Column: Power pangs

Updated: Nov 15 2013, 05:39am hrs
The recently released report of the Power Finance Corporation on the performance of state power utilities shows that, at aggregate all-India level, the gap between the average cost of supply (ACS) and average revenue realised (ARR) has consistently increased from about R0.49 per unit of electricity sold in 2006-07 to about R1.08 in 2011-12, if subsidy is not considered. Even with booked subsidy, the gap between ACS and ARR has consistently increased from R0.25 per unit in 2006-07 to about R0.70 per unit in 2011-12. With ACS and ARR figures for 2011-12 at R4.39 and R3.31 per unit, respectively, it can also be seen that, even after accounting for booked subsidy, the tariffs on an average will have to go up by almost 25% if the ARR is to converge with ACS. In light of this, it is not surprising that state governments are opposed to any increase in tariff due to shortage of coal. We try to examine what will be the burden on the already loss-making state utilities and its impact on consumer tariffs.

The decision to go for competitive bidding did seem vindicated in terms of lower tariffs discovered till problems cropped up. First in the nature of non-availability of coal to the extent required by developers to fulfil their contractual obligations from Coal India Ltd (CIL), and then in the nature of change of law in Indonesia which resulted in steep increase in the price of imported coal available from Indonesia. This has created a situation where financial viability of about 70-75% of the contracted capacity, involving an investment of about R1,700-2,000 billion, is perhaps threatened.

Based on Central Electricity Regulatory Commissions statutory advice dated May 20, 2013, the ministry of power advised state governments and state regulatory commissions to consider allowing pass-through of higher fuel charges arising out of coal shortages made good by imported coal on a case by case basis. The impact of this suggestion to allow pass-through of higher fuel charges on the distribution companies (discoms) and their consumers, however, will vary depending on the mechanism used for bidding, the source of fuel, and the structure of the bid. In the following paragraphs we analyse the impact with respect to capacity contracted under case 2 bidding mechanism.

As per the competitive bidding guidelines, where the location, fuel or fuel linkage are specified by the procuring discoms, the procurement is to be considered as being done under case 2. With the notification of new guidelines for competitive procurement of power by utilities on September 25, 2013, the case 2 guidelines now stand repealed. However, about 10,400 MW of capacity already stands contracted under case 2 bidding mechanism.

For about 8,500-9,000 MW of this capacity, fuel availability is through linkages to domestic coal mines. For the balance, the fuel source is a captive mine. With CIL unable to supply full quota of coal required to run this 8,500-9,000 MW capacity, resort to imported coal to run the plants at a normative plant load factor (PLF) of 85% is unavoidable. Since the cost of imported coal is two to three times the cost at which linkage-based coal is available through CIL, normally the developers of this capacity would have incurred losses to run their plants at normative PLF of 85%. However, for majority of this capacity, the bids were invited on the basis of capacity charge and net heat rate. This has meant that the procuring utilities have assumed the entire fuel cost risk. In other words, the developers of this capacity do not stand to incur any losses on account of higher cost of imported coal, provided they are able to procure the coal to run their plants or keep their plants available at normative PLF of 85% or they do not face any technical problems in running their plants on blended (imported and domestic) coal.

Thus, in the case of capacity contracted under case 2 bidding mechanism, the adverse impact of CIL not being able to supply the required quantity of coal will entirely fall on the procuring discoms or on consumers, if utilities are able to pass-through the impact through increased tariffs. What is pertinent to note is that, even if procuring discoms opt to not procure electricity from these plants beyond what is generated through CIL-linked domestic coal, they will still have to pay the entire capacity charge as long as the developers of this capacity are able to keep the availability equal to the normative PLF of 85%.

Data shows that majority of case 2 capacity has been procured at levelised tariff rates of R2.80 to R3.02 per unit. Assuming the price that state discoms pay, preliminary analysis shows that the marginal cost of supply contracted under case 2 bidding mechanism would be in the range of R5.5 to R5.9, after accounting for aggregate technical and commercial losses, discoms return on equity and other expenses. If we factor in CILs inability to supply the requisite quantity of coal and the recourse that needs to be made to imported coal as a result, the marginal cost of supply could go as high as R5.8 to R6.3 per unit. Clearly, such high levels of marginal cost of supply will put unsustainable burden on the already loss-making discoms or will result in large increases in average consumer tariffs.

The impact of inability of CIL to fulfil its contractual obligation to supply the needed coal will not affect the developers who have contracted their capacity under case 2 bidding, except maybe in terms of loss of incentive for generating beyond PLF of 85% as the procuring discoms may choose not to buy the relatively costly power beyond PLF of 85%. Capacity contracted under case 2 will not, thus, require the kind of bail out that will perhaps be required for capacity contracted under case 1 or as ultra mega power projects. However, the discoms and consumers, on the other hand, will have to face the full (100%) impact of the increased fuel cost with respect to capacity contracted under case 2.

Pramod Deo & Vijay M Deshpande

Pramod Deo is former chairman and Vijay M Deshpande is an energy economist and former principal advisor (economics), CERC