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Dr. Pramod Deo, Chairperson and Chief Executive, Central Electricity Regulatory Commission

13 Dec 2010

Dr. Deo is the longest serving electricity regulator in India and took over as Chairperson of the Central Electricity Regulatory Commission on June 9, 2008. He has earlier been associated with MERC as Member before being elevated as the Chairman on February 11, 2005. He has also co-authored three books on energy planning, energy management and regulatory practice. InfralineEnergy's Chhavi Tyagi spoke to him on various issues concerning the Indian electricity regulatory scenario.

Edited Excerpts

How would you evaluate the performance of the power sector during the on-ongoing 11th Plan?

As far as the capacity addition is concerned, it is strictly not an area which the commission monitors. However, an important aspect which got highlighted in this Plan is the increasing reliance on private sector contribution. During the last year, the country added an additional capacity of 10,000 MW, which is called `breaking that Hindu rate of growth', out of which 45 percent was the contribution of the private sector. This year, nearly 50 percent capacity addition is expected by the private sector and this trend seems to be on an upward tilt helped by the entry of a number of new private players.

Another important factor which will provide a strong impetus to the private sector participation will be the introduction of competitive bidding for public sector from January 1, 2011. It would bring private players on a level playing field, except for a few exceptions in cases of peaking power and hydro industry. However, the public sector entities have a lot of work on hand, for instance, NTPC had already gone and contracted a lot of capacity through PPAs, with the result that they will continue to have that cost plus regime. Also, Power Grid has transmission lines, since we have allowed them to build corridors for evacuation for power so they will still be continuing in the cost plus return regime for quite some time to come. This means that any new PPA signed will only happen through competitive bidding but whatever the utilities have signed before January 1, 2011 is covered under the cost plus return regime.

Many experts believe that the state electricity regulatory commissions have failed in their most important job of fixing the power tariff. The commercial loss without subsidy stands at Rs 50,585 crore in 2008-09. In your opinion what could be the best possible way to move towards tariff rationalisation and what role can CERC play in it?

CERC does not play any role when it comes to the distribution business. However, since I also wear the hat of the chairperson of Forum of Regulators (FoR), I would reply to this question in that capacity. In the FoR, all the chairpersons of the state regulatory boards are members and we try to evolve a consensus, and work towards harmonisation of regulations. So, we have been working towards tariff realisation, but I cannot really talk for all the State Electricity Regulatory Commissions (SERCs) as to what is happening. Though, the 13th Finance Commission Report itself is very clear on this issue. The issue, which these SERCs face, is that they don't know what the losses are, how much is consumed by critical segments like agriculture? In such a scenario, it becomes very difficult to come out with a certain trajectory and formulation of loss reduction to provide to the discoms.

On the other hand, discoms can also play around with that number because they can always claim that they have achieved the number. To this problem, there is no easy solution and many a times, you find that the annual revenue requirement of the discoms has been met but it has only been met on paper, they really don't have money. On top of that, there may not be any tariff revision or very marginal tariff revision. So that's where R-APDRP comes in. Since, we cannot measure electricity consumption by agriculture without installing meters, let's measure what we can. R-APDRP suggests covering all the urban areas and having a consumer indexing on the distribution transformers where there will be automatic meter reading. This will help us in knowing exactly how much electricity is being consumed in the urban areas, which means that the remaining electricity obviously goes into the rural areas and then, basically, the agriculture consumption would be known. Or, the states where they have gone for separate agriculture feeders to quantify the electricity consumed by the agriculture.

"The issue, which these SERCs face, is that they don't know what the losses are, how much is consumed by critical segments like agriculture? In such a scenario, it becomes very difficult to come out with a certain trajectory and formulation of loss reduction to provide to the discoms. On the other hand, discoms can also play around with that number because they can always claim that they have achieved the number. To this problem, there is no easy solution."

Another problem is that you also don't want the tariff to increase, with the result that the numbers can again be juggled. On top of that, if you don't give much tariff increase, it is disastrous for the distribution companies.

Do the regulators have any plan to change the cost plus regime for transmission companies, mainly for the PGCIL?

We have already changed that. After competitive bidding comes into effect from January 1, 2011, PGCIL will also have to go through the competitive bidding route. However, as I said earlier, utilities like PGCIL have enough work on hand to not feel the pinch immediately. With the kind of contracted capacity these utilities have, they will have enough time and work on their hands for a smooth transition. Though, they will have to change their systems in order to give a better competition to the private players. However, the real issue for someone like NTPC would be availability for fuel so they will have to figure out how to do it. Case-II projects would not have many problems as fuel availability has been facilitated by the government. Otherwise, it will become very difficult to even bid Case-I. There is a huge requirement of capacity addition in transmission and PGCIL cannot do it on its own. Thus, private sector has to come and play a far more important role. Now, PGCIL as the central transmission utility has a responsibility to plan transmission network but that doesn't mean that they are going to execute all that. You also have to identify the projects where you will invite private sector to participate.

We now have an empowered committee for identifying projects for competitive bidding, which is headed by one of our members. This committee does not go into competitive bidding, but only identifies the projects. They have already identified three projects. Private sector will come as a licensee and on the basis of tender. So from January 1, 2011, PGCIL or any private company will all have to compete to get any project. While PGCIL will identify new projects, it would not mean that it would be PGCIL's project.

As for tariff regulation, we have tried to bring in some of the efficiency parameters and we will also be coming out with performance standards. These performance standards are like performance standards for distribution companies, failing which they can be penalised. Standards would be set for PGCIL and not only PGCIL, but for any interstate transmission licensee. So, if your performance falls below the prescribed level, you can't get away with that.

Recently regulators have come up with new transmission pricing regulations. How is this going to bring economic efficiency to stakeholders of the industry?
The physical flow of electricity is such that it goes from high pressure to low pressure, so the new transmission pricing is based on this concept. However, the system cannot be completely switched over overnight. So, the initial year will see a hybrid system before we completely change the pricing system. Also, the tariff policy clearly states that it has to be sensitive to distance and direction so that element has also been captured. Thus, it is based on the load flow studies. Another important responsibility is to collect this money, which would be the responsibility of the central transmission utility; otherwise the licensee will find it very difficult. Therefore, it's a very big exercise which will also promote investment but it will take time for all the players to understand the process fully. That's why we are conducting seminars, workshops and adequate time is being given for the transition.
Lanco Amarkantak TPS was infusing power into the grid without an approved open access agreement for a period of 10 months. We feel that UMPPs (particularly, SASAN and TILLAYA) would pace up their execution, arrive at an earlier COD and may infuse power through UI or merchant basis. What would be CERC's reaction if such a thing happens?
We are taking care of the issue. We have issued notice and the matter is now being heard, which is why I cannot comment on that. There was some part which did not have any regulation, a sort of a no man's land. It has all been taken care of now, when it came to our notice we amended our grid code. SASAN and TILLAYA cannot do that now because we have taken care of the problem.
Would the UMPPs be allowed to compete in short term market if they achieve an earlier COD?
It depends on the kind of PPA that they have entered and we'll have to see the fine print in the PPA. If the PPA specifies a date for the commencement of the supply of electricity then that's fine, which means that if they don't have to supply before a given date, then it becomes a merchant power plant. However, there is a big difference between this and Lanco's game plan. Lanco was infusing power in UI, you cannot do that. It all depends on what the PPA specifies.
Against the discoms' increased participation in short term market, state regulators are planning to seal the quantum and price of their monthly short term procurement. Wouldn't this restrict the growth of short term market?

When it comes to short term market, regulators ask the utilities as to the amount of electricity they are planning to supply in the year to come and from which source. Also, the regulator asks a short term market as to the amount of electricity planning to be bought. Since you cannot have any price cap in the short term market, it is very legitimate for a regulator to ask the amount of the short term power planning to be bought because there is a responsibility to supply the power. There are standards of performance and therefore, within those boundary conditions, the amount of power purchased has to be decided.

"All over the world, you have long term contracts; nobody is going to switch over entirely to the short term market. After all, anyone who sets up a power plant, which is very capital intensive, cannot be doing it. It's a gamble. Right now because of the shortages, it seems very attractive but I don't think that today any investor is putting any money thinking that I will be able to sell at this rate for all time to come."

Now, most of the states in India are short of power and it is obvious that there is going to be some load shedding there. This load shedding also gets approved by the regulator because there is no way that these states can meet the entire demand. For instance, agriculture is never supplied electricity for 24 hours; it is supplied only for 6-7 hours by rotation. Another factor is that load shedding does not happen throughout the year as the shortages are not for 12 months but in certain seasons. These all are part of the tariff petition which is provided. The regulator has to look at all these aspects when it comes to buying from short term market. It does not mean that you can purchase as much power as you want from short term market. First of all, the utilities will not have that much money and even if they do, you have to consider as to how much power is actually required. The job of a state regulator is very difficult.

The quantum of electricity traded in the short term market is increasing at a fast pace. During September 2010, 11 percent of the total electricity generated was transacted in short term market. Could it be expected that by FY 2025, 70 percent of the total electricity generated would be transacted through the exchange (not necessarily of short term in nature)?
All over the world, you have long term contracts; nobody is going to switch over entirely to this kind of market. The tariff policy says that 15 percent of the new capacity should be in the short term market. So, if you take the best capacity plus the 15 percent, still the volume of the short term contracts has not reached 15 percent. After all, anyone who sets up a power plant, which is very capital intensive, cannot be doing it. It's a gamble. Right now because of the shortages, it seems very attractive but I don't think that today any investor is putting any money thinking that I will be able to sell at this rate for all time to come. It's a different matter that in a few years, he may make a real killing. So, you are going to have long term contracts but then you may have a medium term as well as short term.
Any plans for long term contracts being transacted through exchanges?
Long term contracts are bi-lateral contracts so obviously you don't have to go to the exchange and do that. However, you can have capacity contracts in future which could be traded in exchange.
The latest UI pricing was expected to bring more discipline in the grid. However, the utilities have now have resorted to load shedding instead of long term power planning. Also, the purchase from traders and exchanges have not picked up in trade off of load shedding. What are your views on it?
They are not facing the elections (laughs). On a serious note, there are regulations governing this too. The discoms are subject to standards of performance. Now, the standards of performance do not mean that you will stop supplying the electricity. Also, when they come with a tariff petition, they have to also tell the regulator as to the hours they are going to supply the electricity. So, we have provided the mechanisms to control and regulate this, but again when it comes to enforcement, you will have to ask the state regulators.
CERC introduced a price charge cap of Rs 8 per unit for 45 days when the market prices were at a peak. Do you see any such intervention in future if prices scale to a new peak?

We debated the issue and decided that we do have the authority to take such a step. We tried it for 45 days and the reason was that three states, Maharashtra, Haryana and Arunachal Pradesh were going to polls at that time. Based on past experience during the Lok Sabha elections, we put a price cap of Rs. 8. The rationale behind putting the cap at Rs 8 was that we did not want NTPC's plant running on naphtha to shut down. It is not possible to put a price cap on the basis of fuel used because the source of the power supplied to the power exchanges is not known. However, the way the investments are taking place in the generation sector today, our view is that we do not want to give any wrong signal by putting a price cap.

"If there is a situation where we feel that the market is going completely berserk maybe we will have to putting a price charge cap. There the matter rests. But, it is something like the last resort. Right now, we don't want to do this."

Also, another difficulty for the regulator is to identify the basis on which the price cap can be applied. As said earlier, the regulator cannot put it on the basis of fuel used. However, if there is a situation where we feel that the market is going completely berserk maybe we will have to resort to that. There the matter rests. But, it is something like the last resort. Right now, we don't want to do this.

What are your views on merchant power plants by PSUs like NTPC, NHPC? The question becomes critical in the light of the prospect of mandatory competitive bidding from 2011 for public sector players.

These are the government owned companies and it is really for the government to decide as to what they should be allowed to do. The question comes in when we decide the tariff. We decide the tariff based on certain norms, which are cost plus norms. We do not control the profit they are earning as a company, what we do control is the regulatory business. However, when it comes to the merchant power plant, it is the market which decides. As for these PSUs, the central government will have to take a decision on that.

However, a more serious matter, on which we have given advice to the government, is the percentage of the power provided to the state. The question that comes in this case is when the state governments get this power, what do they do with it? Since it is not the state distribution companies which get this power but it's the state government, they enter into contracts with the traders and because of the Supreme Court's judgment it is treated as intrastate. While we have placed margins on traders for interstate, we have no control on intrastate. And, if there are no intrastate margins, these states can also make windfall profit. Besides, those states which do not have requirement for this electricity, they sell it in the market. This is a serious matter which has the tendency to distort the market, and not just short term but it can also distort the medium term market.

The question is that if you are getting this free power, can you sell it at any rate? Since, we do not have any control on that, we have advised the government and it is up to them to decide.

When are the regulators planning to introduce financially settled electricity derivative contracts, ancillary service contracts and capacity contracts in the short term market? What are the pre-requisite market conditions for introducing such contracts? Among FMC and CERC, which one of them is likely to regulate the electricity derivate contracts?
As far as ancillary service contracts are concerned, we had a public hearing on that. We were also thinking of entering the evening market so all those things would be coming out with some order. As far as the derivative contracts are concerned, we are of the firm view it is not the time for it as the depth of short term market is low. Given the shortage situation, it can be very speculative and even a slight 100-200 MW can distort the market. Our views are certain on that, so the derivate market will have to wait till we get away from this shortage situation. For FMC and CERC, the case has been heard by High Court in Mumbai and it is reserved for judgment so we will have to wait for the judgment on that issue.
Can user-associations of SEZ (Special Economic Zones) or an Industrial Park directly participate in trading and procure power?

There is a difference. The rural areas, which have been declared as the rural areas by the state governments in consultations with the state regulatory commissions, can be exempted from regulatory purview for procuring and selling power. SEZs or Industrial Parks do not fall in that category. You could have the franchise arrangement but the franchise arrangement doesn't mean that you will not be regulated because after all the franchises are only a contractor for the distribution company.

However, the real issue is different. For SEZ, there is no network of the distribution company today; it's like a parallel network if it has been built. In theory, technically a discom is supposed to supply to anyone and if there is no network, this is also the responsibility of a discom. However, when a discom's network exists and the network has been built by SEZ itself, then SEZ's network is like a parallel network.

(InfralineEnergy thanks Dr. Pramod Deo, Chairperson and Chief Executive, Central Electricity Regulatory Commission for sharing his valuable insights with our readers. The column 'In Conversation', is a platform to engage experts from various sectors to share their views on the different transformations in the Indian energy sector)