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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.

International Renewable Energy Certificates (I-RECs) are becoming more popular in India. In 2022, new projects aggregating 1 GW capacity were registered under the scheme outpacing registrations under the Indian REC scheme for the second year in a row. Aggregate registered capacity has now touched 3.7 GW, split between solar, wind and hydro power at 1.3:1.3:1.1 GW respectively. Annual issuance volume is up 88% YOY at 6,090 GWh.

RECs have become the only source of ancillary revenue for new solar and wind projects since they are no longer eligible for carbon credits granted by leading carbon credit registries like Voluntary Carbon Standard and Gold Standard. These registries have barred solar and wind projects since they are deemed financially viable without any additional revenues from sale of carbon credits. I-RECs, distinct from national RECs, are issued under transparent rules laid down by the International REC Standard Foundation and accepted by all global reporting frameworks including GHG Protocol, Carbon Disclosure Project and RE100. The instruments are traded bilaterally across 50 countries and account for a major share of global REC market with more than 170 GW registered capacity as of 1 March 2023.

I-RECs trade at much lower prices in comparison to Indian RECs – average price of INR 82/ MWh vs INR 1,000/ MWh in 2022 – but their relative popularity has increased because of high regulatory uncertainty in the Indian REC scheme. As Figure 1 shows, I-REC project registrations react sharply to changes in the Indian REC scheme. Another key advantage for I-RECs is that they are recognised internationally allowing multinational companies to meet renewable power procurement targets across multiple jurisdictions through a single market instrument.

Figure 1: Project registrations, MW

Source: I-REC standard, REC registry of India, BRIDGE TO INDIA research

Despite rapid increase in registered project capacity, I-REC issuance volume remains weak at only about 30% of estimated power generation from relevant projects. We believe that the low issuance volume owes to both demand and supply constraints. Most Indian consumers prefer direct procurement of renewable power instead of buying RECs at additional cost. Moreover, I-RECs are not recognised by Indian regulators and voluntary market is still in a nascent stage. The project developers are also hesitant to sign up because of significantly lower prices in comparison to Indian RECs, which enjoyed regulated price floor of INR 1,000/ MWh until December 2022. As the following figure shows, both REC markets suffer from considerable supply overhang.

Figure 2: Issuance and redemption volumes

Source: I-REC standard, REC registry of India, BRIDGE TO INDIA researchNote: Trading was suspended in Indian RECs from July 2020 to October 2021.

Going forward, a couple of factors should help boost the I-REC market. Growing corporate decarbonisation push is expected to boost voluntary demand. Fall in Indian REC prices post liberalisation of trading regime and lingering regulatory uncertainty should also improve relative attractiveness of I-RECs.

CEA has released a transmission network plan to enable cumulative renewable power capacity of 500 GW by March 2030. Setting aside previously announced schemes, the plan envisages further network expansion for evacuating 253 GW renewable capacity together with 51.5 GW battery storage capacity. The plan’s focus is mainly inter-state network expansion leading to increase in total inter-regional transmission capacity from 112 GW at present to 150 GW by March 2030.

Projects pending under existing Green Energy Corridor and Renewable Energy Zone (REZ) schemes are expected to be completed by March 2026. For new schemes, timeline for 71 GW expansion is not known, while remaining 182 GW is expected to be completed in three phases by December 2030.

Table: Transmission capacity growth, GW

Source: CEA

The incremental network expansion plan split across states and technology is broadly consistent with recent trend in renewable capacity addition and current project pipeline.

Figure: State and technology split for further network expansion

Source: CEA, BRIDGE TO INDIA research

The plan includes 10 GW offshore wind evacuation capacity split equally between Tamil Nadu and Gujarat. CEA also anticipates need for battery storage capacity of 51.5 GW/ 257.5 GWh to manage intermittent profile of renewable power.  

Total capital expenditure for works pending under REZ scheme and further network expansion (excluding storage capacity) is estimated at INR 2.4 trillion (USD 29 billion) – at an average cost of INR 10 million/ MW and 28 million/ MW for onshore and offshore RE capacity respectively. Based on past experience, about 50% additional expenditure is expected to be required for intra-state network augmentation. While the government may provide some grant funding along with low-cost financing from multi-lateral agencies in line with historical practice, bulk of the financing is expected to come from private sector with most ISTS capacity likely to be procured on a competitive basis.

Given that lack of evacuation infrastructure has been a significant growth bottleneck for the renewable sector, it is encouraging to see a clear roadmap. The overall numbers appear ambitious but as the following figure shows, an evenly spaced out plan is largely in line with historic trend. The challenge now is to ensure timely implementation particularly in view of growing ROW and environmental issues.

Figure: Historic and planned transmission capacity addition

Source: MOP, CEA, BRIDGE TO INDIA researchNote: ‘Annual average until December 2030’ includes both intra and inter-state capacity expansion. This estimate excludes expansion requirements for conventional power and regular upgrades.

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

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

In an unexpected positive development for the renewable sector, DISCOM dues have been coming down steadily over the last seven months. PRAAPTI portal, maintained by the Ministry of Power, reports DISCOM overdues (amounts outstanding past their due date) coming down from INR 1,367 billion in July 2022 to INR 288 billion at present, a fall of 79%. The fall is seen across multiple states including the ones with the most notorious payment record (Tamil Nadu, Andhra Pradesh, Rajasthan, Uttar Pradesh).

The most surprising element of improvement is what has led to it. The two fundamental policy initiatives aimed at reforming distribution business – Electricity Act amendments to delicence distribution and RRLSDS scheme to upgrade the physical network – are still stuck or in early stages of implementation. Instead, it is the short-term pressure tactics of central government that have borne surprise results. The new Electricity Rules, effective since July 2022, allowed the DISCOMs to clear their overdues in equal monthly instalments spread over 1-4 years with funding assistance from central-government owned financial institutions. DISCOMs failing to make monthly payments on time were threatened with ban on procurement from inter-state power projects as well as short-term open access and exchange markets. In August 2022, 27 DISCOMs across 13 states were restricted from buying power on the exchanges after missing the first payment date, but the list was reduced to only four DISCOMs the next day after overnight payments.

PFC and REC have together sanctioned and disbursed debt totalling INR 1,028 billion and INR 280 billion respectively to DISCOMs in 13 states as of December 2022 (Andhra Pradesh, Bihar, Chhattisgarh, Jammu & Kashmir, Jharkhand, Karnataka, Madhya Pradesh, Maharashtra, Manipur, Tamil Nadu and Telangana).

Figure: DISCOM overdues, INR billion

Source: PRAAPTI portalNote: PRAAPTI portal data, collated using voluntary information provided by IPPs, is not complete. Total DISCOM overdues are estimated to be about 50% higher as per PFC reports. Data excludes overdues converted in equal monthly instalments.

Total overdues of solar project developers are estimated to have come down from a peak of about INR 135 billion in July 2022 to INR 35 billion at present. All publicly listed IPPs have reported significant improvement in receivables position. ReNew reported a 30% YOY reduction in receivables position to 178 days by December 2022. Adani reported similar progress in payments from Tamil Nadu, Madhya Pradesh and Karnataka. According to a CRISIL estimate, receivable days for leading developers, accounting for about 50% of total renewable capacity, are expected to reduce from 180 days currently to 140 days by March 2024.

It is still early days but resolution of DISCOM dues is great news overall. The payments and liquidity crisis facing IPPs has been averted for now. Preliminary estimates for FY 2022 also suggest encouraging reduction in AT&C losses and ACS-ARR gap to 17% and INR 0.22/ kWh from 22% and INR 0.69/ kWh respectively a year ago. However, there have been multiple instances in the past of temporary progress after announcement of short-term financial packages only for the problem to get worse again. Lack of a clear roadmap to reform the distribution business remains a concern but nobody will complain if the central government can enforce discipline through indirect measures.

The Power Minister has announced that the government is planning to waive ALMM requirement for two years because of lack of sufficient domestic manufacturing capacity. A final notification is expected shortly. It is not clear as yet if the requirement will be waived for all projects or only projects tendered by government agencies (most likely, the former); or for how long. The project developers want the waiver to last until domestic module and cell manufacturing capacity reaches 50 GW and 40 GW respectively. Separately, the government has issued an ultimatum to project developers that it would encash their bank guarantees and blacklist them for 3-5 years if they fail to commission projects within prescribed time. There is even strong speculation that BCD will be waived for selected projects but we deem that as highly unlikely.

These actions and speculations are all linked – slow pace of progress has finally got the government worried. The current annual run rate of about 15 GW capacity addition is less than half of government targets. 2023 prospects are looking even worse because of ill-timed policy moves. Progress on domestic manufacturing keeps getting delayed. Most of the new cell plants are not slated to commence commercial production until early 2024. Bids for PLI 2 scheme are yet to be submitted, five months after approval of the enhanced budget. Over the last six months, module availability has averaged only 521 MW per month. All alternative import routes like bonded warehouse scheme and concessional duty project imports have been closed.

Figure: Module availability for the domestic market, MW

Source: BRIDGE TO INDIA research

We estimate total solar pipeline capacity with March 2024 completion deadline at 29,590 MW. Minus ALMM waiver, total module availability in the year could be as low as 8 GW, explaining the government’s sudden volte-face.

However, ALMM waiver with BCD still applicable does not solve all problems. Prospects for imports from ASEAN countries, enjoying BCD exemption under the Free Trade Agreement (FTA), are limited. Total cell and module manufacturing capacity across ASEAN countries is estimated at only about 10 GW and 30 GW respectively. And most of this capacity is earmarked for exports to other countries (mainly US) at substantially higher prices (30-35% higher in comparison to China). There is also a potentially cumbersome issue of needing to prove 35% local value addition to meet FTA norms. We believe that ASEAN imports would be preferred by corporate renewable projects (no change in law compensation, shorter project timelines and willingness to pay higher prices).

Volumes and price wise, imports from China remain the most viable option. But that option is closed to projects not eligible for BCD pass through to offtakers. Even otherwise, the developers are reluctant to incur BCD cost, which has to be funded entirely by equity, due to uncertainty in getting ‘change in law’ claims resolved in a timely manner. Considering all these limitations, we estimate actual module availability during the year at maximum 20 GW including imports.

For domestic manufacturers, the ALMM waiver is not good news. Every relaxation is a blow to their business fundamentals and a pointer to the whims of policy making in India. Lack of foresight and kneejerk policy responses pose a critical risk to both manufacturers and project developers alike.

Renewable power trading on the exchanges grew strongly in 2022 with total volume up 60% YOY to 7,397 GWh. One clear trend in the market was increasing preference for non-solar power, which accounted for 72% of total volume and bulk of total growth. Non-solar power also enjoyed a 28% price premium over solar power – average price of INR 6.35/ kWh vs INR 4.98/ kWh respectively – on the Green Term-Ahead Market (GTAM). Overall, average prices for different instruments were up about 35-42% YOY in response to rising demand.

Share of traded power also rose to 4% of total renewable power generation, up from 3% in 2021. Green Day-Ahead Market (GDAM) contracts accounted for 70% of total renewable power traded on IEX owing to easier trading mechanism and higher output predictability.

Figure 1: Renewable power exchange trading volume and prices

Source: IEX, PXIL, HPX, BRIDGE TO INDIA research Note: Trading volume is shown for all IEX and PXIL GTAM transactions (98% of total green power traded in 2022). Pricing information is shown for IEX, which accounted for 73% share of total traded power.

Higher demand and prices for non-solar power could be explained by relatively faster increase in national evening peak power demand, which touched 216 GW in the year as against 203 GW in 2021. Average peak price on GDAM in 2022 was recorded at INR 9.30/ kWh, a delta of INR 4.68/ kWh over day-time power, explaining increasing popularity of peak power tenders.

Figure 2: Average hourly volume and prices on IEX GDAM in 2022

Source: IEX, BRIDGE TO INDIA research

As expected, trading demand has been dominated by states with low RPO compliance and/ or unfavourable renewable resource. Maharashtra was the leading buyer, followed by Punjab, Gujarat, Daman & Diu and Dadra & Nagar Haveli, Assam, DVC and Delhi. Participation of corporate consumers was limited with Railways, ArcelorMittal and Vedanta the only corporate consumers on GDAM. Exchange power remains commercially unattractive because of high total landed cost including grid charges of about INR 9.57-11.04/ kWh in key industrialised states.

Figure 3: Leading buyers and sellers on GDAM in 2022: total traded volume – 3,573 GWh

Source: POSOCO, BRIDGE TO INDIA research

Conversely, the sell side was dominated by states running ahead of their RPO targets. Karnataka, which reported renewable power penetration of 59% in FY 2022, led with 33% share of supply on GDAM. Adani (19% share), ReNew (3%), NTPC (2%) were the leading IPP sellers, but their participation came mainly from operational projects still awaiting commissioning certificates.

Growing exchange activity is a significant positive for the sector. It is providing not only a relief from rigid long-term PPAs but also vital signals about evolving shape of the sector as well as needs of market participants. While sector growth is bound to benefit market liquidity, further policy measures to improve trading volumes will be of huge help.

Slowing growth and mounting execution risks have had a disastrous impact on financial health of wind turbine manufacturers. FY 2022 operational income for Inox Wind and Suzlon, two of India’s biggest OEMs, was down by 86% and 31% respectively in comparison to FY 2016 numbers. Both companies have been consistently reporting losses since FY 2018. Alongside other smaller OEMs, they have had to shut down capacity and undergo multiple rounds of business and financial restructuring. It is worth noting here that India transitioned to wind project competitive auctions in 2017.

International OEMs like Vestas, Siemens Gamesa and GE are facing similar problems. Siemens Gamesa, which reported net loss of EUR 884 million in Q4 2022, more than double over a year ago, has flagged high warranty costs arising from high failure rate in its new 5.X onshore turbines. The company is reorganising the business by cutting jobs and adjusting capacity to match market demand. Vestas expects revenues and profitability to suffer further in FY 2023 due to high input cost inflation and weaker than expected demand.

Figure: Financial results of listed OEMs

Source: BRIDGE TO INDIA researchNote: Financial year for Vestas and Siemens Gamesa ends in December and September respectively. Inox Wind demerged its EPC and IPP businesses accounting for 9% of total revenue in FY 2021.

Stuck between spiralling costs, growing construction risks and downward pressure on prices from project developers, the OEMs are seeking to de-risk their business. No OEM is prepared to offer lumpsum turnkey solution including turbine supply, land acquisition, transmission connectivity, installation, commissioning and O&M. The focus now is to just build and sell turbines. The project developers are therefore having to acquire remaining services piecemeal from other contractors or perform them in-house.

The change has brought about a huge market disruption with emergence of a whole new class of sub-contractors and supply chains. Specialised contractors like Kshema Power, Everrenew, KS Wind and Sanghvi Movers are providing services like resource assessment, government permits, land and ROW rights, transmission connectivity, installation and commissioning. There is another group of companies including Inox Green, Renom, Powercon and Windcare providing a range of unbundled operational and maintenance services. Some developers including JSW, ReNew and Greenko have started performing O&M activities in-house. Some are even seeking to make their own turbines with technology licences from overseas companies. Adani recently announced plans to manufacture wind turbines in Gujarat.

The principal implication of these changes in value chain is transfer of execution and performance risk from OEMs to project developers. The new class of contractors is often too small with nominal risk bearing capacity. Any reduction in costs is insignificant in comparison. The project developers are getting squeezed between low tariffs and mounting execution risks.

This video presents a summary of major policy and regulatory developments in December 2022.

This video presents a summary of major sector developments including tender issuance and auctions in December 2022.

MSEDCL recently concluded auction for its 250 MW peak power tender issued in August 2022. Tariff for daytime power (10 AM-6 PM) was fixed at INR 2.42/ kWh and bidders were required to quote a tariff for supply during remaining hours (6 PM-10 AM). There were four bidders – Ayana (150 MW) and NTPC (250 MW) quoted the lowest tariff at INR 9.00/ kWh, while HES Infrastructure (50 MW) and Greenko (250 MW) quoted INR 9.01/ kWh and INR 9.04/ kWh respectively.

The tender provides a lot of flexibility on project configuration but peak power offtake provisions are unfavourable:

Minimum CUF is specified as 19%.

Projects may be may developed anywhere in the country using any combination of solar, wind and hydro power coupled with any storage technology. There is no requirement to co-locate storage component with other components.

Bidders must be able to supply 125 MW power – 50% of contracted capacity – for any six non-solar generation hours (peak power) as specified by MSEDCL on daily basis. However, MSEDCL obligation is limited to offtaking power for only 2 of these hours.

Any shortfall beyond 15% in peak hour supply would be penalised at 1x, 2x and 3x peak power tariff for shortfall between 15-20%, 20-30% and > 30% respectively.

Surplus power supply in peak hours and off-peak hours would be compensated at 100% and 75% of off-peak tariff respectively.

With co-location of storage component not essential, we understand that all four bids are based on pumped hydro storage technology. Ayana has signed an agreement with Greenko to secure 6,000 MWh pumped storage capacity. NTPC is in the process of contracting 500 MW/ 3,000 MWh storage capacity with Greenko at an estimated cost of storage of INR 5.00/kWh for one daily cycle, proving strong cost advantage of pumped hydro over battery technology.

Figure: MSEDCL 250 MW auction result

Source: BRIDGE TO INDIA research

The ideal technology combination for these projects is solar:wind in the ratio of about 40:60 to meet minimum peak supply requirement at the lowest possible cost while minimising storage capacity. Given the effective pumped storage cost of about INR 3.75/ kWh assuming 1.5 average cycles per day, the bid tariffs seem quite a bit higher than expected. The catch here is that while the bidders are required to build system flexibility, MSEDCL has limited its obligation to buy peak power to only two hours every day. As a result, all storage cost has been loaded on two committed hours of peak offtake increasing peak tariff by about 30% to INR 9.00/ kWh. A simplistic comparison with SECI’s 1,200 MW peak power tender – off-peak power tariff fixed at INR 2.88/ kWh, 100% offtake obligation for entire peak hour output – shows the difference clearly. In this tender, winning peak tariff bids came in the range of INR 6.12-6.85/ kWh by Greenko and ReNew respectively.

The risk now is that the high tariff would be unacceptable to MSEDCL, which is reportedly trying to negotiate with both Ayana and NTPC. Irrespective of the final outcome, it is becoming abundantly clear that pumped hydro technology is the winner with its significant cost advantage notwithstanding construction risk concerns. Other than Greenko, which has total capacity under development of 2,460 MW/ 22,100 MWh, JSW and Adani group are also developing pumped hydro projects.

More peak power tenders are on the way. SECI has issued another 1,200 MW peak power tender, while GUVNL is about to conduct auction for a 500 MW peak power tender. Results of these tenders will provide useful clues about shape of industry over next few years.

CERC, the central power sector regulator, has issued an order capping base penalty rate under Deviation Settlement Mechanism (DSM) at INR 12/ kWh for both power producers and consumers. Earlier, the base rate was set at maximum of weighted average price discovered on power exchanges and weighted average ancillary service charge. The change came in response to reports of around 20% increase in frequency excursions beyond the prescribed band (49.90-50.05 Hz) since new DSM regulations came into effect on 5 December 2022, which led to ancillary service charge shooting up to INR 40/ kWh.

Under the new DSM regulations, deviation bands for renewable power projects have been tightened from 15% to 10% while penalty rates have been increased. Under-injection beyond 10% attracts penalty at 10% of the base rate while over-injection between 5-10%/ beyond 10% attracts penalty equivalent to 10% and 100% of PPA tariff respectively. The asymmetric nature of penalties means that the power producers are overestimating generation resulting in higher frequency band violations and greater demand for ancillary services.

States with high renewable power penetration have been pushing CERC for more stringent deviation penalties for renewable projects to help maintain grid stability. Karnataka is a good example – the state reported 58% renewable penetration in FY 2022 with monthly penetration reaching a high of 76% in July 2021. Daily wind power generation in the state varied between 800 MW to 2,700 MW in FY 2022 necessitating more frequent and bigger changes in conventional power consumption resulting in higher penalties.

Power producers have reported a sharp jump in penalties under the new regime. Wind and solar power producers in the southern region reported 12x and 6x week-on-week increase respectively in penalties for the week of 5-12 December 2022. Weekly penalties for the seven ISTS wind power producers in southern region increased from INR 3.5 million to INR 42 million in the week of 5-12 December 2022, while the quantum went up from INR 13 million to INR 77 million for the 29 ISTS solar power producers in the southern region in the same period. The trend is similar for projects in the western region as seen in the following figure. We understand that projects in the northern region managed to buck the trend mainly due to favourable weather conditions.

Figure: Aggregate weekly deviation penalties for ISTS projects, INR million

Source: Regional Power Committees, BRIDGE TO INDIA research

Aggregate deviation penalties for solar and wind power producers are estimated to grow from 0.3% and 0.5% of revenues to 1.2% and 2.5% of revenues respectively. Power producers have raised their concerns at various levels including a legal challenge in the Delhi High Court. The court has refrained grid operators from encashment of bank guarantees or grid disconnection until 25 April 2023. Meanwhile, MNRE has set up a committee to address grievances of renewable power producers.

The new DSM regulation exposes growing conflict between renewable power producers and consumers. Tamil Nadu, Karnataka, Madhya Pradesh and Haryana have already adopted CERC regulation for intra-state projects, while Gujarat has gone for an even tighter permissible deviation band of 7-8% for solar and 8-12% for wind power projects. Other renewable-rich states are bound to follow. The Draft Indian Electricity Grid Code 2022, currently under consideration by CERC, proposes limiting revision flexibility in generation schedules, which would make things worse for power producers.

In the absence of any likelihood of recourse under ‘change in law’ provisions in the PPA, the project developers can only hope for a favourable decision from the courts and hone their forecasting ability to minimise revenue loss.

MNRE has finally released the much-anticipated National Green Hydrogen Mission document. As expected, the target is to build 5 MMTPA green hydrogen production capacity fuelled by 125 GW renewable power capacity by FY 2030 for domestic consumption. The document sets out an additional aspiration of becoming a global hydrogen hub with another 10 MMTPA capacity by FY 2030 for exports. To help initial scale up and reduce costs for early adopters, the government aims to provide financial support of INR 197 billion (USD 2.4 billion), split 89:7:4 across subsidy programmes, pilot projects and other areas including R&D, consumer awareness etc. The plan is divided in two phases – Phase I (FY 2023-26) with a focus on boosting demand and building supply capabilities, and Phase II (FY 2027-30) with a focus on implementation and increasing penetration.

The mission document is macroscopic in its vision and should be lauded for capturing all key techno-commercial aspects besides softer areas like inter-ministerial coordination, international collaborations, R&D, testing facilities, technical standards, skill development, ease of doing business, safety and certification etc. The Phase I timetable also seems pragmatic with due consideration provided to capacity building efforts. But things get sketchy thereafter and detail is scarce.

The vision is extremely ambitious. The anticipated renewable capacity and total capital cost of over USD 100 billion are more than 2.5x actual achievement in the renewable sector in the last five years. Layering the 125 GW renewable capacity target on top of current renewable sector plans takes annual renewable capacity addition target to 60 GW, which seems outlandish.

The planned support measures do not go far enough either. Critical issues like commercial viability, demand creation and export competitiveness have not been given sufficient consideration. For example, green hydrogen cost, currently estimated at about USD 6-7/ kg, is about 3x the cost of grey hydrogen. Even with significant improvements in technology, reduction in power generation costs, 100% waiver from grid charges (far from certain) and marginal subsidies, green hydrogen is expected to be more expensive than grey hydrogen in five years time.

Figure: Green hydrogen production cost, USD/ kg

Source: BRIDGE TO INDIA research

The envisaged subsidy budget of INR 175 billion (USD 2.1 billion) is too small to make a difference. Our calculations suggest effective subsidy of just 8% for electrolyser manufacturing and hydrogen production for only 20% of total target. Absent commercial viability, demand creation becomes crucial but the government seems to be dithering on forcing green hydrogen or ammonia purchase obligation on refineries and fertiliser plants. It is understandable that the user industries, already struggling to cope with input cost hikes and other challenges, are resisting any premature obligations.

On exports, India is expected to face strong competition from many other countries including the US, Canada, Australia, Middle-East and China, all racing ahead to gain an attractive pie of the emerging market. The US and Europe have already announced substantive subsidies to produce green hydrogen domestically. Canada recently proposed to provide 30% capital subsidy for renewable projects and 40% tax credits for green hydrogen projects in an effort to catch up. China has identified green hydrogen as a national priority and already accounts for nearly 50% of global electrolyser capacity.

The mission document is a good start, but more as a statement of intent than a blueprint. Realising the vision would require detailed planning, more incentives and policy support. Our latest India Renewable Market Brief on green hydrogen discusses many of these issues in more detail.

Best wishes for a very happy new year to all our subscribers!

2022 was the year when renewable power sector proved its resilience in the face of extreme cost pressures, BCD, ALMM, shortage of modules and transmission system hold ups. Our estimates suggest a record capacity addition of 16.4 GW, up 31%, split 88:12 between solar and wind respectively.

The new year has started on a good note with polysilicon and all downstream module costs falling sharply (see below). But there are still two big unknowns. Domestic module availability is tight and expected to remain so until late in the year when new manufacturing capacities start coming online. The government has been sending mixed messages about concessional duty import approvals under project route. And timeline for final decision by the Supreme Court on transmission lines in Rajasthan and Gujarat is also unclear. As a result, construction activity is expected to be subdued in H1 but pick up strongly in H2. Depending on how things play out, annual capacity addition could come anywhere between 11 and 16 GW as against government target of 36 GW. The corporate renewable market should stay buoyant with capacity addition of about 3.5 GW as there is more willingness to bear higher costs. The residential rooftop solar market is expected to flatline at about 500 MW.

We have identified five major themes for the year.

Strong decline in module pricesChina module prices have already fallen by more than 10% in last month and by 28% since the highs of June 2022 to about USD 0.21/ W. With substantial new capacity expected to come onstream in the next year, prices are expected to stay soft with possibility of further decline quite likely. As domestic supply ramps up in parallel, prices in India should also settle around USD 0.25/ W, a fall of over 30% since June 2022, providing big boost in the future years.

Module manufacturing takes offBetween Reliance, Adani, Tata, Waaree, First Solar, ReNew and Premier, almost 24 GW of cell and module manufacturing capacity is expected to start operations by around end of this year. PLI 2 allocation shall provide a further boost to module manufacturing. Prospects are also brightening up on wind turbine availability as Envision, Senvion, Adani and JSW ramp up their manufacturing operations.

Tendering activity to pick upPace of project auctions is expected to pick up considerably as power demand has been growing steadily and SECI has slowly cleared backlog of unsigned PPAs. Focus is expected to be increasingly on new solar-wind-storage hybrid designs to address DISCOM concerns about variability of renewable power and compatibility with demand profile. The DISCOMs should be willing to pay more for the flexibility but that remains an unknown.

Financing costs to stay highHigh inflation and monetary tightening are expected to run course by around middle of the year. But financing costs are expected to stay at the higher end presenting a challenge for project developers. Caught between high capex need and tough funding environment, many developers including NTPC, ReNew, Continuum and JSW are likely to turn to secondary market for funds.

Policy focus on implementationIf 2022 was the year of big announcements (500 GW target, updated RPO trajectory to FY 2030, green open access rules, proposed amendments to Electricity Act, new carbon trading scheme, hydrogen policy), 2023 would be the year of implementation. The government has got its task cut out as effective implementation of these policies would lay foundation for the sector for many years to come.

With a little bit of luck and deft policy manoeuvring, 2023 could really be a turnaround year for the sector. Key events to look out for during the year:

Module PLI 2 auction

More details on the hydrogen mission

Supreme Court decision on transmission lines

Passage of Electricity Act amendment bill through the Parliament

Details of the carbon trading scheme

NTPC renewable energy business monetisation