Lessons from East and West: A juxtaposition of the Indian and US distributed solar market

 

Lessons from East and West: A juxtaposition of the Indian and US distributed solar market

Recently when Narendra Modi won his second term by a landslide victory, one of the Managing Partners at my firm enquired “The Indian government is still pro-renewables, right.”

The conversation took me back to the days when I was a part of the Indian renewable market. Over the past few months, I had been making mental observations on the similarities and contrasts I perceived between the distributed solar market in the US and India.

Both markets, though drastically different in scale and structure, have immense potential for solar and have made significant advancements in solar installations. While the US stands at 67 GW of installed solar, India recently crossed the 30 GW milestone. The US added about 10.6 GW of solar in 2018 and India was not far behind adding 8.3 GW. The rooftop potential in India has been estimated at over 60 GW. This number is dwarfed by the estimated rooftop potential of 1,118 GW in the US.  

India and the US are undoubtedly two of the largest and most exciting markets in the world, and they both have a lot to learn from one another.

Market composition   

US and India are vast markets which can be viewed as a collection of states with each state dictating the regulations that govern power market operations. Also, the individual states are culturally distinct, with the differences more exaggerated in India where C&I business may be conducted in the local languages.    

The very nature of the distributed solar business demands local engagement to contract and execute projects. The strategy for client acquisition that may work in California may not be as effective in Texas, and the art of securing business from a C&I client in Tamil Nadu (a southern Indian state) would differ significantly from that in Rajasthan (a northwestern Indian state). This has created an ecosystem of solar developers in both countries, working at the grassroot level. Several of these developers cross-sell solar – companies that cater to the on-site electrical and roofing requirements have the most synergy in cross-selling and have entered the active solar markets. This creates market efficiencies as solar financiers save on business development costs and the solar developers act as conduits for market competition. Both the countries have several small-scale developers, medium- and large-scale EPC firms, and a few reliable financiers.

One difference is that several developers in the US are sophisticated enough to present a comprehensive package to the financier including a signed PPA, technical due diligence and EPC agreements. Whereas in India, apart from some established EPCs, many small developers contribute to only lead generation and medium-sized consultants facilitate energy contracting. Understandably, not all solar owners and operators in India are willing or able to compensate some of the brokers’ asks (which at times can be significant enough to distort project economics) for the value add of ‘client introduction’. Also, the price levels in the US C&I market can accommodate multiple contributors in the value chain – this is not the case for India currently. Or perhaps, it is the lack of meaningful margin that makes this portion of the value chain unattractive for sophisticated developers in India. It is important to note here that this is despite the fact that soft costs for solar are significantly higher for the US market than for the Indian market – 1 MW solar capital cost in India can be as high as $0.60/W - $0.70/W while the soft costs in the US can easily surpass $1.00/W in some markets.

Low cost of capital, efficient procurement and speed of execution remain crucial to create a viable pipeline in both the markets. While the US C&I deals mostly remain financeable, the Indian C&I market (not to mention the utility-scale market) is stuck in a downward spiral. Credit-worthy corporate clients justifiably expect competitive PPA rates and large corporate clients, with high bargaining power and PR potential, will expect to contract at razor thin margins. Negotiations are protracted – RFP responses are simply considered first offers to be pushed down. The process and PPAs are not uniform, with some corporate customers bidding in their own blind reverse auctions to others structuring a six-month credit period for bill payments. In my opinion, such practices waste both the sellers and buyers’ resources and take a longer route to reach the same destination. Bidders will reserve a margin for negotiation, and the final negotiated price may be overly aggressive, in which case terms would have to renegotiated. This charade ultimately may mask the trade-off between price and project quality. More visible examples of a mismatch in investor appetite and client expectations are the recent cancellations of the utility-scale auctions conducted by the Federal-level Solar Energy Corporation of India (SECI) as well as State-level Renewable Energy Development Agencies. In both instances the market witnessed bids which the auctioning agencies deemed high enough to prompt cancellation over an award to the lowest bidder.  

Federal vs State

Since 2009, there has been a significant push from the Central Government of India to prioritize renewable energy. The stronger policy directive beginning 2014 was a culmination of increasingly attractive solar costs, problems beleaguering the tendered coal capacity addition, and an effort to reduce India’s GHG emissions. The Central Government introduced incentives, such as accelerated depreciation, to encourage investment.

The execution and operation of the projects however are conducted entirely within the regulatory ambit of the respective State Governments. Most state electricity markets in India are regulated and the State Distribution Company (known as Discom in India) holds the monopoly for supply. Most State Discoms in India are practically bankrupt because of the fundamentally convoluted structure of the electricity markets. C&I clients cross-subsidize (insufficiently) residential and agricultural consumption, and on top of that, that the commercial and technical losses are high. High electricity costs make solar economics attractive, but when C&I clients directly contract with solar financiers via behind the meter (BTM) capacity or the Open Access mechanism (Offsite Solar), not only are they taking revenue away from the State Discom, they are taking away the cross-subsidy keeping the system afloat.

State Discoms have tried but largely failed to deter large C&I clients from moving to solar. State Discoms have increased demand charges and introduced new surcharges that reduce savings. The invisible hand has so far prevailed, but the pushback from State Discoms creates a significant amount of uncertainty for the clients as well as investors. This has curbed C&I Solar’s potential and momentum, even in the states which have solar-friendly incentives.

On a separate but related point, some utility-scale solar plants which supply power to State Discoms have faced a similar, if not worse, fate. The State of Andhra Pradesh recently moved to renegotiate PPA tariff for operational solar and wind capacity contracted with the state Discom. To put this in context, this represents 3.2 GW of solar and 3.9 GW of wind, with their future cashflows at stake. Discoms reportedly owe renewable generators $420 million in late payments and dues.  

At this point in time, no amount of financial restructuring can repair State Discoms’ financials. The market itself needs to be restructured or rates need to be raised to make the Discoms solvent.

This presents some unique challenge for solar companies in India. Investors need to navigate complex and uncertain regulatory landscapes and take financially and politically calculated risks.

Now in contrast, in the US, though the Federal Government has incentivized solar with ITC, it is the State governments that have designed innovative structures to stimulate investment. Several active solar markets have mandated Renewable Procurement Standards (RPS) which incentivize solar at a state level. While Massachusetts has moved to create the complex SMART program which largely tries to design stable cashflows for solar, New York has introduced the complex VDER program which compensates solar based on several moving variables.

But not all states in the US have embraced distributed solar. Regulated markets controlled by large utilities have introduced and influenced policies designed to block large consumers from ‘defecting’ the grid (as utilities reason). As an example, companies like MGM and Switch have paid vast sums of money to leave their regulated utility in Nevada so that they could procure lower cost renewable energy.      

The difference is that the Indian State-Discoms pressure investor confidence for solvency, whereas the large regulated utilities in the US have mostly kept third-party solar at bay to preserve profits. Another critically important difference here is that while Indian State-Discoms try to rewrite the rules in the middle of the game, US market regulations, once introduced and implemented, generally provide a high degree of investor confidence. The important lesson here is that in a setup with Federal and State jurisdictions, renewable investments are less risky when there is a genuine state-level push for creating a conducive investment environment.   

Factors driving DG solar

In India, the primary motivation for solar procurement is savings in utility costs as well as maintaining compliance with Government-imposed RPS for large consumers in the Open Access system (Offsite Solar). Oddly enough, the Open Access system is strictly monitored by the State-Discoms for private solar PPAs, yet the State-Discoms themselves are not being held accountable for RPS compliance by regulators. PR is the secondary motivator, especially for multinational companies with publicized RE targets.

The US market operates similarly – it is mostly all about the economics, except for some companies voluntarily procuring RECs to offset their energy consumption with cleaner sources.  The voluntary market is all but non-existent in India, with State-Discoms not complying the with the required RPS.

One key aspect that differentiates the Indian market from the US market, is that Indian Industrial and commercial entities generally have backup generators on-site to ensure a 24-hour power supply. Currently, power outages in India are attributed more to grid inefficiencies than insufficient generation. Though many in the industry are of the opinion that once the economic growth cycle picks up in India, the current generation capacity may not be adequate to satisfy demand – as was seen in many states some years ago. This creates even more incentive for C&I clients in India to procure onsite generation.

Also, market structure supports offsite solar in India. As solar is designated as a ‘must run’ resource, simply submitting a production schedule (with penalties for significant deviations) and assessing technical loss calculations (benchmarks published by regulators) is enough for projecting offsite revenues. In the US, projecting offsite solar prices is vastly more complicated due to the number of different wholesale markets and the pricing zones within those markets.     

Outside of Utility-scale and C&I solar, distributed solar has the potential to bring energy access to millions in rural India who live with no or poor access to energy.     

Beyond economics, an interesting aspect which differentiates the two markets is how solar itself is viewed. India being a developing nation, consumers have embraced solar for the value it provides. Consumers are interested in understanding the production curve, tariff, technical aspects of BTM solar integration, and HSE compliance. Perhaps not having the luxury of viewing solar from an aesthetics/’nice-to-have’ point of view is an inadvertent advantage for the industry in India. US consumers can also help accelerate market adoption by viewing solar as a ‘utility’ which has value to provide rather than as property additions which may impact aesthetics.   

Lastly, there is immense interest in integrating solar with storage in the US market. While Indian market has not reached this point yet, Indian policies are moving towards creating a viable space for electric vehicles. As this market matures and battery costs decline, I expect the momentum will spill onto utility-scale and BTM storage integration.  

Financing and Risk sharing

The ITC in the US market creates a sophisticated but also more complicated financing structure, often extending the closing timeline. Also, the existence of the ITC requires viewing investments as a portfolio for back-leverage, as opposed to India where most assets are generally financed with non-recourse project-level debt. 

A remarkable difference between the two markets is how risk is shared between the various partners involved. The risk-sharing, in my opinion, is more equitable in the US C&I solar market. While the long-term owner of the asset necessarily takes on the longer-term risks of managing the asset for 30+ years, typically unreasonable risks are not passed onto the asset owners. Additionally, financiers with more risk appetite can fund projects with new technologies, lower credit or can be the early movers after major policy changes. There is a more balanced risk-sharing between clients, developers and financiers. That is not to say that this solar market does not witness resistance or unexpected risks. Regulated markets have placed significant entry barriers for third-party competitive solar providers, and large utilities can extend project timelines when they do not approve interconnection in a timely manner.

India presents a different picture though, one with significant regulatory risks. End-clients try to place the entirety of regulatory risk on asset owners. So, the financiers are sandwiched between clients demanding rock bottom PPA rates, while unwilling to share any regulatory risk, and EPC and O&M vendors who understandably cannot operate below cost. Meanwhile state-level regulators quietly assess the revenue-loss for Discoms to understand how best to stall the momentum with policy tweaks that negate any value add presented by earlier announced policies. It is worth noting that the earlier policies came with little expectation of garnering client interest or increasing investment in solar – thus creating these complications within the market today.

Several state-level policies in active solar markets are vague on whether certain additional charges or exemption from grid loss calculations are applicable for solar projects – providing a convenient option for the regulators to insert appropriate language if the need arises. Even in the hypercompetitive Federal-level rooftop auctions, financiers might have to factor in delay or default in solar subsidy payments (ranging from 30%-70% of capital cost) when submitting final bids. It doesn’t help that financiers cannot always depend on speedy legal recourse in India if policy changes or subsidy non-payment render a project economically unviable after the investments have been deployed.     

The impact of policy is also clearly demonstrated by the fact that PPA contract terms typically converge with incentive period. Policy exemptions in India typically range from 5-10 years. The asset owner takes on the risk of merchant exposure or of procuring post-PPA offtake. Whereas, in some US markets, the incentives provide certainty for 15-20 years.

Land: Lease or buy?

Land is a contentious issue in India. Land acquisition and unencumbered title transfer is one of the major bottlenecks in project execution. To avoid possible future conflicts or litigation, financiers prefer to buy land for projects in India. By contrast, many US C&I solar financiers prefer to lease land for projects, as this model is easier to execute. Landowners retain ownership and receive an annual income for the project lifetime.  

India too is trying to move towards a model in which agricultural land can be leased for solar projects – to supplement farmers’ income (over 50% of India’s population is employed in the agricultural sector). Some problems with this policy implementation could be that many poor farmers may not have the capacity to finance solar plants without expensive loans and State Discoms which would contract to procure the power may not make timely payments.

Conclusion:

Both these markets present huge opportunities for renewable capacity, because of the industrial scale as well as the need to reduce GHG emissions.

The Indian regulators can adopt best practices for policy formulation and implementation from the US. The regulators should embark on deep restructuring at the retail side to rescue Discoms and ensure reliable supply to industries and communities. There have been policy suggestions of unbundling distribution and retail to bring in competitive supply (this mechanism already exists in the city of Mumbai). Indian regulators and State Discoms also must realize the importance of maintaining investor confidence to attract much-needed capital for the long-term success of the market. If over the years, the electricity distribution is reformed, concepts like community solar, which is gaining steam in the US, can also become viable in India.

The US market, advanced as it is, would benefit from adopting a developing nation’s viewpoint on solar, and better appreciating the value and necessity of solar and other types of distributed generation. Also, with time if the soft costs of solar decline, solar will become affordable to a larger section of consumers. This momentum will continue to force the hand of utilities in regulated markets to remove barriers and adopt solar-friendly policies. All in all, both markets can learn a lot from one another and should be poised for significant long-term growth.

By: Shivapriya Balasubramanian