Direct PPAs should be scaled up: Asia Clean Energy Partners

CEO INTERVIEW Direct PPAs should be scaled up: Asia Clean Energy

But doing so poses financial risks to the operator due to the longevity of contracts.

The lack of feed-in tariffs or regular competitive auctions serves as a barrier to the clean energy transition in the region, and this can be at least partially addressed through a direct power purchase agreement (PPA).

Asian Power spoke with Asia Clean Energy Partners’ Managing Partner Peter du Pont on how DPPAs are done and why these should be scaled up in Southeast Asia in response to the lack of open access to grid generators.

Du Pont has over 30 years of experience in sustainable energy and efficiency both in the US and Asia. He is Southeast Asia Regional Coordinator for the Private Financing Advisory Network and has previously served as Senior Climate Change Advisor for the US Agency for International Development in Asia.

In a May report, Asia Clean Energy Partners found that the AsiaPacific region is amongst the most challenging markets in the world for businesses seeking to shift to renewable energy. Is this still the case in the region and what are the remaining challenges for businesses switching to renewables?

Yes, there are continued barriers to the scale-up of renewable energy in Southeast Asia. It’s not easy to get renewable energy installed in a way that you can use it on-site and also sell it to the grid. You can install solar rooftops in most countries in Southeast Asia, but you cannot always sell the excess of the solar capacity onto the grid, and this creates a problem.

In Thailand, where there’s not a feed-in tariff in place for large commercial and industrial customers, there’s a huge market—the “behind-the-meter” market, where solar companies come in, and they install systems, with say 300 kilowatts (KW) or 500KW of solar panels on the rooftop, and they cannot export to the grid because regulations don’t allow that. They have to undersize the system, so the amount of electricity that they are producing, even at the peak time, will not be more than what they are using in the factory. If it’s more than the use of the factory, they have no place to put it, so you have sub-optimal systems. The fundamental problem is the lack of a feedin tariff or net-metering mechanism, which can allow facilities to sell electricity to the grid at a good price; and also the lack of open access to the grid for third-party solar project developers.

In Vietnam, the government is testing out something called a direct PPA, which could really unlock a lot of activity in the region. A direct PPA would allow a renewable energy developer to put in a small solar farm, sell it to the grid and wheel the power over the grid, and then somebody else could raise their hand and say, I want to buy that power. So that ability to enter into a contract with a producer of renewable energy, and to buy that power through the grid, having it wheeled through the grid, does not exist in most Southeast Asian markets. So you have a very closed market. And that’s a fundamental problem—the lack of open access to the grid for generators, and therefore consumers pay higher prices for electricity.

If they can’t feed into the grid, at what point would it be economic to store excess power in batteries?

Let’s say the average price that a factory in Thailand would pay for electricity is about four baht. That’s about 13 cents a KW-hour. There are many project developers who can go in and put a solar rooftop onto a factory. And there are thousands of megawatts (MW) of solar rooftop PV being installed across Thailand. They put solar PV

Peter du Pont, Managing Partner, Asia Clean Energy Partners

With the lack of open access to the grid for generators, consumers pay higher prices for electricity

on the rooftop of a factory, shopping centre, or building. The solar electricity that the owner of the factory or the store will buy from the solar company is about two baht, which is about eight US cents a KW-hour. Meanwhile, the factory owner is paying about 4 baht per KW-hour—which is about 13 US cents per KW-hour—to the electric utility. So a solar project developer is coming in to put on a solar rooftop and the electricity that this provides is about one-third cheaper than the electricity they are getting from the grid. That’s a great deal. Does it make sense to put a battery in? Generally, no. I am not aware of companies coming in and saying we’re going to make a bigger system and make it twice as big and put a battery in because the economics are not there for that.

One of the biggest problems in this whole dilemma is how the Thai utilities, PEA and MEA, can continue to pay for the upgrading and maintenance of the grid, whilst they are losing load from customers who are putting in solar rooftops. The best thing that could happen is, instead of putting a battery at the site, you can allow the export of power from the solar rooftop to the grid and use the grid as a battery. So if you have that excess power from your solar rooftop, then that just goes into the grid, a feed-in tariff, or net metering process. But the reason that the Thai utilities are not accepting power exports into the grid is that they have an oversupply in most regions of the country, and they do not have a way of being compensated by customers for the value of using the grid as a battery.

toward competitive procurements across the region, and this is a good thing because it brings down costs.

For rooftop solar, stores and factories need to get a fair rate. In some of the customer segments, Thailand is doing net billing for rooftop PV. For some customer segments, such as the small commercial, and residential, the utilities only pay customers about 2.1 baht (about 6-7 US cents) per unit when they buy electricity from rooftop solar systems. But the utilities charge customers about 4 baht (or 13 cents) per unit for electricity that the utility sells to them. So if you have your solar on your rooftop, and you’re selling it to them, you only get about half the rate for selling your electricity to the utility, compared to what the utility charges you for their electricity. That’s not a good deal. There needs to be a fairer deal for the solar rooftop customer.

The rate that utilities pay to solar rooftop owners needs to be increased to make economic sense. But at the same time, it is clear that the utilities should be able to charge a reasonable fee for the service of allowing solar rooftop owners to inject electricity into the grid, and essentially use it as a battery.

What we’re trying to do is just get renewable energy into the system by allowing for direct PPAs, which I described earlier. Wheeling of electricity is a common practice, and it is being implemented in other parts of the world, and it is an approach that can be tried and scaled up across the Southeast Asia region.

With regard to utility-scale solar, where companies are setting up solar farms, one of the biggest limiting factors to reducing the cost of production is the cost of capital. In Thailand, the typical cost of capital for renewable energy is in the range of 3% to 5%; in Vietnam and Indonesia, and the Philippines, it’s a bit higher, at 5% to 7%. If it costs you 6% or 7% to borrow the money, then it will make a big difference in a five-year or 10-year contract, compared to someone who gets the money at 3% or 4%.

What are the risks in implementing direct PPAs?

The fundamental risk of allowing direct PPAs and wheeling is the financial health of the utility that operates the grid. The problem that the utilities are facing is that many of the utilities operating the power systems have entered into long-term contracts to get stable power, and they are typically locked into the prices in these contracts for 10 years or more.

If the electricity regulator allows direct PPAs and wheeling, then you will have new generators coming in and selling power at rates significantly lower than the utility’s current tariff. When this happens, the off-takers, the utilities who have committed to these long-term contracts, have financial risks because they’ve already committed and they may not be able to enter into direct PPAs at lower rates. In my view, direct PPAs are a good tool, but they should be gradually phased in.

What is the current pricing of battery storage per MW-hour that you’re seeing in the market?

Actually, the fundamental challenge that utilities have is to meet demand at peak times over a relatively limited number of hours, typically hundreds of hours over the course of a year. We are increasingly seeing that it is cheaper to provide peak power using battery storage coupled with solar or wind energy, as opposed to having gas peaking plants. It’s quite likely now, definitely going forward, that battery storage and solar will be more cost-effective than peaking gas plants as a way of meeting peak demand in Thailand, and many other Southeast Asian countries. If solar and storage are not more cost-effective than peaking gas now, they will be in a year or two, and it will depend upon the specific use case, such as the size of the plants and the number of peak hours you’re trying to cover.

Developed countries have no business putting pressure on developing countries to go net-zero faster when they haven’t lived up to their commitments for financing

have installed more than 10,000MW of both utility-scale and rooftop solar over the past two years. Vietnam has a lot more solar rooftops than Thailand because there’s been a government policy with a feedin tariff for solar rooftops. Thailand’s market is almost exclusively behind the meter and it has taken off because the cost of solar is onethird less than the utility tariff. There are at least 100 or more really large companies that each have scores of megawatts of solar rooftop in their portfolios, in markets such as Indonesia, Malaysia, Thailand, and Vietnam. I expect that this activity will only increase.

Thailand’s solar rooftop market is very active because the economics are so good, but it’s very inefficient. The amount of solar rooftop is much smaller than it could be if you didn’t have undersized systems due to the lack of net metering. So you basically end up with having undersized systems on many factories when you could have many, properly sized systems if you had net metering. But this would put a big strain on the utilities. The markets, to the extent they’re active in other countries in the region, are mostly like this, behind the meter, and this greatly limits the amount of rooftop solar getting built.

What additional pressures will be put on Asian governments that are still reliant on coal, following the COP meeting in Glasgow? There seem to be a lot of caveats to the net-zero pledges and no new coal plant pledges.

Let’s separate net-zero for countries versus companies. We’re talking about developing countries in Southeast Asia, where the discussion around climate change is a very different discussion from that of developed countries. It’s really about equity between how developed and developing countries address climate change and how quickly countries move to reach a decarbonisation target.

For example, most of the climate targets that developing countries have set are highly conditional upon financing that was pledged by developing countries as part of the Paris Agreement. That’s supposed to be $100b a year by 2020 to help fund decarbonisation. If you look at the climate targets or the nationally determined contributions or NDCs, they have two targets. One is the target for what they will achieve with their own resources, and this is typically a smaller number. The other target is the amount that countries will achieve if they have international climate finance support, and this target will be many times higher.

I think developed countries have no business putting pressure on developing countries to go to net-zero faster when they haven’t lived up to their commitments for financing. Where’s the $100b, right? You have to take care of that first.

Furthermore, the discussion should not be about net-zero, it should be about net-zero with development, which we call ‘Beyond Net-zero’. How do you meet the development needs of countries such as the Philippines, Thailand, Vietnam, Cambodia, Laos, Myanmar? How do you get people out of poverty, create good-paying jobs, and meet development objectives, including the UN Sustainable Development Goals? I think the discussion around net-zero should be focused on how we can do net-zero for Thailand, Indonesia, and all of these other countries in a way that meets their development objectives first and foremost.

INTERVIEW India is aggressive in privatising discoms

Most public discoms are on the verge of bankruptcy because of high AT&C losses and political populism.

In India, most public distribution companies (discoms) are facing bankruptcy due to aggregate technical and commercial (AT&C) losses, but these are expected to decline as the government moves to privatise distribution and enable discoms to collect revenues better.

NITI Aayog, a state-owned policy think tank, reported in August 2021 that the discoms’ total loss is estimated to be ₹90,000 crores (US$12.1b approximately) and the accumulated overdue payment stood at ₹67,917 crores (US$9.13b), as of March 2021. Moreover, according to the Ministry of Power in August, the AT&C losses fell to 21.83% in 2019-2020 from 23.5% in 2016-2017.

Arthur D. Little’s Managing Partner Barnik Maitra discussed with Asian Power the state of India’s power sector. He also touched on the topic of discoms’ privatisation and shed light as to why the country is prioritising it.

Can you give a brief overview of where India is now in terms of its renewable targets? How is it faring compared to other countries?

Most markets, like Indonesia, the Philippines, China, and Vietnam, are very coal-dependent. The challenge has been how to increase the share of renewable energy (RE) without shutting down coal plants because all of these are dynamic growing markets. The strategy adopted by most countries, India, in particular, is to not add more coal capacity unless it’s completely needed or critical. The post-COVID economic recovery in India has been much faster than anticipated, yet mining productivity and the coal supply chain has not kept pace. Again, things like these just emphasise the need to move away from it. Amongst a lot of countries, India has done quite well. They’ve set reasonably aggressive targets. I think they’re currently at an installed capacity of RE of over 100 gigawatts (GW), which they’re planning to quadruple to 450GW by 2030.

The approach that India has taken is two-fold. One is there are very reasonably attractive subsidy mechanisms put in the earlier phase and now they’ve also completely relaxed foreign direct investment (FDI) norms to push RE. It’s a calibrated, slow journey but you have to realise that in emerging markets, it’s very difficult for you to do a dramatic shift; but India’s adding the capacity. India is able to deliver because of the subsidy mechanism, the FDI mechanism. A couple of Indian conglomerates, like Adani Energy, have also made big bets on RE. Tata Power is the largest private utility player that made a big bet on renewables. Tata Power had set a 2025 goal of having 35% of its generation capacity from renewables. I think they’re already at 32% of generation capacity from clean energy sources, which is a noteworthy mix. Adani recently picked up all of SoftBank’s RE portfolio.

I don’t think we will get to a place where coal will completely be phased out. But fast forward to 10 years from now, you should be able to see at least 35-40% renewable in markets like India. The last mega coal-fired project in India was commissioned or was announced in 2010. Since then, there have been no big projects announced. These are the measures that governments are taking. Will this be enough? Probably not. But again, it’s a good start and good progress in a country like India.

How viable are the targets of India in reducing emissions?

Six to seven years back when the push towards solar started, the total cost of production was around ₹8 to ₹10 a unit per kilowatthour, compared to coal, which is around ₹3. Now, if you’re going to also store it, because what this does not include is the battery costs and often that becomes 50% to 60% more when it started seven to eight years back, there was a five, six times delta between the two sources. Now because of technology and innovation, what was ₹8 to ₹9 is already down to ₹3 and the battery’s also down from ₹7 or ₹8 to another ₹3; So, if you look at the cost curve, it is not below coal, but it is at least on a comparable basis and getting more competitive as storage costs improve.

In distributional markets in India, the industry and the commercial segments cross-subsidise the agriculture and residential segments, which means industrial users and commercial users pay ₹8 to ₹9 per unit of power. If you supply power to them at ₹6 to ₹7, you are actually not losing money, making the business case in itself viable.

The government is also now pushing incentives to encourage home users to do rooftop solar. With the capital subsidy, the cost numbers look very different. The nature of the power grid itself is shifting, but if you fast forward 10 years from now, rooftop solar becomes more important because all utilities are going to move to micro-distribution or microgrid models. There are already pilots beginning on how to do microgrids, generate closer to demand and not generate centrally and transmit long distances. As we move towards microgrids, I think you will have rooftop solar becoming an integral part of grids and India has put subsidy mechanisms in place to encourage installations. The government has now realised that the nearly bankrupt public distribution, cannot be made financially viable. They have actually realised it’s better to gradually privatise distribution than recapitalise public distribution companies.

Barnik Maitra, Managing Partner, Arthur D. Little

Most markets are very coaldependent. The challenge is how to increase the share of renewable energy without shutting down coal plants

Why are they bankrupt?

One is obviously the classic AT&C losses, which are very high because of theft. Most markets are operating above 20%; whereas the benchmark is 6% to 7%. Reason number two is political populism. In a lot of states, agricultural power is free and residential power is subsidised extensively. In a few states, in the residential sectors, the first 100 units are given free. So there is a lot of adventurism on behalf of local politicians who actually announced free power with the public discoms left to collect the tab. The problem of inadequate collections and high AT&C has driven these discoms to the verge of bankruptcy.

I think that the government, a couple of years back, pumped in several billion dollars into the public distribution sector, all of which has disappeared because collections and AT&C losses were not addressed, and they are again bankrupt or on the verge of bankruptcy.

What value do you think could be unleashed in privatisations?

If you look at the performance of a private sector distribution, the AT&C losses can get to as low as 6%, whether currently operating at over 20%. If the government wants you to subsidise power, they pay you the subsidy and you don’t bet on a customer’s behalf. That model is proven. You will not lose money if your power mix is 50% renewable and 50% coal because you will be able to realise tariffs, which are ₹4 to ₹5 from the residential segment minimum and ₹8 to ₹10 from the commercial sector. If you look at Tata Power’s strategy, they’re already ahead on the generation piece where they’ll get to probably 40-50% renewable mix in 2025 or 2026. And as a private distribution company, as they reduce AT&C losses to 6%, even distribution becomes financially viable.

Then there’s another big movement, which involves smart meters. A lot of electricity losses are not really theft but driven by archaic manual measurement practices. The New Electricity Bill, which is going to get passed in India soon, actually mandates the compulsory installation of smart meters in every single household.

So what will happen is that by 2027-2028, 80% or 90% of Indian households and commercial establishments will have a smart meter. This will help distribution companies collect more. How? Say, you’re a resident with a shop in your garage and you are running heavy electricity guzzling equipment like multiple A/Cs, refrigeration equipment and you need to be rated at 10 Ampere and not 5 Ampere. Automatically there are some implied tariff losses that happen because customers are fundamentally not really rated as for the usage and smart meters will plug this by providing accurate consumption and load data to the discom. Not only will smart meters plug AT&C losses, but these revenue losses also.

For the plants coming to the end-of-life cycle, the government is considering creating disincentives for renewals

Do you have any idea how much the market will be for smart metering in India once this new law comes through and if there is full privatisation of the distribution networks?

I don’t think the government is going to pay $5b needed for installing

By 20272028, 80-90% of Indian households and commercial establishments will have a smart meter

smart meters. I think the government will give it for free in a way to the consumers with the discoms bearing the initial deployment cost and the discoms, in turn, recovering it from end customers gradually. Remember, these are all debt-laden public discoms that have no financial viability today to roll out smart meters at scale. I think the market for smart meters in India is going to come up to 250 million smart meters in the next 10 years. investors are looking to create smart meters manufacturing facilities because they see this $5b opportunity and they say, listen, even if we get a 20% share, that’s like 50 million smart meters. That’s the other step. Coming back to the fundamental shift, the moment privatisation happens, everybody can collect better. With the push for privatisation, better capitalised private discoms will only accelerate smart meter deployment. With at-scale, smart meter deployment discoms will have higher collection efficiencies and better AT&C losses. This in turn will also indirectly fund a greater renewable energy mix in the end-customer consumption portfolio. So, in a way, privatisation of discoms and smart meter adoption can become interesting catalysts for India’s push towards more clean energy adoption.

Do you think there’ll be no more large power plants built in India? Or do you think the existing ones coming to the end of their life will be renewed with another plant?

There will be no new mega coal-powered greenfield projects because there are no incentives for them. For the plants, which are coming to the end-of-life cycle, I think the government is considering creating some disincentives for those power plants to be renewed or incremental capital to be put in because the strategy has been all-new demand serviced by green energy. As plants come up for renewal, we should be able to shut most of them down. Now, whether everyone will do it or not, is another question. But if you look at major private generation companies, I think most of their plants will come end-of-life in another five to 10 years.

Some of the coal-fired plants may get renewed, but the economics of that will be different from the original economics. Remember initially when these plants got set up, the reason why coal is at ₹2 a kilowatt-hour is that they were built on very attractive capital subsidies. If you look at the big Tata Mundra, it’s an ultra megawatt power plant of 4,000MW. It was commissioned in 2012. The original bid tariff was ₹2.26 per unit and the unit needed government support with future offtakes negotiated at ₹4 to 5. Now, the government is clear that there’s no capital subsidy for coalfired plants. So six years from now, there is a very possible scenario in which as you’re renewing a plant like this, the ₹2 suddenly begins to look like ₹4 to 4.5 (as happened with Mundra), because there’s no government subsidy, no capital subsidy, and no tax subsidy. And the solar power may be close to ₹4 to 7, I think at that point in time, every single such plant will getting renewed will be an unlikely outcome.