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The Maharashtra electricity regulator has made several market-friendly amendments to its open access (OA) and net metering regulations. Unlike in the past, OA consumers shall now be eligible for net metering connectivity for their rooftop solar installations and vice-versa. The OA regulation has been largely aligned with the Green Open Access Rules – reduction in minimum contract demand to 100 kW, monthly banking of power, REC issuance for unutilised power and 100% AS waiver. Additionally, there is no cap on quantum of banked power and standby charges, equivalent to about INR 0.20/ kWh, have been completely waived. All possible connectivity options including net metering, group net metering, net billing, gross metering and behind-the-meter are permitted for rooftop solar systems up to contract demand without any size caps. The only exception is an absolute cap of 5 MW, much more generous than in other states, for net metered systems. Existing behind-the-meter systems would be allowed to convert to net metering. Rooftop solar systems would also benefit from a relaxation on imposition of grid support charges, which would be waived completely until total installed capacity in the state reaches 5 GW, revised upwards from 2 MW (current installed capacity – 1,716 MW). There is even a penalty of INR 500/ day on the DISCOMs in case of delays in grid connectivity.

The main negative change relates to retention of green attributes associated with net metered, net billing and behind-the-meter systems by the DISCOMs, unless the consumer is an obligated entity. Also, unlike in the Green Open Access Rules, there is no cap on cross-subsidy surcharge.

The catalyst for these changes, in a state historically resistant to the growth of private markets, seems pressure from MNRE, which has been urging states to implement its directives on the Green Open Access Rules and RPOs. The new distributed RPO target of 4.5% by FY 2030 is a definite trigger. Unfortunately, the biggest OA pain point in the state remains unaddressed – an arbitrary limit of 1.4x contract demand as specified in the grid code – a big constraint for users seeking to push RE adoption beyond about 40-50%. The regulator has refused to heed to market concerns on this crucial issue.

Notwithstanding retention of green attributes from distributed systems by the DISCOMs, rooftop solar is a big winner. Consumers should find free net metering up to 5 MW, with cost saving potential of 50-70%, still highly attractive. Allowing consumers to avail both OA and net metering options, and conversion of behind-the-meter systems to net metering are extremely positive for the market.

The regulator’s focus now should be on effective implementation of the new regulations. It has disregarded most operational concerns of the MSEDCL about inadequacy of distribution and billing infrastructure. But if MSEDCL uses ad-hoc measures like denial of approvals and levy of extra charges, as seen in the past, the reforms may not amount to much.

Figure: Total corporate power consumption and direct renewable penetration, FY 2022

Source: BRIDGE TO INDIA research

As this figure shows, Maharashtra’s historically negative policy stance has impeded growth of the corporate renewable market with one of the lowest penetration rates in the country. The state enjoys huge growth potential due to its large market size, high grid tariffs and abundant solar and wind resources. A more conducive regulatory environment is needed to unleash this potential.

The Ministry of Power has again revised Renewable Purchase Obligation (RPO) trajectory for FY 2025-30. Total target of 43.3% by FY 2030 remains intact but sub-targets for wind and hydro power have been reduced sharply from 6.9% and 2.8% to 3.5% and 1.3% respectively. The gap has been filled by a new sub-target of 4.5% for distributed renewable power, to be met by power procured from rooftop solar and other projects with capacity less than 10 MW each. Residual target for other technologies including solar, bio-mass, small hydro, older wind and large hydro projects remains largely unchanged. The technology specific sub-targets shall henceforth not be applicable to obligated corporate consumers, who shall be required to meet only the aggregated target. The revised targets shall take effect from FY 2025 onwards. The government has also brought RPO trajectory under the ambit of the Energy Conservation Act from Tariff Policy 2016 to give it statutory status and make it binding on all respective parties. 

Figure: Revised RPO trajectory 

Source: Ministry of PowerNote: Wind and hydro RPO targets can be met only by power procured from respective projects commissioned after March 2024. Hydro target includes small hydro and power output from pumped storage projects irrespective of input power source. Combined target for solar, bio-mass, small hydro, older wind and large hydro projects is almost unchanged – rising from 24.8% in FY 2024 to 34.0% in FY 2030.

The new trajectory, coming on top of previous changes in July 2022 and October 2022, does not seem well thought out and raises some key questions.

Why such a drastic reduction in wind and hydro RPOs?The nearly 50% reduction in wind and hydro RPO targets is hard to explain. According to the initial trajectory, approximately 70 GW and 24 GW of new wind and hydro capacity was expected to be built by FY 2030. These figures have now been adjusted to 35 GW and 11 GW, significantly lower than CEA’s recently announced National Electricity Plan. The reduction is not only an acknowledgement of severe challenges facing both sectors but also seems inconsistent with huge (and unchanged) solar capacity target.

How to implement distributed RPO?The new sub-target for distributed power – implying total installed capacity of about 75 GW by FY 2030 – is laudable but difficult to implement. It is technology agnostic but is intended mainly to boost rooftop solar and agri solar markets. Because of difficulties in collating power generation data from such projects, the government has proposed that the DISCOMs may use an annual power output benchmark of 1,278 kWh/ kW capacity. However, this proposal creates a serious risk of double-counting of green attributes between the DISCOMs and project owners. If the DISCOMs impose restrictions on green attribute claims by project owners, as happens in many states currently for net metered systems, the proposal would be self-defeating.

What happened to storage RPO?In July 2022, the government had introduced a separate storage purchase obligation (ESO) of 4.0% on top of the total 43.3% RPO target. There is no mention of the ESO target in the last two revisions, which suggests that it may have been dropped altogether, a setback for the still fledgling sector. RPO is an important overarching policy setting overall direction for the sector and sending appropriate signals to various demand and supply actors. But lack of rigour, over-detailing and arbitrary tinkering are creating confusion in the sector and undermining sanctity of this process. Many states have belatedly started accepting the older recommendations and will now need to reconsider their plans. We also continue to believe that creating a uniform technology-specific RPO trajectory across all states is not desirable because of major differences in availability of natural resources across the country.

The Ministry of Power has amended Electricity Rules, 2002 to harmonise power tariff across a pool of ISTS-connected renewable projects in central government tenders. The government is planning to create separate pools for different project types including solar, wind, solar-wind hybrid, hydro, RTC, peak power and firm power. A weighted average tariff shall be determined for total power output from each pool using tariffs of individual projects. Projects will be added to each pool over a period of five years as more auctions get completed, after which the pool will be frozen and a new pool created for future auctions. DISCOMs will need to specify the quantum of power they want to buy from one of the relevant pools – in turn, they will need to commit to pay weighted average tariff of that pool over remaining PPA life of respective projects. The Grid Controller of India shall be responsible for maintaining pool data and updating tariffs from time to time.

The pooling mechanism means that the DISCOMs – instead of buying power from pre-identified projects at a fixed tariff known upfront – will now buy power from an unspecified projects at a tariff that will change with every successive auction until the five-year window is completed. It is designed to ensure that the DISCOMs do not cherry pick projects with low tariffs. There is conclusive evidence to show that every time tariffs go up because of, say, increase in equipment costs, taxes and/ or interest rates or even changes in tender conditions, the government struggles to find buyers. When tariffs go up, the DISCOMs choose to walk away – resulting in cancellation of auctions – and wait for the cycle to turn, slowing execution progress in the sector. The change is positive for the developers as it diversifies their offtake risk and significantly reduces risk of tariff renegotiation and project cancellation. However, it is (almost) a zero sum game and exposes DISCOMs to tariff variability risk (see figure below).

Figure: SECI ISTS solar and wind auctions in last 5 years, INR/ kWh

Source: BRIDGE TO INDIA researchNote: Weighted average tariff is revised over time as more auctions are completed in the five year period.

SECI solar and wind auction tariffs have ranged between INR 2.00-2.71/ kWh and INR 2.69-3.22/ kWh respectively in the last five years. Early procurers will be concerned that they run the risk of bearing higher costs if tariffs go up later (as happened in wind sector in 2022-23). Late procurers will not be interested if the tariffs were higher in the earlier years (as in the solar sector in 2018-19).

We believe that the DISCOMs will not be keen on the pooling mechanism. While they get an advantage of bulk power procurement from central government tenders at relatively attractive tariffs in comparison to state tenders, particularly for states with poorly rated DISCOMs, they hate that they have little control over these procurements. Projects often get delayed and/ or cancelled upsetting their procurement plans and RPO performance. DISCOMs also have no control over change-in-law and other legal matters exposing them to additional risks in central government tenders. The pooling mechanism seems to be a non-starter especially for hybrid technologies due to high volatility in tender conditions and resulting tariffs. Pooled mechanisms are created successfully in other parts of the power sector – most notably, in transmission. DISCOMs are obligated to pay pooled transmission system costs across the entire national grid. They also need to often buy power on the exchanges at market rates. But the net impact of these variations is relatively small. And change is always difficult to bring. Unless the government revises the pooling mechanism, the DISCOMs would prefer to issue their own tenders as seen with greater frequency of late.

MNRE has announced the widely awaited green hydrogen standard for India. The standard –covering only green hydrogen production stage and excluding all pre and post-production emissions – has been set at an average of 2 kg CO2e/ kg over 12 months. No standards have been defined for derivative products like green ammonia and methanol. The Bureau of Energy Efficiency (BEE) shall provide accreditation to agencies undertaking monitoring, verification and certification of green hydrogen projects. A detailed methodology for the same is expected to be issued shortly.

In contrast, the European Union (EU) has set a much more onerous standard at about 3.4 kg CO2e/ kg covering entire lifecycle from power generation to end-use (scope 1, 2 and partial 3 emissions). The EU has also set strict requirements for additionality, geographical and temporal correlation of associated renewable power output. Renewable power projects must be commissioned not more than 36 months before respective hydrogen plants, located in the same power market and produce power matching with consumption profile on an hourly basis (monthly basis until 2029). Strict temporal matching of power output would have serious implications on production cost because of expensive power storage and/ or lower capacity utilisation of electrolysers.

Notably, the EU has not classified biomass-based hydrogen as green hydrogen because of its carbon emission intensive process requiring carbon capture.

The US hydrogen mandate extends beyond ‘green hydrogen’ to other forms of hydrogen, for example, blue hydrogen using fossil fuels coupled with carbon capture. The emission threshold has been set at 4 kg CO2e for well-to-gate processes including water treatment, electrolysis, gas purification, drying and compression (scope 1 and 2). Hydrogen output will receive incentives under the Inflation Reduction Act based on emission levels – full tax credit of USD 0.60/ kg for emissions less than 0.45 kg CO2e (with the possibility of a fivefold increase if labour and wage standards are met), 33% tax credit for emissions between 0.45-1.5 kg CO2e, 25% tax credit for emissions between 1.5-2.5 kg CO2e and 20% tax credit for emissions between 2.5-4.0 kg CO2e. However, the US is now mulling stricter rules with requirement for additionality likely to be added as a qualifier.

Over in the UK and Japan, the emission standard has been set at 2.4 kg CO2e and 3.4 kg CO2e respectively for well-to-gate processes (scope 1 and 2). Japan has also set a separate threshold for green ammonia production emissions at 0.84 kg CO2e.

Figure: Green hydrogen standards across the world

Source: BEE, EPRS, US DOE, BRIDGE TO INDIA research

The huge divergence in international standards is confusing but understandable given the nascent nature of the market. It is fair to believe that the standards would get streamlined over time. The EU, expected to be the largest importer and an early user of green hydrogen, may set the tone with other countries converging behind its strict standards. Evolving standards are expected to be a major challenge for hydrogen producers around the globe.

India’s relatively loose standards are not consistent with its aspiration to become a global hydrogen hub. There is also the important issue of mismatch on use of banked power, permitted in India but not in the EU.

The Ministry of Power has issued a framework for promoting energy storage to support integration of variable renewable power capacity. The framework mostly seeks to combine the different policies and plans already announced – energy storage obligation of 4% by FY 2030, projected capacity of 74 GW/ 411 GWh by FY 2032 in line with the National Electricity Plan, competitive bidding for storage and hybrid projects, 25-year ISTS charge waiver for projects completed by June 2025, financial support for PSP and participation in ancillary markets as well as High Price DAM window on the exchanges. Separately, the government has announced that it will subsidise 40% of capital cost through Viability Gap Funding (VGF) for developing 4 GWh battery storage capacity by FY 2031 with a financial budget of up to INR 94 billion (USD 1.1 billion).

There are some interesting new provisions in the framework but without concrete detail. As an example, it is suggested that renewable power projects over 5 MW may be mandated to install storage capacity equivalent to 5% of power capacity with minimum one-hour duration. Similarly, it adds that: i) ALMM (shudder!) and further production linked incentive schemes for BESS may be introduced in future; ii) concessional finance and priority grid connectivity may be provided to storage projects; and iii) the government may establish a nodal agency to coordinate dedicated R&D efforts with additional funding. The only material new provision relates to allowing storage projects utilising renewable energy to avail carbon credits, a potentially important incentive for the sector.

Figure: CEA’s storage capacity projection, GW

Source: CEA, BRIDGE TO INDIA research

The VGF scheme has been designed to reduce battery LCOS to INR 5.50-6.60/ kWh as against current estimates of over INR 11.00/ kWh. The scheme requires minimum 85% of capacity to be tied up in long-term contracts with DISCOMs. VGF shall be awarded through a competitive bidding process and disbursed most likely in five annual tranches post completion.

Subsidy support for BESS is much needed as users seem unwilling to bear full cost despite struggling to cope with intermittent profile of renewable power – delaying growth of this critical technology. The government is right to subsidise BESS but the proposed scheme size of 4 GWh is negligible in comparison to the FY 2032 BESS target of 236 GWh. The proposed VGF budget of INR 94 billion anyway seems sufficient to subsidise up to 10 GWh capacity and it is to be hoped that the scheme size will be enhanced over time.

The storage framework, already too late, needs more substance and concrete provisions for boosting R&D efforts, improved access to minerals and metals, more domestic manufacturing capacity and developing technical standards. From this point onwards, growth of the renewable sector would be dependent on growth of storage capacity.

India added 2,206 MW solar capacity in Q2 2023, 40% lower YOY, declining QOQ for five straight quarters in a row. Main culprit for the slowdown was utility scale solar, which added a mere 420 MW in the quarter. Open access was the saviour with volumes jumping steadily and outpacing utility scale capacity addition for the first time since the start of 2023.

The slump in utility scale solar can be attributed to a multitude of factors but three factors stand out – high module prices (greater than USD 20 cents/ W until April 2023), untimely ALMM implementation (relaxed in March 2023) and limited domestic module availability (only 4,404 MW in last 12 months, net of exports). Project developers have been delaying execution with help of multiple deadline extensions from the government on account of COVID, supply chain disruption and ban on laying overhead transmission lines in parts of Rajasthan and Gujarat. Only 16% of the total 12,678 MW capacity allocated in 2020 with SCOD up to March 2024 has been completed so far. There are still 4,043 MW of projects allocated in 2018 and 2019 waiting to be completed. Total project pipeline with SCOD before March 2024 and in FY 2025 stands at 26,817 MW and 19,714 MW respectively. Top five project developers by pipeline capacity with SCOD up to Mar 2025 include Adani (6,700 MW), NTPC (4,877 MW), ReNew (2,940 MW), SJVN (2,565 MW) and Azure (2,546 MW).

Figure: Solar capacity addition, MW

Source: BRIDGE TO INDIA research

The tide is now set to change with sharp correction in module prices – China FOB prices fell to record lows of USD 0.16/ W, down nearly 50% from last year’s highs – and ALMM relaxation. MNRE’s ultimatum to the project developers to complete all projects allocated before 9 March 2021 by March 2024 or risk suspension from future bidding has also spurred developers into action. Other growth enablers include rising contributions from open access and rooftop solar as well as significant increase in domestic module manufacturing capacity.

Consequently, we expect a big step up in annual capacity addition to over 18,000 MW and 20,000 MW in FY 2024 and FY 2025 respectively. Most of new projects completed this year are expected to use modules from China and SEA countries, which is bound to cause further policy angst. Cue further tussles on ALMM extension and import duties on SEA modules.

Note: INDIA RENEWABLE WEEKLY shall take a summer break over next three weeks. Next edition shall be released in the week commencing 11 September 2023.

Indian module exports have been on the way up for a year now. Q2 2023 export volume amounted to 1.3 GW modules, up 1,492% YOY. Total exports in the year ending June 2023 were estimated at 4.3 GW, up from just 247 MW in the previous year. Share of exports in total module production has now increased to 45% from just 4% in the previous year. Main exporters include Waaree and Adani with 61% and 31% share respectively during the year. The USA accounted for 97% of total exports.

Figure: Module export volume and price data

Source: Ministry of Commerce, BRIDGE TO INDIA research

Evolving global trade dynamics and keenness of the US and Europe to reduce reliance on China have turned the tide for India-made modules. The US has imposed anti-dumping duty of up to 165% on Chinese imports. Concerned by human rights abuses in China, it even enacted a sepcial legislation, the Uyghur Forced Labor Protection Act (UFLPA) in 2022, and detained 2 GW of Chinese shipments causing major uncertainty for project developers.

For India, the international aversion to Chinese imports is a terrific export opportunity. The US and European markets have a combined annual demand of up to 150 GW and no viable alternatives. Both regions are ramping up their own manufacturing bases with generous incentives for manufacturers under the Inflation Reduction Act (IRA) and Net Zero Industry Act respectively. However, despite expectations of a big bump in manufacturing capacity over next three years to about 60 GW and 30 GW respectively, supply is expected to remain well short of demand. These markets are focused on quality and willing to pay high prices. Exports to US have been priced at a rather lucrative USD 0.36-0.38/ Wp as against domestic market prices of around USD 0.25-0.30/ Wp over the last year.

It is therefore disappointing that the Indian companies have made only a feeble and opportunistic play to tap into the export markets. India’s module manufacturing capacity is growing but polysilicon, wafer and cell supply shortage seems set to continue. Indian manufacturers are heavily dependent on China for import of technology, engineering skills, upstream supplies and other critical components. Barring 2-3 companies, most manufacturers are focusing merely on low tech assembly or meeting in-house demand.

Customers in the US and EU want the latest technology, traceability, scale and security of supply. Most Indian manufacturers do not seem well positioned on any of these parameters.

There has been a slew of new entrants in the open access (OA) market over the last two years. Vedanta, a large industrial conglomerate has set up a dedicated platform, Serentica Renewables, to decarbonise group companies. International IPPs like BrightNight, Ampyr and AB Energia have entered the market recently and are already developing 100+ MW capacities across multiple states. New platforms like Sunsure have been set up with the support of private equity. Many utility market-focused project developers like Apraava, O2, Blupine and Sprng have jumped into the market. Torrent Power recently signed a 132 MW solar PPA with Shapoorji Pallonji for supply to its desalination plants in Gujarat. Public sector majors like NTPC and SECI are also keen to tap the opportunity. The number of active project developers with annual investment appetite of 50+ MW in the OA market is estimated at more than 30.

The increased interest comes in the face of improving market fundamentals with liberalised central government policy stance and higher corporate demand. Total OA renewable capacity addition in FY 2023 was estimated at 3,414 MW, up 67% over FY 2022, which itself was up 53% YOY. Share of OA in total renewable capacity addition increased to 25% in FY 2023 from 15% in the previous year. Most utility scale developers are also attracted by an opportunity to diversify portfolio – lower DISCOM exposure, higher financial returns and a more stable business (utility scale business is more lumpy, prone to longer gestation periods).

The inherent nature of the corporate renewable market means that it is highly fragmented. ReNew, the biggest player in the market by commissioned capacity over last three years, accounted for only 8% share of the total market. It was followed by Continuum, Cleantech, Fourth Partner and Ampin with market shares of only 4-7%. Top 14 developers accounted for only 56% share.

Figure: Leading OA project developers by commissioned capacity in FY 2021-23, MW

Source: BRIDGE TO INDIA researchNote: Data includes projects developed by consumers for 100% captive use.

With entry of so many new players, the marketplace is getting crowded and intensely competitive. There is some evidence of aggressive tariffs and risk positions in the PPAs, particularly around offtake and default provisions, especially in the private equity funded ventures. But there is also plenty of evidence of reasonable discipline in the market, due in part to lessons learnt from exceptional sector uncertainty over the last three years (BCD, ALMM, Covid, equipment and commodity price hikes, supply chain disruption) as well as the need to raise capital frequently. Rapid growth is also easing some of the competitive pressure.

So how are players seeking to establish a competitive edge? Indian corporate houses like Tata, Aditya Birla, JSW, Vedanta and Hero have a huge advantage because of the substantial in-house demand. As an example, JSW and Serentica have set targets to install 6 GW and 5 GW capacity respectively in the near-term future for captive use. Tata Power recently signed a 966 MW wind-solar hybrid PPA with Tata Steel for supply of round-the-clock (RTC) renewable power to its steel plants. Such players are generally more conservative when working with non-group consumers. Meanwhile, the utility scale developers enjoy a relative advantage in financing, execution scale and familiarity with the latest technologies. They are generally targeting select consumers with a 20 MW+ ticket size with the help of their corporate relationships. The corporate market specialists, on the other hand, are more nimble and focused on the 5-20 MW project business with larger business development teams on the ground.

One way to gain competitive edge is to make early investments in land acquisition, transmission connectivity approvals and other related infrastructure, typically about 8-10% of project cost. Readiness to commission a project within 6-12 months of signing the PPA is a big draw for consumers. Going forward, wider technology expertise and an ability to offer hybrid RTC solutions are also expected to be key differentiators.

Madhya Pradesh has recently issued a detailed procedure to verify captive status of renewable projects every year to ensure compliance with requirements as per the Electricity Act – minimum collective 26% equity ownership and 51% power offtake by respective consumers(s). In May 2023, Punjab had issued somewhat similar criteria to verify the captive status but went one step further. It mandated captive consumers to furnish a security deposit equivalent to estimated Cross Subsidy Surcharge (CSS) and Additional Surcharge (AS) for 51% of total annual power generation on a pre-emptive basis. Other states to have issued procedures to verify captive status of projects include Uttar Pradesh, Tamil Nadu and Himachal Pradesh. The Ministry of Power has also appointed CEA as the nodal agency for verifying captive status of inter-state projects.

Each state agency is using a different interpretation of the Electricity Act particularly in relation to changes in project shareholding structure or offtake over time. Recent amendments in Electricity Rules, 2005 have created further confusion. As per the amendment, a captive generating plant requires minimum 26% ownership and consumption of minimum 51% of power generation by a “consumer.” It is not clear if the change from “consumer(s)” to “consumer” is intentional – the amendment effectively permits only one consumer to claim captive benefit from a project and disbars multi-consumer captive transactions. The amendment also allows a parent company to claim captive status for a project owned by an affiliate subject to minimum 51% ownership in the latter.

All these measures, designed to prevent abuse the captive policy, are adding to unwarranted uncertainty in a growing market. Captive projects have become the de facto norm for open access transactions as they allow consumers to transfer all financial and operational risk for the project to a specialist third party and yet claim full benefit of CSS and AS exemption (see figure). The only niggle is that the consumers need to cough up 26% equity, equivalent to 7.8% of the capital cost, but they get pro rata reduction in PPA tariff.

Figure: CSS and AS waiver benefit for industrial consumers connected at 132 kV level, INR/ kWh 

Source: State tariff orders for FY 2024, BRIDGE TO INDIA researchNote: For Karnataka and Madhya Pradesh, AS is ignored as they have adopted the Green Open Access rules.

States are fiercely opposed to the idiosyncratic captive definition as it creates a hole in their finances. Many states including Rajasthan, Gujarat and Haryana have been downright denying approvals to such projects, while some others are using ad-hoc measures like unlawful levy of AS, captive tax, operational restrictions on existing projects and increased regulatory scrutiny to deter use of captive status.

We believe that it is time to unwind the captive policy, a vestige of old times, and simplify all associated processes particularly for renewable projects. The policy was designed at a time of severe power shortage for delivering (firm) conventional power to a group of consumers that could not individually set up thermal power plants. None of those assumptions hold true for renewable projects being developed today. The policy should no longer discriminate between projects based on their ownership or offtake. And if it can propose a simplified grid charge structure which compensates DISCOMs fairly for services provided by them, the policy could be a win-win for all parties.

This video presents a summary of major sector developments including tender issuance and auctions in May 2023.

L&T recently signed a technology licence agreement with France-based McPhy for making alkaline electrolysers in India. Before this, Greenko had signed an agreement with John Cockerill to build a 2 GW alkaline electrolyser manufacturing plant. Other companies to show an interest in electrolyser manufacturing include Adani, Ohmium, H2ePower, Reliance and GR Infraprojects. The latter two have signed technology partnerships with Stiesdal and H2B2 respectively. The US-based Ohmium already has an annual capacity of 500 MW, the only one to make electrolysers in India at present. These announcements add up to a total of 8 GW annual capacity by 2025. While most of the companies are looking to produce alkaline electrolysers, some are hedging their bets while Ohmium is focused exclusively on the newer PEM technology.

Electrolyser availability is obviously a key requirement for green hydrogen production. In view of the nascent market status, there are concerns that lack of supply may hold up green hydrogen growth. India’s green hydrogen production target of 5 MMT by 2030 requires total electrolyser capacity of about 50 GW, translating to annual manufacturing capacity of about 15-20 GW by that time. Global demand-supply scenario shows a similar deficit. Total manufacturing capacity at the end of 2022 was reported at only 15 GW – with China predictably taking the lead – as against estimated 2030 demand of between 134-240 GW. As per IEA, manufacturing plans announced so far by all companies worldwide add up to only 65 GW capacity by 2030.

Figure: Present electrolyser manufacturing capacity, GW per annum

Source: BloombergNEF, BRIDGE TO INDIA research

It is a great opportunity for India to take lead in a high growth market. China is expected to remain the dominant supplier with its large domestic market, strong government support and manufacturing prowess. But other countries need a supply alternative. The US and EU are also promoting domestic manufacturing with eye-watering incentives although it is debatable if they can ever become genuinely competitive with their high cost base and tougher permitting process.

Getting private companies to accelerate their manufacturing plans, however, is tricky since even the current small capacity remains underutilised. Private capital needs some demand visibility or at least a clear roadmap to price competitiveness of green hydrogen. It is a classic chicken and egg problem.

We believe that growth of Indian electrolyser manufacturing business is contingent on three factors – getting demand certainty, access to latest technology and critical raw materials. The government’s plan to offer incentives for green hydrogen production does not go far enough. The proposed INR 44 billion (USD 538 million) subsidy for electrolyser manufacturing is misguided since electrolyser cost accounts for barely 15% of total cost of green hydrogen production. These funds should instead be diverted to green hydrogen production and/ or incentivising technology research and/ or gaining access to supply of mineral and metals like zirconium, nickel (both dominated by China), iridium and platinum (concentrated in Africa). It seems more desirable to focus efforts on improving technology to handle variation in renewable power availability, reducing dependency on rare metals and developing recycling capability than trying to reduce the cost of electrolysers.

This video presents a summary of major sector developments including tender issuance and auctions in April 2023.

The European Parliament has given final nod to its landmark climate policy initiative, Carbon Border Adjustment Mechanism (CBAM). The scheme’s objective is to provide a level playing field to European Union (EU) businesses by subjecting imported goods to an effective tax equivalent to incremental environmental cost borne by domestic manufacturers because of EU’s tighter emission standards. The carbon tax will be determined based on differential of emissions produced in the production of goods overseas in comparison to benchmarks used in the EU Emission Trading Scheme (EU-ETS). The scheme is dsigned to eliminate expected to promote local production by eliminating arbitrage opportunity between domestic and international emission standards.

CBAM will be implemented in two phases. The first phase starting from 1 October 2023 will be a trial period applicable only to select industries like cement, iron and steel, aluminium, fertilisers, electricity and hydrogen that are exposed to higher risk of carbon leakage. These industries together account for more than 50% of emissions covered in EU-ETS. There will be no actual financial tax or payments during this period. This phase is meant to provide a learning curve both to the policy makers and businesses and also give the latter sufficient time to develop low carbon products. CBAM will be applicable only to direct emissions (scope 1) in this phase with indirect emissions expected to be added at later stage.

Full rollout of CBAM, the second phase covering more sectors and wider range of emissions, will start from 1 January 2026 when companies exporting to EU will have to purchase CBAM certificates based on emission intensity of their manufactured products. The certificates, meant to be non-tradable, shall be priced at levels corresponding to carbon pricing in the EU-ETS market, where prices have been observed in the range of USD 88-114/ tonne this year.

Indian exports of iron, steel and aluminium products to the EU amount to a considerable USD 8.2 billion (INR 670 billion) annually, 11% of total exports to EU and 26% of total exports of these commodities.

Figure: Indian exports to EU, million USD

Source: Ministry of Commerce, BRIDGE TO INDIA research

CII estimates that CBAM will levy an effective carbon tax of 39.6% and 19.8% on Indian steel made from blast furnace and electric arc furnace routes respectively. The presumptive tax on aluminium is 20.3%. Such high taxes are mainly due to dependence of Indian industry on coal-fired power resulting in its high carbon intensity – 2.6 MT CO2/ MT of crude steel, 37% higher than global average and 56% higher than EU average. Similarly,  carbon intensity of Indian aluminium production at 17-20 MT CO2/ MT is 150% higher than the EU average.

CBAM levy of 20-40% would obviously be highly detrimental to Indian businesses. It comes on top of a domestic carbon trading scheme, also imminent over the next few years, and rising RPO trajectory. The growing regulatory thrust on decarbonisation provides strong tailwinds for green technologies. We expect corporate renewable market to be the biggest beneficiary as renewable power enjoys significant lead in terms of techno-economic viability over other decarbonisation technologies like carbon capture and green hydrogen.

After witnessing one of the slowest periods in project auctions through 2022 and early 2023 (average monthly auction capacity of 802 MW), last six weeks have seen a surge in activity. Since April, a remarkable ten auctions totalling 6.9 GW capacity have been completed. Prominent auctions include 1,200 MW peak power by SECI, 1,000 MW RTC power by Indian Railways, 1,750 MW solar power by REC, 1,100 MW solar and 500 MW wind power by Gujarat, 1,000 MW solar power by Rajasthan, and 500 MW solar power by Maharashtra. Appropriately for these times, total allocated capacity was split 60:7:2:31 between standalone solar, wind, solar-wind hybrid and solar-wind-storage-hybrid projects. Actual hybrid project capacity is expected to be about 50% higher because of oversizing to meet higher CUF requirement.

Market response has been keen but not desperate. Most auctions were oversubscribed by about 1.2-3.0x. There were 27 unique bidders with bulk of the interest coming from private equity backed platforms and PSUs. The three biggest winners were ReNew (1,400 MW), NTPC (1,250 MW) and Avaada (1,040 MW). Notable absentees included Adani, Azure, Tata, JSW, Sprng, O2 and most international utilities.

Figure: Leading participants in auctions between 1 April–12 May 2023, MW

Source: BRIDGE TO INDIA research

As the following chart shows, tariffs have been on an upswing in the last year recovering to levels last seen in 2019/ early 2020. Even in SECI’s peak power tender, average tariff of INR 4.70/ kWh was about 15% higher than its last such auction in January 2020. Tariffs also seem more rationally based around differences in offtaker and location than at any time in the past. Barring the top winners, bidders have shown willingness to walk away if risk-return is not attractive. One hopes that Gujarat and other tendering agencies will accept these results rather than resorting to any cancellations.

Figure: Average tariffs in key auctions, INR/ kWh

Source: BRIDGE TO INDIA research

The upswing in tariffs, coming at a time when the cost outlook is becoming more benign, is a positive development for the industry. Module prices have now fallen by over 30% since May 2022 and look set to fall by another 10-15% by this year end.

This rare period of optimal bidding balance for the industry is explained by the fact that many developers are sitting on large project pipelines. Having delayed construction over last 2-3 years, they are still occupied by financing and execution issues. We believe that this scenario of rational bidding would last for another six months or so.

At the start of every financial year, DISCOMs revise grid tariffs with approval from regulators. It is usually a routine exercise involving a review of all operational costs and changes required in tariffs to sustain overall business. But this year, it seems that the DISCOMs have decided to tactically fight back against the growing corporate renewable market and its adverse impact on their finances. The new tariff orders include a series of measures such as reduced daytime tariffs, rebates for consumers switching back to grid, additional grid charges on renewable power and lower green tariff premium to protect their business.

Alteration in grid tariff structureA common set of measures seen across multiple states includes adapting grid tariff structure in a manner that makes open access less attractive. Maharashtra, Bihar, Karnataka and Uttarakhand have increased fixed charges, while some others (Madhya Pradesh, Andhra Pradesh and Odisha) have either reduced daytime variable tariffs or offered rebates to consumers to switch back to the grid (see figure below). TOD tariffs are also changing with higher discounts during solar hours and vice versa as seen in Karnataka, which is proposing to offer a rebate of INR 0.75/ kWh between 10 AM-3 PM and charge a premium of INR 1.00-1.50/ kWh between 6-10 AM and 6-10 PM.

Maharashtra, Madhya Pradesh and Karnataka have offered tariff rebates of INR 0.75-2.00/ kWh to OA consumers to encourage higher grid consumption.

Figure: Measures to make OA less attractive

Source: BRIDGE TO INDIA researchNotes: Some measures announced by Karnataka are still in proposal stages. Charges are shown for HT industrial consumers connected at 33 kV level.

Higher grid charges for renewable powerDISCOMs are also levying higher grid charges on renewable power to make it less attractive. Like Tamil Nadu, Maharashtra, Madhya Pradesh and Gujarat have done in the past, Andhra Pradesh, Chhattisgarh and Telangana are proposing additional charges for OA projects. Karnataka has gone even further and proposed a charge of INR 3.01/ kWh.

More attractive green tariffsThe number of states offering green tariffs has gone up from three in 2021 to thirteen. As the figure shows, several states including Uttarakhand, Maharashtra and Odisha have reduced the premium to increase attractiveness of this route.

Increase in banking chargesAlthough more states are offering banking for renewable projects, banking charges have been revised sharply upwards from 2-5% to 8% in Telangana, Madhya Pradesh and Karnataka, and to 15% in Punjab.

State governments and DISCOMs have historically resisted OA renewable by simply withholding connectivity approvals. The route has been unavailable to most consumers in key states like Maharashtra, Gujarat, Andhra Pradesh, Rajasthan, Telangana, Haryana and Punjab all these years. But issuance of green OA rules by the Ministry of Power in 2022 has changed the modus operandi. There is pressure on the states to be more transparent and introduce renewable-friendly policies. Many of the laggard states including Madhya Pradesh, Haryana, Punjab, West Bengal and Telangana have agreed to implement green OA rules although the timeline remains uncertain.

As seen in recent tariff orders, DISCOMs have a lot of tools available to discourage OA renewable market. We believe that the recent measures are just a beginning. Over time, DISCOMs are expected to further increase fixed tariffs (while lowering variable tariffs), impose higher grid charges on OA power, restrict banking and resort to more extreme TOD tariffs.

This video presents a summary of major sector developments including tender issuance and auctions in March 2023.

This video presents a summary of major policy and regulatory developments in March 2023.

Last four months have seen a flurry of activity in the agri-solar market with 23 new tenders totalling 7.3 GW capacity under KUSUM (components A, C-II) and state schemes. Since January 2020, a total of 73 tenders aggregating 25 GW capacity have been issued so far under these schemes. Maharashtra and Madhya Pradesh have tendered maximum capacity of 14.4 GW and 4.8 GW respectively, followed by Karnataka (1.3 GW) and Gujarat (1.1 GW).

Figure: Agri-solar tender issuance and project allocation since Jan-2020, MW

Source: BRIDGE TO INDIA research

While tender issuance is booming, subsequent progress is disappointing. Most tenders are heavily undersubscribed and/ or indefinitely delayed due to poor response. Only 1.25 GW capacity is believed to have been allocated so far, while total installed capacity across all schemes stands at only 653 MW. Main problem relates to intensive effort required for land acquisition and execution for a portfolio of small projects spread across vast regions. Project developers expect a tariff of circa INR 4.00/ kWh (USD 0.05), a premium of about 50% over utility scale projects, to make up for the extra cost and higher risk. But most tenders come with ceiling tariffs of about INR 3.30/ kWh or lower. A further complication is requirement to match L1 prices. With eligibility thresholds being kept intentionally low to encourage higher participation from farmers and other developers, stray low bids spoil prospects for other bidders.

Table: Agri-solar tender specifications

Source: BRIDGE TO INDIA research

The KUSUM scheme was announced in 2019 with a target of adding 17 GW solar capacity (excluding solar pumps) by 2022. The target was later revised upwards to 20.75 GW. In view of poor performance, the scheme deadline was extended to 2026. The government has tinkered with many scheme provisions including removing bank guarantees, relaxing project size limit and eligibility criteria but with little success.

The concept of agri-solar is too important to be allowed to fail. Distributed solar projects alleviate pressure on land and transmission grid, provide supplemental income to farmers and potentially improve farm yields. The government must find a way to reform the scheme to make it attractive for both farmers and solar project developers. New concepts like agri-voltaics, combining agriculture with solar power generation, should also be explored.

Waiver of ALMM requirement for projects commissioned by March 2024 has again opened doors to module imports. Project developers now have a range of choices when buying modules – import modules from China, import modules from South-East Asia, buy modules from domestic manufacturers, or import cells from China and convert them into modules through a tolling agreement with a local manufacturer.

But more choice is not necessarily making it easier for project developers, particularly for utility scale projects. Buying from China has definite advantages – local players have immense scale and produce the best modules using the latest technology at the lowest possible cost. But many projects are either not eligible for change-in-law relief for effective customs duty of 44% and/ or the developers are wary of a long, uncertain claim settlement process. Moreover, the time window available for ALMM-free imports is only about six months since projects need to be commissioned before March 2024.

South-East Asia imports have the advantage of zero customs duty under the Free Trade Agreement with ASEAN countries. But the downsides are formidable – higher prices in comparison to China, limited manufacturing capacity and need to comply with 35% local value addition requirement, which may not be so straightforward. Most of the 30 GW capacity in these countries is geared toward supplies to US, fetching prices as high as USD cents 35/ W. South-East Asia is an ideal choice mainly for corporate renewable projects with relatively low volumes and no entitlement to change-in-law relief.

Buying in India is the least preferred option as it entails the highest cost, which can vary significantly between USD cents 32-40/ W depending on volumes, quality and timeline. Most suppliers have small scale, limited working capital and are not deemed bankable. Only 3-4 domestic manufacturers can cater to a project needing 400 MW modules over a three-month period. This option is therefore preferred only by those with a mandate to use domestic modules – under CPSU, KUSUM and residential rooftop solar schemes.

Figure: Cost under different procurement options, USD cents/ W

Source: BRIDGE TO INDIA research

The last option is for project developers to import cells and get them converted into modules under tolling agreements with local manufacturers. There are some minor benefits over buying modules domestically – slightly lower cost, better control over BOM and quality, but the downside is a more involved decision process for developers, who also need to make advance payments to suppliers (local manufacturers are strapped for liquidity) and bear more risk in the process. This option was gaining in popularity before ALMM waiver but is likely to become less preferred in the short-term.

There are more layers of complexity to the procurement decision. The Chinese manufacturers, keen to protect their margins with more countries keen on domestic manufacturing, are resorting to increasing price manipulation. As the following figure shows, cell prices are being artificially kept at high levels despite a supply glut, even as module prices have been declining steadily. The shrinking price delta puts manufacturers in other countries at a considerable cost disadvantage.

Figure: China p-type mono cell and module FOB prices, USD/ Wp

Source: PV Insights, BRIDGE TO INDIA research

Meanwhile, the domestic manufacturers, hurt by ALMM waiver and duty-free imports from SE Asia, are preparing a petition for levy of safeguard duty on imports from South-East Asian countries. The project developers, on the other hand, are pushing the government to extend timeline for ALMM waiver. The tussle between manufacturers and project developers goes on.

SECI has announced winners of tranche-II of the Production-Linked Incentive (PLI) scheme. 11 companies have been awarded total PLI of INR 139 billion (USD 1.7 billion) to set up combined manufacturing capacity of 39.6 GW. Reliance and Shirdi Sai have each been awarded PLI for another 6 GW fully integrated capacity taking their total awarded capacity to 10 GW each, maximum permissible under the scheme. First Solar is the only other winner in the fully integrated category with a capacity of 3.4 GW. There are five winners including Waaree, ReNew, Avaada, Grew and JSW in the wafer-module category with a combined capacity of 16.8 GW; and three winners including Tata Power, Vikram and Ampin in the cell-module category with a combined capacity of 7.4 GW.

Average PLI amount per GW of awarded capacity in the polysilicon-module, wafer-module and cell-module categories works out to INR 5 billion, INR 3 billion and INR 2 billion respectively, approximately 25% of capital cost.

The second tranche was 4.3x bigger than the first tranche and yet the total response was 32% lesser in comparison. Overall, it was undersubscribed to the extent of 28% but the biggest shortfall of 37% was seen in the fully integrated category. Many bidders from the first round chose not to participate, most prominently Adani. Having earlier set ambitious plans, the group chose to sat out this round focusing instead on capital discipline in the aftermath of Hindenburg allegations. The muted response is mainly down to the overly generous US Inflation Reduction Act (IRA) and massive overcapacity in China. Both countries are seeing a spate of investments leading to concerns about competitiveness of India-made modules in the international market. China’s polysilicon capacity is expected to double this year to an equivalent of 500 GW of modules as against estimated global demand of about 300 GW. Meanwhile, the US module production capacity is expected to grow multi-fold to over 25 GW by 2026.

Suddenly, the Make-in-India story seems to be losing it sheen. Almost 50% of the bid capacity has come from project developers (Reliance, Tata Power, ReNew, JSW, Avaada and Amp), who, spooked by market disruption over last two years and stiff import barriers, are seeking mainly to meet their captive demand. We expect domestic polysilicon, cell and module capacity to reach 15 GW, 32 GW and 60 GW by March 2025 and 30 GW, 42 GW and 82 GW by December 2026 respectively – barely enough to meet domestic demand at the upstream level.

It is worth asking a question – was it necessary to spend INR 180 billion (USD 2.2 billion) in subsidies to attract these manufacturing investments, particularly when the government has already imposed daunting import barriers?

This video presents a summary of major policy and regulatory developments in February 2023.

This video presents a summary of major sector developments including tender issuance and auctions in February 2023.

After years of being talked up with little on-the-ground progress, pumped storage is finally on a roll in India. Noting the urgent need for more system flexibility in view of growing renewable capacity addition and high cost of battery storage, the Ministry of Power has issued draft guidelines for development of pumped storage projects (PSP). Projects shall be allocated on a preferential basis to PSUs and through competitive bidding process to private companies. Proposed incentives include exemption from any obligation to contribute to Local Area Development Fund or supply free power or pay any upfront success fee to state governments, 25-year waiver from inter-state transmission charge for projects commissioned before 30 June 2025, public funding for enabling infrastructure, and inclusion in the recently introduced high price day ahead market (HP-DAM). Further, off-the-river PSPs or those using existing reservoirs shall be exempted from requirement to obtain environmental clearance.

To improve financial viability of PSPs, the MOP has recommended regulations for creation of ancillary services markets including spinning reserves, reactive power, black start, peaking supply, tertiary and ramping support, faster start-up and shutdown besides notification of peak and off-peak tariffs for providing appropriate pricing signals to potential consumers.

The procurement front is also brimming. Karnataka has just concluded auction for a 1,000 MW/ 8,000 MWh pumped storage tender, a first of its kind by a state. Bidders were asked to quote a fixed annual fee payable over 40 years. JSW (300 MW) and Greenko (700 MW) quoted the lowest price at INR 1.22 million/ MW/ month, 14% lower than in NTPC’s 500 MW/ 3,000 MWh auction in December 2022. Levellised cost of storage is estimated at INR 5.00/ kWh, less than half for battery storage. West Bengal has developed a site for a 900 MW/ 4,500 MWh project at Purulia and is now inviting developers to build the project with no offtake guarantee.

India currently has 3.3 GW PSP installed capacity, which operates mostly in a power generation mode. Total PSP potential is estimated variously at 103 GW/ 618 GWh for on-river projects. As per CEA, 31 GW capacity is in various stages of development. The Draft National Electricity Plan expects 18.8 GW installed PSP capacity alongside 51.5 GW battery storage by FY 2032. However, the MOP is recommending faster development if battery storage systems are not deemed affordable. More than 70% of new PSP development is taking place in five states – Andhra Pradesh, Rajasthan, Karnataka, Maharashtra and Tamil Nadu.

Figure: Select states with pumped storage projects, MW

Source: CEA hydroelectric potential reassessment report

Greenko, an early mover with total under development capacity of 2.4 GW/ 22.1 GWh, is a big beneficiary. But long gestation period combined with high development, environmental and construction risk means that competition is likely to be limited mainly to Indian corporate groups like JSW, Adani and Shirdi Sai.

PSPs could be the optimal solution for India particularly over next 5-7 years while battery technology matures and becomes affordable. Domestically available technology with no reliance on international supply chains is a particularly attractive feature in current times. The key will be to manage long gestation period by developing sites proactively and managing environmental risk carefully.

Uttarakhand has become the latest state to accept the Ministry of Power’s (MOP) revised RPO target of 43.33% by FY 2030. Six other states including Himachal Pradesh, Rajasthan, Haryana, Punjab, Chhattisgarh and Madhya Pradesh have already done so. Himachal Pradesh and Madhya Pradesh have issued final regulations whereas other states are still at draft stage. Six states have adopted MOP recommendations without any exception, while Madhya Pradesh has adopted a slightly lower target of 37.89%.

Getting states to accept a central RPO target and enforce it has historically been a major challenge affecting growth prospects for the sector. In the past, most states have chosen to set their own RPO targets, often significantly below the central government recommendation. It is therefore encouraging to see states adopting the MOP recommendation. The central government is also determined to push in that direction – the draft Electricity Amendment Bill 2022 seeks to bind states to the central target with non-compliance penalties of INR 0.25-0.50/ kWh.

On the compliance front, only four states – Karnataka, Telangana, Rajasthan and Andhra Pradesh – are believed to have met their RPO targets so far with all other states consistently behind. The DISCOMs have been able to successfully argue for a lenient regulatory treatment citing reasons such as delays in project commissioning, high cost of renewable power and temporary suspension in REC trading for their failure to meet RPO targets. In Gujarat and Tamil Nadu, the regulators have simply overlooked non-compliance. In many other states including Haryana, Himachal Pradesh, Chhattisgarh, Uttarakhand and Punjab, the regulators have allowed DISCOMs to carry forward unfulfilled targets to future years without any penalty. In Punjab, a portion of the unfulfilled target was even waived off.

However, there is some evidence of regulators getting stricter. In Madhya Pradesh, the DISCOMs have been penalised to the extent of REC forbearance price (INR 1.00/ kWh) and weighted average market price for unmet targets in FY 2021 and FY 2022 respectively. The Uttar Pradesh regulator went one step further by asking the DISCOMs to deposit funds totalling INR 55 billion (USD 665 million) to cover penalty for unmet RPO in FY 2021 and 100% of required renewable power purchase cost in FY 2022. In Maharashtra, the regulator allowed carry forward of shortfall in FY 2019 and FY 2020 until FY 2023 subject to ARR reduction of INR 0.10/ kWh in each year.

Figure: Future RPO trajectory and current compliance level in select states

Source: State commission orders, BRIDGE TO INDIA researchNote: Actual RPO compliance level is shown for select states for FY 2020 or FY 2021 depending on data availability.

But imposing a uniform RPO trajectory on states is not a panacea. For states with current renewable penetration less than 10%, the target is particularly steep. Each state faces multiple and unique challenges in procurement of renewable power based on its specific position on demand-supply of power, grid status, availability of natural resource as well as suitable land at reasonable price. A state specific roadmap addressing these factors is required to ensure meaningful progress.