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.Read more »
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.Read more »
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.Read more »
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.Read more »
This video presents a summary of major sector developments including tender issuance and auctions in December 2022.Read more »
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.Read more »
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.Read more »
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.Read more »
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 monetisationRead more »
India added 3,761 MW corporate renewable capacity in first nine months of the year, 61% more than in whole of 2021. The numbers are especially pleasing because of a series of recent adverse developments including increase in construction costs, imposition of BCD and ALMM, and high policy uncertainty. The jump has come mainly from spurt in solar open access (OA) capacity addition of 2,608 MW in the first nine months. In comparison, both OA wind and rooftop solar have been struggling with total capacity addition of only 1,153 MW.
Figure 1: Corporate renewable capacity addition, MW
Source: BRIDGE TO INDIA research
OA growth has been led by Tamil Nadu (750 MW) and Karnataka (643 MW) together accounting for 49% of capacity addition in the 9 months to September 2022. These two states have been mainstay of the business for a few years. The major positive is emergence of other bigger states like Maharashtra (386 MW), Gujarat (336 MW) and Rajasthan (203 MW) as growth engines.
OA market resilience can be attributed to two developments. There is a paradigm shift in consumer behaviour with larger corporates driven more by decarbonisation push rather than cost savings. That has made a big difference at a time when costs and tariffs have been inching up. Adoption of net zero and other such pledges like RE100 is leading to pressure to increase renewable penetration as evident from recent deals by Vedanta, Amazon, ArcelorMittal, Adani and Reliance. We understand that Reliance alone plans to install 20 GW captive solar generation capacity by around 2027.
Figure 2: Major renewable OA project announcements
The corporate push, in turn, is giving way to a more favourable policy environment. The central government has taken the lead with new green OA rules, new RPO trajectory until FY 2030, ISTS waiver and relaxation of transmission connectivity procedure. The recently launched green open access portal has already seen 2,210 project applications being approved. Even state governments and DISCOMs, historically resistant to the market, are beginning to bow to consumer demand – Gujarat and Maharashtra being prime examples in that regard. Karnataka, Madhya Pradesh, West Bengal and Punjab have already issued draft policies consistent with green OA rules. Five states including Haryana, Madhya Pradesh, Chhattisgarh, Himachal Pradesh and Punjab have proposed to accept revised national RPO trajectory.
BCD, ALMM and shortage of high efficiency modules domestically still pose considerable short-term hurdles. But to compensate, we expect CERC to effect ISTS waiver for OA projects in the coming few months. That, together with module supply situation easing from H2 2023 onwards, should provide a further boost to the market. We expect the OA market to grow at a CAGR of 25% plus in the next five years.Read more »
In a recent note, we identified land, transmission and technology as the most acute supply side challenges for the renewable sector. Dependence on overseas technology is a key risk specifically for the Indian renewable sector. However, technology receives little attention in the discourse on sector dynamics.
It is well known that about 90% of modules used in India’s solar sector have been imported historically. But the country’s technology dependence on external parties goes far beyond this. The entire inverter supply comes from outside India although some of these suppliers now assemble products in India. It is the same story for other key solar project components like trackers and robotic cleaning. For wind turbines, Indian suppliers together account for about 50% market share but all technology is sourced internationally. In any case, most critical turbine components are still imported. Global battery manufacturing capacity has grown rapidly to cross 1,000 GWh, whereas India is just entering the race. There are billions of R&D dollars being deployed in clean energy technologies but again India’s share is negligible.
Figure: Leading suppliers for projects commissioned between 2017-2021
Source: BRIDGE TO INDIA research Notes: Capacity figures are stated for grid-connected projects in MW AC. Data excludes rooftop solar and other distributed renewable systems.
The Make in India thrust should help but it does not sufficiently address the core question of technology dependence. All fundamental technology know-how and even manufacturing lines and installation personnel for new PV cell and module lines, being set up currently, are coming from overseas suppliers. The downside of such heavy technology dependence is vulnerability in times of trade wars, geo-political disturbances and material shortages. We have already witnessed that when polysilicon capacity became constrained recently, module supplies to India were terminated and shipments were diverted to other countries willing to pay higher prices. Boom in clean energy demand worldwide is creating increasing fragility in international supply chains. Other countries are entering into a competitive race to attract investments and technology.
There is another dimension to dependence on global technology. Most technology R&D is focused on developing products for a specific use case, ambient conditions and financial capacity typically for customers in rich western countries or perhaps China. As we have seen in multiple sectors including electronics, automobiles, healthcare amongst others, India’s demand is of an altogether different nature. Germany may need high powered 4-W EVs with large batteries performing ideally in cold temperatures, whereas India mostly needs smaller vehicles travelling shorter distances in a hotter, dustier environment. Dependence on other countries often means overpaying for sub-optimal technology from an Indian viewpoint.
By various estimates, India is going to invest over USD 300 billion in this decade on clean energy. Consulting firm McKinsey estimates the country’s total spend on decarbonisation by 2050 at between USD 7-12 trillion. It cannot afford to spend all this money being completely beholden to foreign technology. The government needs to take the lead by developing domestic research capability, providing R&D grants, signing international technology transfer agreements, incentivising use of new technologies and making technology a key focal point of all policies. As an example, power procurement framework needs to evolve from simply choosing the lowest tariff to paying a premium for more efficient technology that uses less land and water resources, and more locally available, eco-friendly materials.Read more »
Of the four main supply side factors for renewables – land, transmission, technology and financing, the first two are the most critical – always in short supply and on critical time path due to long lead times, complex regulations and increasing cost. Despite multiple government initiatives including solar parks, green energy corridors and renewable energy zones (REZs), there are persistent delays in acquiring land and transmission connectivity.
It’s an obvious problem. Renewable projects require huge parcels of land – more than 150,000 acres every year to meet national targets (about 4 acres per MW). The land must have attractive renewable resource, suitable topography, be contiguous and accessible, located close to transmission network and low cost. With most attractive sites already utilised, government authorities and project developers are increasingly forced to seek uneven parcels of non-contiguous land, often with swampy or rocky terrain in extremely remote locations increasing execution cost and timeline uncertainty. These project sites also frequently encroach on ecologically or socially sensitive areas creating thorny conflicts (link, link, link). Extending transmission system to these remote locations further amplifies the associated problems. According to a government report in October 2020, 18 out of 42 transmission projects by Power Grid Corporation were facing delays due to land acquisition problems, difficult terrain, natural obstacles, geological surprises, contractual disputes, and environmental and forest issues.
Efforts to set up a 13 GW wind-solar-storage hybrid project in Leh with inhospitable climate and no infrastructure are illustrative. A 5 GW transmission line along with 1 GWh grid storage capacity is being developed to evacuate power to Haryana at an estimated cost of INR 247 billion (USD 3 billion) and completion timeline of 5 years. To defray the high cost for consumers, the government is mulling providing subsidy worth INR 99 billion, 40% of the project cost.
All government schemes intended to tackle land and transmission challenges have been beset with multiple hurdles.
Solar park schemeThe scheme was launched in 2014, aiming to develop solar park infrastructure for 20 GW capacity, later increased to 40 GW, by March 2022. Multiple reasons have slowed progress – slow land acquisition, delays in statutory approvals, poor infrastructure and inflated costs. Only 10,001 MW project capacity was commissioned as of June 2022.
Figure 1: Status of solar park scheme as of June 2022, MW
Source: MNRE, BRIDGE TO INDIA research
Green energy corridors The first phase was launched in 2015 with a target to evacuate 20 GW renewable energy at a cost of INR 101 billion (USD 1.6 billion). Inter-state transmission works, mostly in Rajasthan and Gujarat, were completed on time but intra-state works have been delayed despite deadline extension by over two years. Phase II of the scheme was launched in March 2022 to evacuate 19.4 GW renewable power from seven states over the next four years at a cost of INR 120 billion (USD 1.6 billion).
Figure 2: Green energy corridor phase I progress as of October 2021
Source: MNRE, BRIDGE TO INDIA research
Renewable energy zonesThe REZ scheme was launched in 2019 to provide land and transmission infrastructure for 66.5 GW renewable project capacity across seven states – Rajasthan (20 GW), Gujarat (16 GW), Andhra Pradesh (8 GW), Maharashtra (7 GW), Karnataka (7.5 GW), Madhya Pradesh (5 GW) and Tamil Nadu (3 GW). Current status is not known.
Land and transmission issues are expected to intensify over time presenting one of the most serious challenges to growth of the renewable sector. Unfortunately, the policy makers have missed a trick by ignoring potential of rooftop solar, agri solar, other distributed renewables and floating solar. A recalibration of the sector growth plan along with long-term, proactive planning is essential to address these problems.Read more »
After more than a decade of exceptionally benign macro-economic environment, the global financial markets are facing greater disturbance and volatility. With natural steady state of the economy shaken first by COVID and now the Ukraine war, a domino effect is in play affecting inflation, cost of capital and exchange rates across countries. Inflation has soared to recent highs due to a combination of factors including increase in oil & gas and other commodity prices, trade wars and supply side disruptions. Monetary tightening by central banks has led to interest rates spiking up around the world. The 10-year Indian gilt yield has widened to 7.4% since touching a low of 5.9% last year. The Rupee has been falling sharply against USD, now down 11.5% since January 2022 and an annual average of 4.6% over last ten years. Yields on USD-denominated green bonds, the mainstay of debt financing for larger project developers, have more than doubled in last six months to 10-11% levels.
The last decade was unprecedented in macro-economic terms – extremely low inflation and interest rates on account of ample monetary easing by central banks and shift in manufacturing to China. But now that the economy has turned, the investors are in a state of panic. There are concerns about mounting deficit and leverage at both sovereign and corporate levels. There is greater risk aversion and migration of capital to safe havens further compounding volatility in asset prices and risk premia.
Figure 1: Exchange rate and bond yields
Figure 2: Annual changes in inflation indices, %
Source: S&P Global, RBI, BRIDGE TO INDIA research
For the renewable sector, timing of these developments coming on top of increase in equipment costs, supply side blockages, BCD on solar cells and modules, ALMM, transmission line stay order in Gujarat and Rajasthan besides the usual policy uncertainty in open access and rooftop solar markets is far from favourable. Project financial models have long done away with any contingency for macro-economic parameters. On the contrary, project developers have been building overly optimistic assumptions on inflation (5% or less), interest (8% for Rupee debt) and exchange rates (limited hedging, 3% annual depreciation). We estimate combined effect of adverse movements in macro-economic parameters at around 15-20% of project value.
Table: Impact of recent macro-economic developments on renewable project values
Note: Inflation impact excludes increase in price of core products like solar modules and wind turbines.
The macro-economic tide has added to the aggravation caused by sector specific issues. There are some signs of commodity price easing but it seems fair to assume that overall geo-political and economic volatility is here to stay for some time. The industry needs to re-calibrate its approach to macro-economic risks and build sufficient buffers to guard itself.
Finally, we wish all our subscribers a joyous Diwali with lots of happiness and good health!Read more »
CEA, the apex power sector planning agency in the country, has released draft National Electricity Plan with a detailed assessment of sector requirements for the next ten years (until FY 2032). The plan, revised every five years, lays out generation and transmission capacity growth roadmap to aid system planning and facilitate coordination between various government departments. The plan is based around two core sets of assumptions – demand growth and share of renewable power in the total energy mix.
Energy requirement and peak demand are projected to grow at CAGR of 6.3% and 6.0% from FY 2022 to 2,538 billion kWh and 363 GW respectively in FY 2032. Share of renewable energy is consistent with the new RPO targets (43.33% in FY 2030) and accordingly, CEA has estimated capacity addition for solar, wind, hydro, thermal and nuclear power as 279,480 MW, 93,600 MW, 21,839 MW, 35,014 MW and 15,700 MW (see figure below).
Figure: Planned growth in generation capacity, MW
Source: Draft National Electricity PlanNotes: Figures inside the chart indicate planned capacity addition in each five-year period. Thermal capacity addition numbers are net of planned retirements totalling 4,259 MW capacity by FY 2027. Biomass capacity numbers (10,682 MW as of Mar-2022) are excluded.
Other key highlights of the plan:
Average annual solar and wind capacity addition of 34,516 MW over next 5 years is about 3.5x the rate over previous five years.
Offshore wind capacity addition is pegged at 10,000 MW by FY 2032.
Gas-fired power output is assumed as static at current levels (16% PLF), a missed opportunity to recoup investment and improve grid stability.
Back-ending of storage capacity: Only 2 GW of new pumped hydro capacity and nil BESS are anticipated until FY 2027, going up to 10 GW and 52 GW respectively in the next five years to FY 2032. Total battery storage requirement of 258 GWh by FY 2032 is significantly at odds with the Energy Storage Obligation (ESO) target recently laid out by MOP.
To us, the entire exercise appears utterly surreal because of the overly optimistic power demand growth assumption of 6.3% set against the decarbonisation context and when viewed against historic trend – 4.0% over last ten years and 5.0% over last twenty years. As a result, all generation numbers look overblown. The fear is that such numbers provide support to new thermal power investment plans particularly because of long lead times and multiple execution, financial and policy related challenges faced by the renewable sector. NTPC and other public sector entities have already started new rounds of fresh thermal project investments. Coal India is working to boost coal production at a CAGR of 4.3% to 1,058 million tonnes by 2032. Indeed, the Union Ministry of Mines is planning to double coal production by 2032. Investment in these expensive legacy assets risks further undermining growth of the renewable sector.
When viewed together with backtracking on renewable sector targets and Prime Minister’s announcement at COP 26, the National Electricity Plan is sending conflicting policy signals. The government is even refusing to confirm any firm targets for renewable power capacity. The need of the moment is for the government to be decisive, call a complete halt to new thermal investments and provide comprehensive support to the renewable power sector.Read more »
SECI has completed auction for a standalone 500 MW/ 1,000 MWh battery storage tender, the first of its kind. The project would be located in Rajasthan near Fatehgarh sub-station, a major solar power hub with total connectivity of 14 GW. JSW Energy has won the full capacity in a tight auction process with an availability-based tariff bid of INR 13 million (USD 162,000) per MW per annum. Other bidders in the auction included Acme, Hartree, Eden, Sterlite, NTPC, ReNew and Azure. In another standalone storage auction for a 10 MW/ 20 MWh project last month by Kerala State Electricity Board (KSEB), Hero’s bid of INR 13.5 million per MW per annum was declared the winner. Other bidders included O2 and Tata Power.
Figure: Bid results for SECI and KSEB storage tenders, INR million per MW per annum
Source: BRIDGE TO INDIA resaerch
We find both winning bids to be extremely aggressive in view of recent hikes in battery cost and stiff performance penalties. The winners may be banking on capital cost reduction but that seems unlikely in the foreseeable future. Key project parameters for SECI tender:
Despite keen bidding, levellised cost of storage is estimated at over INR 10.00/ kWh raising immediate questions about viability for offtakers. In an amendment to the original tender, SECI had reduced contracted capacity of the project from 70% to 60%. POSOCO has committed in advance to contract 30% of total capacity suggesting strong government support for the project. We expect low interest from DISCOMs as tariff differential between peak and off-peak power on the exchanges, even though up sharply over last few years, is still well below the storage cost at about INR 4.50-8.00/ kWh (see figure below). It is likely that the government would intervene to line up support from some friendly states and/ or central PSUs for the remaining 30% capacity. The developer is required to find alternate uses for the 40% uncontracted capacity. Most likely, JSW Energy would use it for internal captive consumption in the group steel business.
Figure: Hourly prices on conventional Day Ahead Market, INR/ kWh
Source: Indian Energy Exchange, BRIDGE TO INDIA research
Another consideration in assessing demand is MOP’s recently recommended storage target as part of 43.3% RPO trajectory for FY 2030. The 1.5% target for FY 2025, going up to 4% by FY 2030, entails setting up storage capacity of about 35 GWh and 122 GWh by March 2025 and 2030 respectively. These are extremely ambitious numbers. While the government may line up all necessary support to see the first major storage tender sail through successfully, high cost is a significant barrier for future tenders. We believe that policy support should be initially weighted towards RTC tenders rather than standalone storage projects aided by a carefully planned carrot-and-stick approach to ensure demand from DISCOMs.Read more »
The US Congress has passed a landmark law which aims to provide a massive boost to the clean energy sector. The law seeks to reduce clean energy costs, spur technology innovation, create jobs, incentivise domestic manufacturing and adoption by consumers. Total funding provision over next 10 years is USD 369 billion (excluding loan guarantees) mainly in the form of tax credits:
Investment and production tax credits for energy generation from solar, wind, nuclear and geothermal sources, energy storage and green hydrogen facilities
Production tax credits worth USD 30 billion and investment tax credits worth an additional USD 10 billion for US manufacturers of clean energy products including solar panels, wind turbines, batteries, and critical minerals processing
USD 60 billion aid for disadvantaged areas affected by climate change including USD 27 billion for community clean energy projects
USD 100 billion loan programmes for financing production of EVs and up to USD 250 billion in loan guarantees for clean energy producers
Home energy rebate programmes worth USD 9 billion to reduce consumer costs
Tax credits and grants for industrial consumers transitioning to clean energy
Investment of USD 20 billion in climate-smart agriculture and USD 2.6 billion to protect and restore coastal habitats
Even though the final law is a sharply pared back version of the original draft, it is mammoth in scope and ambition. Besides hard incentives and funding provisions, it has significant soft initiatives focused on creating clean hydrogen hubs, promoting recycling research, supporting low carbon materials produced domestically, undertaking inter-disciplinary industrial decarbonisation research and designing a new carbon-based trade policy to keep out ‘dirty’ products. Interestingly, the new law makes no mention of any federal carbon tax or emission trading scheme.
Preliminary estimates suggest that the law would reduce net US emissions by about 40% below 2005 levels, compared to 27% under previous policies. Renewable power capacity addition is expected to get a big boost with almost 4x increase to an average of about 100 GW per annum over next 10 years. Module manufacturing capacity is expected to jump from 7 GW at present to 37 GW by 2025 and 50 GW by 2030. The two criticisms are aimed mainly at support for carbon capture and storage, a long-touted technology but still unproven at commercial scale. It is also feared that the generous loans and loan guarantees could lead to wasteful use of taxpayer money.
The US is not alone in scaling up clean energy ambitions. Increasing weather extremities and concerns about air quality, energy security and affordability particularly since the start of the Ukraine war have jolted everyone. The European Union’s REPower EU plan, announced in May 2022, aims to accelerate green energy transition by setting up 723 GW renewable capacity by 2030 to attain 45% renewable power share. China recently announced plans to add 1,200 GW renewable capacity by 2030.
Between the US, EU and China, the revised targets amount to an average annual renewable capacity addition of about 310 GW per annum, more than double the progress over last five years.
Figure: Renewable power capacity addition in key international markets
Source: IRENA, BRIDGE TO INDIA researchNote: Figures include hydro power capacity.
From an Indian perspective, the US law offers lessons in policy making particularly about the importance of technology research, job creation, recycling and trade policy. US incentives for domestic manufacturers, investors and consumers are in stark contrast to tariff and non-tariff barriers in India, which are constraining the market.
Overall, the international efforts towards technology innovation and scale up should bring down costs for Indian consumers too. But rapid sector growth is bound to intensify competition for minerals and metals, funds, skills and expertise. India will have to work harder to compete in the global marketplace and manufacturing domains. Moreover, other countries’ attempts to boost domestic production are a setback for Indian companies eyeing the lucrative exports market.Read more »
After resisting growth of net metering and open access markets, DISCOMs seem to be now turning their focus on ‘behind the meter’ (BTM) installations, a key engine of growth for the rooftop solar market in the last few years. Maharashtra and Gujarat DISCOMs are asking consumers seeking open access project approvals to switch BTM systems to gross metering mode effectively making them financially unviable. Some Rajasthan DISCOMs have even started levying electricity duty, cross subsidy surcharge (CSS) and additional surcharge (AS) on BTM systems with the same end result.
Switching from BTM to gross metering mode reduces effective saving potential of rooftop solar installations drastically from variable grid tariff (INR 8.48-13.08/ kWh and INR 6.80-7.39/ kWh in Maharashtra and Gujarat respectively) to gross metering tariff (INR 3.00/ kWh and INR 1.75/ kWh in Maharashtra and Gujarat respectively). The reduction renders all such systems, almost without exception, as financially unviable. The levy of electricity duty, CSS and AS totalling INR 3.35 – 3.52/ kWh in Rajasthan has the same end result. These measures are particularly harmful for OPEX-based installations, which are being forced to shut down in many cases.
As net metering policy became increasingly restrictive over the last few years (see figure), BTM installations became the default mode for setting up large rooftop solar systems – often over 1 MW in size. We estimate that a total of 2,211 MW rooftop or other onsite solar capacity has been installed in this mode spread mainly across Maharashtra, Rajasthan, Gujarat, Madhya Pradesh, Karnataka and Tamil Nadu. In the absence of any formal policy clarity (eligibility criteria, technical requirements, approval process, applicability of grid charges and surcharges etc), consumers and OPEX solution providers market have conveniently taken the view that there was no restriction on BTM systems for 100% self-consumption and no requirement to bear any grid charges. Historically, the only formal requirement for such systems has been to obtain approval from local safety inspector depending on prevailing policy in addition to installation of a simple relay to prevent injection of power into the grid.
Figure: Net metering connectivity size limit for C&I rooftop solar systems
Source: BRIDGE TO INDIA researchNote: In Karnataka and Madhya Pradesh, net metering is not available for OPEX business model. Tamil Nadu and Uttar Pradesh offer only net billing and gross metering to C&I consumers. West Bengal provides net metering to C&I consumers but with a system size limit of only 5 kW.
The changes in policy stance are blatantly ad hoc and creating confusion in the industry. That these changes are being applied to older installations without any prior warning and forcing them to shut down is outrageous. Elsewhere too, DISCOMs continue to deny or delay project approvals, impose ad hoc certification or reporting requirements and levy charges in defiance of official policy framework. The regressive actions by DISCOMs are another reminder of high policy risk in the corporate renewable market.Read more »
After having seemingly binned the Electricity Act, 2003 amendment bill last year, the government has sprung a surprise by reviving it. A new draft has been tabled in parliament but immediately sent to a standing committee for wider consultation amid opposition from other political parties, state governments and other stakeholders. The central feature of the bill, as last time, is proposed delicensing of the distribution business. The proposal is to allow new players to enter distribution business and supply power to end consumers by riding distribution networks of incumbent DISCOMs for a fee. The new players shall seek approvals from state regulators but based on criteria specified by the central government rather than state governments.
The Bill has several other provisions relating to streamlining of tariff determination process, ensuring full cost recovery by DISCOMs, constitution of state regulators and more power to regulators pari passu with civil courts. These provisions are broadly similar as last time but there are two main changes. The first one relates to requirement for all power purchasers to maintain adequate security of payment prescribed by the central government. If the power purchasers fail to maintain the prescribed payment security, power would not be scheduled and despatched to them. The other main change is enforcement of a uniform RPO trajectory across the country although financial penalties for non-compliance are proposed to be reduced by more than 50% to INR 0.25-0.35/ kWh in first year and INR 0.35-0.50/ kWh in subsequent years.
Main objective of the Bill clearly (and rightly so) is to restore financial condition of DISCOMs, which has been deteriorating steadily putting all sector initiatives at risk. The innumerable financial support and reform packages announced to date have been to almost no avail. ICRA estimates that total DISCOM debt has increased from INR 4 trillion (USD 50 billion) to INR 6 trillion (USD 76 billion) in the last five years while there has been no improvement in payment status to IPPs.
However, the proposed delicensing solution has a fundamental flaw. The incumbent DISCOMs would continue to own and be responsible for all legacy PPAs, distribution network and associated costs. Running a full service distribution business and providing a parallel service to new competitors introduces a severe conflict of interest. Managing that conflict – sharing of power supply, granting network access and maintaining a cross subsidy balancing fund on an equitable basis – is going to be a herculean challenge. It remains to be seen if integrity of this process can be maintained particularly as the state governments see a natural incentive in DISCOM mis-governance and using cheap power to lure voters.
The government has mistakenly abandoned the other two potential routes of making DISCOMs financially viable – privatisation and separation of content and carriage. Each route is fraught with unique challenges but the delicensing solution is almost too complex to be workable. Failure to implement with due rigour would be a recipe for endless regulatory disputes and confusion. Given the magnitude of the problem and its widescale implications for economy, we believe that the government needs to build a consensus on sector reform and possibly change course.Read more »
Since announcing the goal of achieving net zero emission status by 2070 in November 2021, the government has taken first tangible step in that direction. A bill has been introduced in the Lok Sabha to amend the Energy Conservation Act, 2001 to mandate use of non-fossil fuel based energy sources and establish carbon credit market in the country. It defines applicability threshold as all industrial, commercial and residential consumers with a minimum connected load of 100 kW or contract demand of 120 kVA. The bill is mainly a directional policy document; detailed rules would be issued separately.
Key highlights of the bill:
i. Energy consumption targets would be set for different types of consumers;ii. Financial penalties would be imposed on entities failing to meet targets;iii. Manufacturing or import of specific equipment failing to meet energy consumption standards would be banned; andiv. Regulatory jurisdiction will lie with state electricity regulators.
In India, there are already two different schemes indirectly targeting decarbonisation by industrial and commercial entities. All thermal power consumers are required to procure a minimum specified share of power from renewable sources or buy Renewable Energy Certificates (RECs). The Perform, Achieve and Trade (PAT) scheme requires specific businesses in energy intensive industries to comply with energy efficiency standards or buy Energy Saving Certificates (ESCERTs). As the following table shows, the REC and ESCERT markets are tiny in scope, coverage and market value.
Table: Comparison between REC, ESCERT and carbon trading certificate
Source: IEX, BRIDGE TO INDIA research
The new carbon trading scheme is expected to be significantly larger in comparison. It would also inevitably have significant overlaps with both REC and ESC schemes. For example, if a company increases renewable power consumption and reduces its emissions as a result, will it be entitled to both RECs and carbon credits? It is vital for policy clarity and market efficiency that the three schemes are merged into a single scheme. A unified approach with a consistent emission based denominator would also act as useful guidance to energy consumers evaluating investment decisions in alternate decarbonisation technologies.
There are currently 32 carbon markets – covering 17% of global GHG emissions – operational around the world. In 2021, traded volume and value jumped sharply to 15,811 million MT (plus 24% YOY) and EUR 759 billion (164%) respectively. Europe accounts for 90% of total activity because of stricter enforcement and more mature market. Prices in different markets range between EUR 16-65 per tonne or about INR 1.30-5.20/ kg.
Figure: Total value of global carbon markets, EUR billion
Source: Carbon Market Year in Review 2021, Refinitiv
A detailed study of different global carbon markets should offer useful lessons for Indian policy makers. Designing the scheme, setting targets, defining standards, trading protocols, and developing inspection and monitoring capability will require careful consideration. The government would also need to play a critical enabling role in developing technology, skilling and financing expertise for decarbonisation efforts.Read more »