Inflated prices in power pacts suggest need for new bidding regime

Written by Noor Mohammad | Noor Mohammad | New Delhi | Updated: Nov 7 2013, 10:28am hrs
The winners curse or overpricing by bidders due to incomplete information has undermined a few public-private partnership projects in the highway and power sectors in recent months, leading to renegotiation of contract terms, despite that being dubbed a moral hazard. Such incidents are hardly going to be a thing of the past, going by a slew of power purchase agreements signed recently in Rajasthan, Uttar Pradesh and Tamil Nadu. In these cases, the developers have quoted prices as high as R5/unit to the distribution companies and yet won the contracts.

These exorbitant prices, apparently beyond the markets capacity to pay, are mainly due to the uncovered fuel risk in the existing Case 1 bidding provisions. The new prices discovered for long-term (up to 25 years) power supply are significantly higher than the price level of R3-3.50/unit quoted by developers in 2010.

A question mark is thus put on the way these PPP contracts are structured and bids made. The high bid prices underline the urgency of implementing the new Case 1 bidding norms notified by the power ministry under which the developer will be free to pass any additional fuel costs to the buyers in case of a shortfall in supplies from linked sources. An inter-ministerial panel has completed vetting of the new Case 1 norms and Union power minister Jyotiraditya Scindia is expected to approve them soon.

An analysis would make it clear that developers are quoting unrealistic prices for power. For example, price offers received by Rajasthan Rajya Vidyut Utpadan Nigam ( RRVUPN) for 1,000 MW power supply in a recent tendering are in the range of R4.52-7/unit. In seven out of the 10 bids received by the Rajasthan utility, prices quoted by the generators are more than R5.

The utility may end up tying up requisitioned power supply at the weighted average price of R5 a unit, double the price ruling in the spot market (electricity sale prices quoted by companies at the Indian Energy Exchange).

An FE study shows that RRVUPNs power purchase costs should ideally not exceed R4 a unit given that all the generating stations that have participated in bidding for power supply to the Rajasthan discom depend on domestic coal.

Bidders are required to quote power price along with transmission charges for delivering electricity to the discom. Power price is quoted in two parts, fixed charges and fuel costs. According to industry sources, fixed charges of new power plants should be in the range of Rs 1.50-2 a unit while costs of Coal India (CIL)-supplied coal could vary from Rs 0.80 to Rs 2 a unit, depending on the cost of transporting the fuel from mine to power plant.

Fuel costs for generating stations based on captive mines should be much lower at Rs 0.50-0.60 a unit. However, applicable transmission charges are normally in the range of Rs 0.20-0.30 a unit If transmission charges are on the high side for a power project, coal transportation costs have to be on the lower side. This is because plant are usually put up either near a coal mine or close to a power consumption centre.

The tariff discovered through the recent Case 1 bids appears to be quite high. Power companies have apparently factored in the future fuel and operating cost increases to avoid any losses in the long run. A few years back power producers were very aggressive in bidding and now they have reversed the approach, which is reflected in their bids, said Salil Garg, an analyst with India Ratings, a credit rating agency.

Former PTC India chairman TN Thakur explained why unrealistically high prices are quoted by developers: Bidders may be factoring into the tariff fuel uncertainty and payment delay risks into their offered price. Today no generating company wants less than Rs 4 a unit at its bus bar (the point where power is fed into the grid by a generating station) and thats how the landed tariff of nearly Rs 5 a unit is arrived at.

Kameswara Rao, leader, energy utilities and mining, PricewaterhouseCoopers, agreed with the assessments of Garg and Thakur. The increase in bid price is both on account of fuel and fixed costs; the latter tend to flare up due to project delays, said Rao, adding that bidding rates might marginally reduce in the near future on account of greater competition.

But former Central Electricity Regulatory Commission chairman Pramod Deo differed. Prices discovered under Case 1 (compared to Case 2) bidding are generally higher as they contain elements of transmission costs and are adjusted for transmission losses, Deo told FE. He added that in case of medium-term (one to seven years) Case 1 contracts, prices would be comparatively higher than long-term ones (7-25 years) because the technological risks are lower in the latter case.

Another reason for higher prices being quoted by developers is the fear that the plants could not be run at optimum capacities due to a shortfall in domestic coal. As per the contracts signed by CIL for fuel supply to power generators with a combined 78,000 MW capacity, scheduled for commissioning during April 2009-March 2015, it will supply only up to 65-75% of annual coal quantity from domestic sources during April2013-March 2015 and the balance fuel requirement will be met through imports. That means a developer will have assured supply of domestic coal to utilise only 49-58% of the generating capacity.

Under the existing Case 1 bidding guidelines, there is no provision for pass-through of additional fuel costs. Nor is there any mechanism for recovery of fixed charges for unutilised capacity in the event of fuel shortfall. That means any fuel shortfall will automatically lead to contract default by the supplier. In contrast, revised norms allow developers to pass on extra fuel costs to the buyer in case it has to use imported coal to meet domestic fuel shortfalls. If a discom declines to take costly power, the developer can sell the same in the open market. Apart from revenue from sale of diverted electricity, the developer will also be entitled to capacity charges for half of the unutilised capacity from the discom.

Under Case 2 bidding, the power-buying discom provides fuel (either coal linkage or captive mine) and the bidders responsibility is limited to developing and running the plant. While the Sasan and Tilaiya ultra mega power projects (UMPPs) were auctioned out as Case 1 projects, Mundra and Krishnapatnam UMPPs are examples of projects allocated through Case 2 bidding.

While the developer can import coal to meet domestic fuel shortfalls, discoms have been given the option not to buy costly power generated from imported coal. If the discoms exercise this option, developers will get fixed charges for only half of the unutilised generating capacity as per the Case 1 bidding norms. This also prompts the developers to quote higher prices. Ashok Khurana, director general, Association of Power Producers, recently wrote to Union power secretary PK Sinha, suggesting that discoms option not to buy imported coal-fired power be withdrawn.