The World Of Renewables Has Dramatically Changed

Over the past two decades, the credit of many renewable financings have benefited from often-high-priced power purchase agreements (PPAs) or feed-in tariffs (FIT) and proven technology. In common with other new assets types, renewables have encountered challenges. For example, there have been significant credit losses with reversals in FIT policies in Spain and Italy, and PG&E went bankrupt (see "Suppliers In The Dark As PG&E Weighs Pulling The Plug On Power Supply Contracts," March 14, 2019). Furthermore, technology challenges and underestimations in operating costs and resource risk have resulted in reduced cash flows and rating actions.

Despite these teething problems, renewables have come of age and S&P Global Ratings expects the asset class to grow in capacity and with improving efficiencies and cost competitiveness. Even when factoring in massive renewable investments, but equally recognizing the likely increase in power demand by 40% over the next two decades, S&P Global Platts Analytics forecasts that over 50% of power produced will still come from fossil-fired generation by 2040 under its most likely scenario (compared to close to two-thirds today). Under Platts Analytics' two-degree scenario, the share of fossil-based generation comes down to 30% by 2040.

Certainly over time there has been considerable de-risking of all types of renewable projects, ranging from solar and onshore wind to, more recently, offshore wind. These trends have, however, resulted in thin lending margins and materially lower returns for investors. The drop in costs also has meant that governments are less willing to subsidize tariffs, with more competitive auctions and an inclination toward merchant pricing.

To mitigate the new risks posed by future renewable projects, lenders want both corporate PPAs and the availability of a floor price. Structuring corporate PPAs remains complex as projects cannot readily absorb the variance of generation due to resource risk (at least not on a short-period delivery basis), while buyers need to have certainty of supply. Consequently, outsourcing the balancing needs to a utility, traders, or aggregator, remains fundamental. Other challenges are the lengthening of corporate PPAs to tenors above 10 years, allowing for a higher share of debt-funding.

On a related note, counterparty risk has increased. Given the long-term visibility of their business models, utility and infrastructure companies are ideal off-takers, but more and more corporate entities seek to source part of their electricity needs from renewables. They often are less keen to enter into very long-term contracts or require more contractual flexibility.

The end game for renewables remains linked to innovation and technology, as battery storage development, automation of grids and aggregating of assets, and dynamic supply management of renewables should ultimately transition renewables from an intermittent source to closer to base-load (with a lesser need of back-up requirements).

Given the challenge of the energy transition ahead, we believe government policies will need to remain dynamic and supportive, to stimulate investment, grant permits, and reduce risks. Even if the asset class remains attractive, the need for investment is huge and the pace of transition cannot be taken for granted if returns become too thin (notably if current abundant liquidity decreases), or material merchant risk is on the rise, and, finally, if the consumer is not onboard in terms of affordability and access to land and location.

Growth In Renewables Transitioning From Sprint To Long Distance

Worldwide investments in renewable energy infrastructure assets have been astronomical and at quite a sprint, totaling $2.6 trillion from 2010 through 2019 according to Global Trends in Renewable Energy Investment 2019, by BloombergNEF (BNEF) and the United Nations Environment Programme. Globally, renewable capacity additions outpace fossil fuel with solar emerging as the dominant technology. Key drivers of this meteoric growth have been government and corporate policies (as expressed through FITs, tax incentives, and PPAs) to meet clean energy goals, as well as declining installation costs, with economies of scale that are leading to grid parity.

Despite the strong historical growth, in May 2019 the International Energy Agency (IEA) announced that renewable additions had plateaued in 2018; for the first time since 2001, there was no year-on-year growth. And recently, Platts Analytics announced a further reduction of over 10% year-on-year in 1H2019 across major markets (see S&P Global Platts Analytics' Global Solar PV Market Outlook (2019-2025), Aug. 16 2019). The aggregate numbers in the chart mask what has been happening in key markets and within the subsectors of renewables, such as:

• China's decision to address grid integration issues and control costs by reducing incentives slowed growth in solar.
• Changes in incentives led to slower growth of onshore wind in India and solar photovoltaic (PV) systems in Japan.
• In Europe, the phasing out of FITs for onshore wind, biomass, and solar projects has slowed the growth rate in countries like the U.K. and Germany.
• The U.S. grew modestly, reflecting in part that many of the states have met the initial renewable portfolio standards that were set.

Table 1

Table 2

The pause in growth is notable given how much decarbonization of the power generation sector is needed to meet to meet climate change goals . To meet these goals ,investment in renewables will need to increase significantly over the current run rate. BNEF/CERES (in "Mapping the Gap: Financing the Path to a 2°C Future," 2016) estimated the necessary increase in funding will be $5.2 trillion from 2015 to 2040, over a current base line of $6.9 billion.

Chart 3

Emerging markets will account for the lion's share of the increased amount (about $4.3 trillion), as shown in chart 4.

Despite the slowdown and other headwinds that might materialize (such as reduced demand due to the impact of any recession, and wider adoption of energy efficiency), we expect investment growth to pick up, driven by:

• Climate change-related policies;
• Lower costs of renewables driving grid parity;
• Higher oil prices;
• Demand for electric vehicles;
• Developments with battery and other storage;
• New technologies such as offshore wind floating platforms; and
• Innovations in financial markets.

Corporate PPAs Are On The Rise Globally

As companies pursue their stated sustainable policies while also seeking competitive terms, reliability of supply, and the cost benefit of subsidies such as production tax credits in the U.S. or Renewable Portfolio Standard requirements in the U.K., the number of corporate PPAs has grown.

There are still speed bumps to growth in some jurisdictions. For example, FITs (where the government supports certain technologies by offering to purchase their generated power at rates higher than the market prices) are a disincentive to the development of corporate PPAs. Furthermore, some jurisdictions have laws that require all power to be purchased from national utilities or limit large corporate purchasers from buying power from a single supplier over an extended timeframe.

The U.S. and U.K. were early leaders in the growth of the corporate PPA market, but markets like Sweden, Spain, Mexico, China, and India are taking off. Corporate PPA tenors vary market to market; however, in the majority of cases, there is still not sufficient appetite from the counterparties to sign long-term PPAs covering the whole financing's life.

Chart 5 

The delivery of power under corporate PPAs falls largely into two types:

• Direct: The generator and corporate customer are on the same grid, albeit the power is typically wheeled through a third-party utility.
• Indirect: The generator is in a different region from the corporate customer. The generator sells power to its local utility and the customer buys power from its different local utility. There is a financial settlement between the generator and corporate customer.

In terms of credit risk, corporate PPAs share in common many of the same issues that traditional renewable PPAs with utilities face and additionally have other credit aspects to consider.

Traditional renewable PPAs were contractual arrangements between a developer-owned project and a utility with the following typical characteristics:

• Power was generated at the projects and wheeled to the off-taking utilities. The projects were typically financed with long-term debt that was supported by the long term PPAs through the tenor of the debt.
• Payments under the PPA were very predictable and covered operating expenses.

Table 3

It is not surprising that with a large diversity of corporate companies entering the space, there is an increasing number of innovations being proposed. For example, Microsoft Corp. (a major PPA user) announced in October 2018 the launch of a Volume Firming Agreement (VFA) that transfers weather-related risks to insurers. The product was created with REsurety, Allianz, and Nephila Climate as a complimentary product to the PPA. Another example is that of kWh Analytics' Solar Revenue Put. This is a credit enhancement that seeks to guarantee the production performance of solar assets.

Great Reliance On Merchant Financing Could Increase Credit Risk

Historically, renewable financing was supported by stable cash flows from FITs and traditional PPAs, with a tenor in line with the rated-debt maturity. Stable cash flows from investment-grade off-takers were a key support to the investment-grade ratings we assigned. As the renewable sector matures, with increasingly competitive costs versus thermal, and more jurisdictions are meeting their sustainable goals, some markets are tilting towards a market-driven approach, including merchant assets. The pace of change varies country to country, as does the appetite of investors to have such exposure.

Chart 6

There is some similarity to what happened in the U.S. in the 2000s with the rise of independent power producers and liberalization of markets. Today the U.S. has a significant number of merchant-supported financings, and most of those we rate are non-investment grade with the exception of hydro projects. Furthermore, such financings extensively use the term loan B market as a source of funding. The term loan B market is primarily found in the U.S. and has grown over time.

Increasingly, FIT schemes are no longer seen as the most efficient way to support renewables, as tariffs were not always aligned with the technology changes (and costs declines). Additionally, FITs resulted in growing the burden on end-user electricity prices.

Some governments are using auctions as a transitional step towards more market-based pricing. Through auctions, governments are able to set a more sustainable trajectory for renewable additions, including grid constraints or other supply/demand considerations.

Other governments, such as Spain, are pushing further into merchant financing for renewables. It awarded 8.7 gigawatts (GW) of new renewables contracts in 2016 and 2017 that may not receive any long-term government subsidies (see "The End To Subsidies: The Beginning Of A New Era For Spanish Renewables?" Feb. 7, 2018). Projects are being financed through the balance sheets of the companies or through project finance schemes, and some of them are without any PPAs. Such is the case of X-Elio, which, in March 2019, raised project finance debt for a greenfield solar PV portfolio of 421 megawatts (MW). The portfolio consists of 10 facilities that it won in the Spanish government's renewable energy auction in July 2017. The debt package for the portfolio, which does not have a PPA in place, is €203 million and was provided by Banco Sabadell, S.A. Institucion de Banca Multiple, and CaixaBank S.A. (Source: Inframation.)

Another example of a long-term merchant financing is the 21.5-year senior term loan provided to a special purpose vehicle named Zero-E Spanish PV, which is 100% owned by Zero-E Euro Assets. Zero-E is a subsidiary of Grupo Cobra and the €434 million funds were committed to build an 864 MW Spanish PV portfolio. The assets are part of the 1.55 GW of solar capacity Grupo Cobra won in Spain's third renewable energy auction, held in 2017. The transaction closed in August 2019, with Natixis S.A., Banco Santander S.A., Banco Bilbao Vizcaya Argentaria S.A. (BBVA), and CaixaBank providing the debt. (Source: Inframation.)

Sponsors may need strong balance sheets to fund the new renewables schemes being awarded, and project financing may be more challenging to structure, due to the implied volatility of earnings and the limited leverage potential, unless they manage to sign credit-supportive and long-term PPAs with third parties. However, in some emerging markets the appetite for PPAs or availability of large private off-takers may be more limited than, say, in the U.S. However, one can also argue that in these markets settlements of renewable auctions could stay high, as renewables developers need higher public support.

With greater exposure to merchant risk, we have observed structures with lower leverage and other risk mitigants such as cash sweep structures to pay down further debt if electricity prices are above or below forecasted scenarios. Some renewable auctions themselves can also be seen as mitigants, when settling at higher levels (for example, in Germany, where prices in recent wind and solar auctions have been trending higher).

In the absence of mitigants, greater reliance on merchant cash flows (market risk) will likely lead to an erosion of credit and even potentially undermine growth of renewables. Many of the merchant project we rate are non-investment grade. We have seen some exceptions, such as U.S. hydro deals (see "Credit FAQ: Hydropower Projects 101: How S&P Global Ratings Views The Risk Of Hydro," Jan. 12, 2017) and the offshore wind project WindMW GmbH.

WindMW is exposed to market risk only between 2027 and 2035, the assumed end of the asset life. Of course, forecasting cash flows in a merchant market more than a decade in advance is inherently challenging, especially in a market (Germany) that is in a state of considerable flux. However, we believe cash flows might drop by between 30% and 50% in a severe market downside case, but that a project like this would fare comparatively well because of a low operating cost position. The minimum annual debt service coverage ratio (DSCR) during the contracted period is nearly 1.4x, and this number ticks up later in our assessment. DSCRs exceed 2.5x during the riskier merchant phase due to lower debt outstanding, despite an expectation of weaker power prices.

Chart 7

The degree of exposure some of our ratings have to market risk is reflected in our project finance ratings methodology. We evaluate how much cash flows can vary from our base case to a market downside. The more volatile the cash flows the higher the market risk. In contrast, payments under fixed price PPAs or FITs tend to have stable cash flows and often no market risk. We also assess the project's competitive position, which is influenced by support and predictability, barriers to entry, delivery costs, etc. (see "Project Finance Operations Methodology," Sept. 16, 2014). As an example of how volatile the cash flows can be, consider the spot prices in Spain.

One of the challenges of selling electricity to the market directly will be the penetration of renewables at a certain time of the day, causing volatility in spot prices. This cannibalization risk exists for all renewable technologies, depending on the developments of each specific market. However, for solar this is even clearer since solar generally operates at the same time of day. Specifically for PV technology, this implies that the higher the penetration of PV assets generating, the lower the prices at the generation times. Hence, the capture price entitled for a PV asset could be well lower than a wind asset generating during the night. Consequently, this cannibalization effect could undermine the profitability of PV producers.

California's aggressive build-out of renewables has resulted in its now-famous duck-shaped supply curve (peaks in gross power demand are shaved off to a degree by coinciding solar generation).

Oversupply and/or insufficient transmission can lead to another credit risk: curtailment. Curtailment arises due to a number of factors, including emergencies on the transmission line, if the transmission line is overloaded, or if the transmission operator is optimizing plants that stay online during low price periods. The impact to credit can be material if there is an involuntary loss of production and payment. Traditional PPAs mitigate this risk by typically capping how much loss the generator faces. Absent mitigants, merchant generators are exposed to this risk, and we assess how much power might be curtailed. It varies market to market.

Financing Structures Continue To Innovate

The flow of capital to fund renewables in developed markets has been torrential and we expect continued growth. As the sector matures in developed markets and expands in emerging markets we anticipate increased financial innovation in this space.

So far we have rated a wide variety of vehicles being used to channel capital into renewable assets, including project, corporate, securitization, and fund structures. In addition to the traditional providers of capital such as banks and institutional investors, we are seeing new types of financial institutions provide capital (e.g., Hannon Armstrong Sustainable Infrastructure Capital Inc.).

While there are mega-sized renewable projects, many projects, such as distributed generation, tend to be fairly small, and we have seen bundling as a strategy that governments and sponsors turn to so as to achieve more efficient or alternative forms of financing in both developed and emerging markets.

Table 4

Emerging Markets: A Key Growth Area With Additional Credit Risk

Emerging markets range from investment-grade countries like Mexico and India to deeply speculative-grade countries. Some have local capital providers that are able to finance renewable assets--although even in these markets we see a desire to tap into larger pools of international money to optimize financing costs and flexibility; for example, the cross-border financing of 25 operational solar assets in India with 930 MW of total installed capacity across eight states owned by Adani Green Energy Ltd. (see "Presale: Parampujya Solar Energy Pvt. Ltd. Restricted Group," May 22, 2019).

Although there is significant capital interest in infrastructure, the credit risk of emerging markets makes it less attractive to institutional investors. Such elevated risks include political and regulatory uncertainty, embedded risks in government concessions, currency exchange rate risk, and policies that are often less developed and somewhat unpredictable. (See "It's Time For A Change: MLIs And Mobilization Of The Private Sector," published on Sept. 21, 2018). The recent temporary tariff freeze in Chile, for example, might be well absorbed by large conglomerates but might cause a cash flow burden to single asset renewable projects, and represents a disruption of the historical regulatory stability observed in the Chilean market (see "Regulatory Support Is Powering Latin America's Utilities," March 8, 2019).

Approximately 97% of total private capital investments mobilized by multilateral lending institutions (MLIs) in 2017 occurred in high- and middle-income countries, according to the MLI community's joint 2017 report "Mobilization of Private Finance." Mobilization among low-income countries increased only 4% in 2018, accounting for 3.4% of global private capital mobilization.

Table 5

Many risks holding back private investors could potentially be transferred to a third party. Credit enhancement aims to mitigate specific risks of a project that may weigh on its overall credit profile and therefore make that project less appealing to private-sector participants. We believe multilateral development banks will increase engagement with the private sector via credit enhancements to facilities private capital deployment. Plus, commercial insurers will likely continue to innovate to effectively deploy their capital across different projects and expanded geographies, and look at the whole capital structure beyond senior debt (see "It's Time For A Change: The Role Of Credit Enhancement In Mobilizing Private Investment In Infrastructure," Sept. 28, 2018).

The campaign to scale solutions for the financing of infrastructure in emerging markets is expanding. And according to investment bankers, multilateral development bank (MDB) officials, and government representatives working with the U.N.-affiliated Closing the Investment Gap Initiative (CIG) who spoke at a roundtable hosted by S&P Global Ratings on April 26, 2019, there are solutions in the offing (see "Emerging Markets Have Hope For Sustainable Infrastructure Projects, Roundtable Participants Say," May 7, 2019).

Technological Innovations (And Challenges) Continue To Emerge

Technological innovation continues to be vibrant in many areas of the renewable sector, driven by a desire for grid parity and fueled by gigantic expenditure. Technological change has been both incremental (where costs have been driven down or efficiencies driven up) and radical (with new types of technology being introduced).

Technology risk is an important credit factor for renewable ratings, particularly project finance ratings that are typically linked to the technological performance of the assets. Our approach to assessing technology risk is described in our construction methodology criteria ("Project Finance Construction Methodology," Nov. 15, 2013; see also paragraphs 13-17 of "Key Credit Factors For Power Project Financings," Sept. 16, 2014) and scores range from commercially proven to unproven. The latter can introduce significant credit risk absent robust mitigants.

Generally, when it comes to transactions that are seeking a corporate or project finance rating, we consider the technology predominantly proven, particularly if the issuer is looking for an investment-grade rating. We have seen portfolio transactions use a small proportion of technologies with limited or minimal track record; such is the case of Vela Energy Finance S.A. In these cases, we will discount cash flows from such technologies.

Not all innovations have gone smoothly. The rapidly evolving offshore wind industry has had setbacks along the way. Some turbine models are requiring major repairs, although whether this is just from normal wear and tear is unclear. Erosion on the leading edges of their blades, requiring removal and reconditioning, can not only disrupt generation but increase costs in the long term if the reconditioning was not forecasted in the first place. Although projects can benefit from contractual obligations from the turbine's manufacturer, it is not entirely clear if these will cover all costs, including additional labor and logistics work, and as a result these issues could have negative credit implications.

There are always new technologies entering large-scale commercial or utility applications. For example, there is a lot of expectation that battery technology that could accelerate deployment of renewables (see "Going With The Flow: How Battery Storage Economics Are Changing Power Consumption," Jan. 11, 2018). If we rate a financing that uses technology that we have not yet evaluated, we will need to form an opinion on how it will perform based on information either provided to us or available from public independent authorities--including field data, testing results, and any independent engineer opinions.

Table 6

Emerging Regulatory/Political Challenges In Asia

Regulatory uncertainties and political risks may reduce project returns unexpectedly and dampen investor confidence, especially in developing burgeoning renewable energy markets, as seen in Taiwan. Following local elections in November 2018, the island's regulator proposed a cut of offshore wind tariffs from 2019, and a production cap of annual full-load hours, which may hamper the efficient use of wind farms.

Earlier that year in China, under the mounting pressure of funding renewable subsidies, the government unexpectedly suspended the quota for new solar projects and further lowered the subsidy levels five months after the last cuts. This policy led to the slump of solar growth in China from the historic 53 GW new capacities in 2017 to 44 GW in 2018, with the hardest hit on the upstream and midstream manufacturers due to worsening capacity glut.

Payment delays in India are common but we are witnessing rising political risk with Discoms (state-owned distribution companies) under the new state government of Andhra Pradesh, which is attempting to renegotiate executed contracts, questioning the must-run status of renewables, and resorting to curtailment in order to avoid paying under the PPAs. This puts the fundamental longstanding credit protections for the Indian power sector at risk.

Last but not the least, trade protectionism may create headwinds for renewable growth. The U.S. is likely to continue with import tariffs on crystalline-silicon PV cells and modules, inverters, and other materials from China. On October 22, the exception for bifacial modules ended. India also significantly raised import tariffs on PV modules from China and Malaysia; the potential increase in investment costs casts doubt on India's ambitious target of 100 GW solar power by 2022.

Issues Of Repowering And Lifetime Extension

As the renewable energy industry matures, asset owners need to decide what to do with their seasoning assets. We are observing different strategies such as lifetime extensions, repowering, and decommissioning.

Lifetime extensions for wind farms and solar plants are becoming more of a trending topic of discussion as the choice to decommission might mean disregarding some clear benefits, including the extensive operational track record and associated performance data, connection to the grid and, most probably, the small amounts of debt outstanding.

Alternatively, repowering wind turbines by replacing either components or the entire turbine, is regularly viewed by operators as a viable option to face the rising operation and maintenance expense of aging equipment. Wind turbines repowering has improved output by up to 25% while extending turbines' lifespans by as many as 20 years, according to General Electric (source: EIA).

The current U.S. tax code also favors repowering. Owners of repowered projects can become eligible for the Federal Production Tax Credit (PTC) should the repowering encompass at least 80% of the turbine's value. This threshold furthermore affords owners the flexibility to replace individual components without decommissioning the entire asset. The National Renewable Energy Laboratory forecasts annual repowering expenditures of $25 billion by 2030. In Europe, repowering is incentivized by a dearth of attractive locations for greenfield wind projects. As assets approach the end of their lifetimes, it can be more favorable to repower than to invest in a new turbine elsewhere. Furthermore, as existing sites have historical data documenting their performance, investing in a repowering project bears less risk than investing in new turbines at unproven sites. There's also the fact that available sites could become scarcer in more mature markets.

While there are advantages to repowering, some markets may be more conducive to lifetime extensions. Given the relatively low energy prices forecasted over the next 10-15 years, the potential additional sales may not justify the investment required to repower a turbine. Instead, asset owners seeking to remain in operation may favor lifetime extensions, supported by the operational track record and associated performance data, connection to the grid, and, most probably, small amounts of debt outstanding.

Although lifetime extensions do not generally increase the asset's capacity or lifetime to the extent of repowering, lifetime extensions require significantly less investment, affording owners greater financial flexibility. Should prices increase over the short-term, owners retain the option to invest in less costly lifetime extensions that enable them to capture the benefits of increased prices without committing to a long-term operation, which would involve greater price uncertainty. In Europe, the absence of meaningful government subsidies or tax benefits equivalent to those available in the U.S. cements repowering as the costlier alternative, further encouraging lifetime extension. This may change as PTC and the U.S. solar investment tax credit (ITC) phase out per current legislation.

The Need For Storage And Hybrids Is Abundant, And The Right Technology Seems To Be In View

Regardless of the dispute for the best renewable alternative--either solar or wind--batteries are the third piece of the triangle among industry players. Compared to thermal plants, wind and solar assets experience intermittency issues; as such, batteries could solve the intermittent nature of these resources.

As of today, the predominant technology for energy storage is the hydro reservoirs--either pumped hydro or large hydro plants, which could be dispatched when the solar or wind assets are not operating. Still, these assets are supplying energy in the countries they are located in, and as such their use as availability storage (to reduce solar and wind intermittency) would depend on a complete shift of the energy matrix.

Currently there are few large-scale batteries projects worldwide. We expect this to change dramatically in the next five years, led largely by diminished costs. Furthermore, the development of batteries could get a boost from policies towards carbon emission reduction and by the growth of distributed generation.

For example, in the U.S., storage is already cost competitive for short-duration solutions that include fast-response ancillary services and frequency regulation. Moreover, we see C&I peak-shifting installations as the most economical because of rate arbitrage opportunities (i.e., under a time-of-use (TOU)-based variable-rate structure there is an incentive to shift or shave peak demand). Furthermore, grid storage to integrate renewables or substituting peaking gas assets are also competitive in markets like California, where we now see the possibility of no further natural gas-based peaking generation construction.

Chart 9

In India, the State of Andhra Pradesh was evaluating an Integrated Renewable Energy Storage Project (IRESP), comprising 2 GW of solar power and 2 GW of wind energy capacity, with pumped hydro storage capacity of 8 GW. The project shall be designed for a discharge duration of eight hours. However, the new state government is reconsidering the project and could potentially scrap it.

We believe storage will become a key tool in global efforts to decarbonize the power sector in the years to come. Along this line, we believe there will be regulatory support to develop hybrid solutions of batteries/wind and/or batteries/solar to unlock the full potential of renewable energy in each jurisdiction, creating a solution that contributes to grid stability and to the balance of pricing to cover peak demand.

Grid Price Parity Is In Focus, Especially For China and India

Grid parity is achieved when levelized costs of electricity (LCOE) of renewables are on par or even lower than the incumbent sources of generation, and government subsidies are no longer needed. When grid parity is achieved, deployment of renewables tends to become more sustainable. We have seen this in some or most renewable projects that are awarded through competitive bidding in many areas of the world, including India and China.

Technological innovation has been behind the drastic decline in construction costs, improving efficiency (such as solar conversion rate) and utilization. On top of that, the decrease in financing costs and other nontechnical "soft" costs are important to achieving grid parity, which is positive for the long-term sustainability of the industry.

China, as the largest market of wind and solar power, is likely to remove the subsidy on new capacities of onshore wind power and utility-scale solar power from 2021, and offshore wind power from 2022 (see "China Clears The Air On Solar And Wind Subsidies," April 15, 2019, and "China's Subsidy-Free Renewable Energy Projects May Spur Debt Increase For Developers," Jan. 16, 2019). Indeed on-grid tariffs in some solar pilot projects have been lower than local benchmark coal power prices. However, the higher-than-expected growth of renewables results in sizable deficits in funding subsidies, and the prolonged use of subsidy receivables constrains the liquidity of developers and inhibits healthy industry growth. In this context, the government is keen to push grid parity by reducing the subsidies for new capacities more frequently, providing policy support for subsidy-free projects, reducing curtailment of renewables, and implementing the renewable portfolio standards and tradable green certificates in China.

We believe achieving grid price parity has been one of biggest drivers of growth for Indian renewables. Renewables in India are now competing not just for "greenness" but also price. Competitive bid prices of around INR 2.5/kwh for both wind and solar is now cheaper than the cost of coal plant tariffs at around INR 4/kwh. So the states are happy adopting more renewables. India has had renewable purchase obligations (minimum percent of share of renewable power out of total electricity consumed) for states for some years, but most states fell short of these targets; financially weak states were not able or willing to pay more for cleaner electricity.

The Indian government has discontinued FITs and subsidies for renewables since the industry can now compete on its own. India's renewable industry's good fortune is almost entirely driven by large domestic and international private sector investments, because of factors like:

• Falling capital expenditures and funding costs: A sharp fall in solar panel prices, rising efficiency of wind turbines, economies of scale for operations and maintenance, and lower cost of funding (down to about 9% of larger players from 12% earlier).
• Supportive policies like greater flexibility provided in new bids on choosing sites based on resource availability (rather than the off-taker's location), waiver of transmission charges for interstate renewable transmission, and stronger central counterparties making payments on time rather than the State Electric Utilities delaying payments. Renewables also enjoy grid priority.