to any big customer or utility in any State and similarly the distribution utilities or big customers can buy from any generator or supplier (wholesale competition). This required the legislative measure of introducing ‘compulsory nondiscriminatory open access’ in transmission. Along with this, the transmission pricing had to be reworked, because in the days of integrated monopoly, all the costs of generation, transmission and distribution were embedded in one price. The simplest form of transmission pricing was the postage stamp pricing. A postage stamp rate is a fixed charge per unit of energy transmitted over a zone, irrespective of the distance within the zone. For transmitting power across zones, the price corresponding to every zone was added, and this process was called ‘pancaking’. Postage stamp rates are based on average system costs, and may be either cents per kwh or cents per kw or a combination of both energy and capacity charges. The charges can vary with peak- off-peak, week day and week-end, firm vs nonfarm transport of electricity etc.
Traditional transmission pricing was based on ‘contract path’, from a point A to B, along a transmission line, so constructed for that purpose. Contract path pricing may be agreed by participants to minimize transmission charges and avoid ‘pancaking’. However, as WW Hogan[i] argued contract path is a fiction, and does not reflect actual flow of power, which is determined by Kirchoff’s law, and flows into a network. He suggested ‘nodal pricing’, which is the difference between the prices of electricity at 2 nodes in different locations, since the cost of transmission will then equilibriate the two prices. If the price of power in Chukka (in Sikkim) is Rs.1 per kwh and in Bangalore it is Rs.3 per kwh, then the transmission cost between Chukka and Bangalore should be Rs.2 per kwh. Another variant is flow based pricing, viz. dollars per MW-km; where the price depends on the quantity of power transported and the distance. A third variant is ‘congestion pricing’, where the price increases with congestion, based on the principle that whoever has the maximum willingness to pay, must be allowed to transport first in order to use the transmission capacity efficiently. It is much like the dynamic pricing practiced in the airlines, where you always have a seat, even at the last minute, but at a high price. However, unlike the airlines’ dynamic pricing, congestion costs can be assigned either to the marginal user, or can be shared with all existing users, as it will indicate the need for adding another line to transport electricity, wherever there is congestion. When the transmission becomes congested so that no more power can be transmitted from say Eastern region to Southern region, more expensive generation may have to operate in Bangalore in South than a pithead mine in Orissa. In a competitive market, regardless of the form of transmission pricing used, this would create a difference in the generation prices between the pithead mine in Orissa and a load centre station in Bangalore. (The Central Electricity Authority had long established that carrying electricity through transmission lines is much cheaper than carrying coal through Railways.) The difference between these prices is the ‘economic price of transmission’. It reflects the costs of congestion and losses. In the absence of congestion pricing for transmission service, these ‘economic rents’ would represent a windfall gain to the generation suppliers who are able to sell through the congested interconnection. The congestion revenues can be allocated to market participants through reduced access fees etc.
In India, the Electricity Act (2003) brought ‘compulsory nondiscriminatory open access’ for transmission, but competition was blunted by the retrograde ‘open access surcharge’ on the one hand and pancaking and arbitrarily high wheeling charges designed to protect inefficient State Electricity Boards, by the State Electricity Regulators, who were captured by the utilities they regulated. In fact, before the advent of the regulators, the transmission cost was just to compensate for the transmission losses, since transmission investment was completely decoupled from transmission pricing. The CEA would identify weak links and would augment transmission, subject to availability of funds. This had resulted in most of funds going for generation and transmission getting very little investment. Even when transmission got funds, it was frittered away in inessentials like telemetry, SCADA etc. Today the new mantra is ‘smart grid’ which enables time-of-day pricing etc., but at present the first priority is removal of congestion and enabling power to flow, i.e. sticking to the basics of transmission line laying. Even now, the national grid is not fully integrated, and we have two grids operating asynchronously, the southern grid and the rest of india grid. The only gainers of these deficiencies are 3 entities in India, the Power Trading Corporation, The Indian Energy Exchange IEX, and Power Exchange India Ltd., PXIL, who gain out of arbitrage opportunities. At present we have Eastern region surplus and the remaining regions deficit and there is a lot of congestion due to absence of transmission lines to evacuate power from Bramhaputra basin, Nepal, Bhutan etc.
Before the advent of Availability Based Tariff introduced by the CERC, the situation was far worse, with rampant grid indiscipline and States waylaying power meant for other States. In order to overcome this indiscipline, the high voltage point to point d.c. transmission was installed, which enabled transfer of power from generation station to beneficiary State directly on a point to point basis. This was obviously an infructuous expenditure in a resource constrained economy, just like the investments in standby diesel sets are today. The ABT came as a big game changer in this circumstance.
ABT divided the power flow into two parts: a scheduled part and an unscheduled part. The scheduled part had a capacity charge and an energy charge. The capacity charge was to reimburse fixed cost of plant, linked to plant’s declared capacity to supply MWs to the generating station; to the receiving State, it was proportional to the State’s share in the declared output for the day, of the plant. The energy chare was to reimburse the fuel cost of scheduled generation. The excess drawal of the States were priced in a third category of UI (Unscheduled Interchange) Charges, set much higher during periods of deviations below the standard frequency of 50 Hz, and very little incentives for generators who produce excessively during unwanted periods, when the system frequency shot up above 50 Hz. The ABT is explained with great clarity by Bhanu Bhushan in a primer on ABT[ii].
Process of ABT: Central Generating Stations indicate their next day output capability to RLDC (G1, G2, G3). RLDC translates these into States’ entitlements according to their share (based on a modified Gadgil formula, which gives a greater share to the State where the plant is located, and a lesser but equal share to all other States in the region) (E1, E2, E3), and communicates them to SLDCs. The SLDCs convert them into their requirements (R1, R2, R3: Ri <= Ei). These are then transformed into Dispatch for the CGSs as (D1, D2, D3) and as drawal limits for receiving States (d1, d2, d3). Each CGS’s marginal generation cost corresponds to a certain grid frequency for which it is equal to the UI rate. When the grid frequency is lower than this, it has all the incentive to operate at 100% of its capacity. When the grid frequency is higher than this critical frequency, that plant can back down and save the marginal cost of generation, and instead buy from the grid since that cost is lower. Thus it leads to merit order operation of plants, and settling down at a grid frequency level corresponding to optimal loading, given the capacities of the plants. Of course, storage hydro operation is more complicated: there the objective is that (i) energy storage capacity must be fully utilized over the year (ii) it should be operated so as to replace the costliest source of other energy. Henry Jacoby has suggested a trick of using an inverted demand duration curve to place the merit order position of hydro satisfying the above two constraints[iii].
The ABT, and more particularly its third component of UI charge, has significantly reduced grid indiscipline, by imposing fine on errant States. However, certain problems remain. Hydro power is a State resource and the previous Electricity Act had kept the pricing of hydro power in the jurisdiction of the State, and rightly so, keeping the federal structure of India, in place. Thus hydro operation is exogenous to ABT rules, and may bring in some asymmetry, particularly in the light of generation incentives. (Can the States decrease their hydro generation and increase their thermal portfolio, to claim incentives?). In UK when this advance declaration a day ahead was introduced, generators could game the system by mothballing, viz. declaring a capacity unavailable as under maintenance, and bringing it on the day of demand claiming a higher price for it. Such abuses, one suspects, are available to Indian generators as well. Most importantly ABT does not give signals for increasing generation capacity, in fact, probably does the opposite, by increasing grid frequency and lowering payment, when capacity is augmented. This is similar to the problem UK had when the regulator had given a capacity payment to all the generators who were called in to supply, and who had bid lower than or equal to the system marginal cost. Though the capacity payment was based on the shadow price of power and was equal to the loss of load probability and the value of loss of load, the generators had to calculate when it will increase their payment if they added capacity and when it will decrease it, by reducing lolp.
The final drawback is that the UI charges are determined by the regulator and not market determined, nor is a method suggested whereby the UI charges set by the regulator will serve as initial conditions and the system will move to a different set of values based on overall supply and demand. Thus it fails critically to meet the condition of competitive supply, which means supply = demand.
India has 3 power trading houses, one in public sector and two in private sector. The total amount of power traded is a very small quantity about 1-2% of total power generated; Average price in 2008 was around Rs.7.5 per kwh and maximum price Rs.11 per kwh. The public sector PTC had a margin of Rs.3 per kwh (too high!), but a gross profit of only 2% of the turn over of Rs.88,687 million, for trading on 28,597 MU in 2012-13. The CMD and Board members who were mostly Government IRS bureaucrats gave themselves hefty salaries of upto Rs.1 crore per year, merely for milking the arbitrage opportunities. IEX, headed by retired IAS, had a margin of 5.2 paise per kwh in 2013-14, but had a profit before tax of 87% on turnover on trading 29,270 MU of energy, showing a much slimmer organization. The third exchange, PXIL which was formed with NSE and NCDEX, does not have its annual accounts on its website. It is worthwhile to point out, none of these 3 exchanges have brought in competition; they have been the beneficiaries of the overall shortage of power and the consequent arbitrage opportunities.
Conclusion: With the arrival of private sector in power generation, the generation industry moved on from engineers to financial engineers. Yet, sufficient generation has not been forthcoming because transmission and distribution are still regulated, and the regulators are more mindful of tariff shock, than in incentivizing adequate supply of electricity. This has lead to lot of investment that has gone into generation, not being able to deliver the power. Reform of transmission is most vital to give signals for competitive markets in electricity to emerge. For that to happen, the transmission and distribution reforms should take place, and the engineers must be working alongside financial economists. Merely, bringing engineers and stock exchange people, will not do.
 Paper presented at the National Conference on Power Transmission and Distribution, Bhopal on 22-23, Sept. 2014 by Indian Power Management Academy.
 A natural monopoly is one where a single firm alone can produce at the minimum cost. Typically this was due to economies of scale—the feature of long run average cost declining with output—through this was a sufficient but not necessary condition for a natural monopoly.
 Vertical integration is being integrated along the value chain; horizontal integration means integration among different geographical areas.
 Estimated by Prof. Paul Joskow, MIT.
[i] WW Hogan “Contract networks for competition in transmission grids” IAEE, 15th Annual International Conference, Plenary paper, Tours, France, 18-20 May, 1992.
[ii] Bhanu Bhushan “ABC of ABT: A primer on Availability Tariff” 27 June 2005
[iii] Turvey and Anderson “Electricity Economics” World Bank., chapter 13.