Renewables and energy transition require massive funding. The immediate task for pure-play renewable producers, fossil fuel-based power majors and others will be to properly assess the variety of funding models on the table.

In our view, structures with tight ring-fencing, cash flow waterfall and security package may qualify for a project-finance approach.

This FAQ examines the methodologies we apply to determine ratings, factors affecting power-purchase agreement renewals in Australia, and how market prices influence these projects. We also discuss the risk assessment of different energy forms, particularly solar and wind, and their potential to obtain investment-grade ratings. Lastly, we explore the assumptions used in debt amortization.

This report complements another FAQ, "Assessing Project Finance As Way To Unlock India's Renewables Potential."

Frequently Asked Questions:

How are lenders, issuers, and investors driving the emergence of different funding platforms in Australia?

Funding models are evolving according to the needs and actions of each group.

Lenders:  They traditionally provide funding for under-construction and operating assets. They are increasingly focused on single borrower/group limits, and expect higher capital charges for long-term projects, especially those involving large transition and growth funding needs for existing and new clients.

Issuers:  They usually get funding for construction from banks, and free up bank limits by seeking funding from the capital market for operational projects. There are huge growth opportunities as the share of regulated assets gradually decreases.

• Fossil fuel-based power majors are increasingly focusing on segregating green finance investments to realize better pricing and widen their investor base.
• Renewable players are focusing on developing diversified cost-efficient, replicable funding platforms to segregate under-construction and operational assets.

Investors:  They were traditionally indifferent to fuel mix and more focused on long-term stable cash flows or structural protections for market-based pricing structures. An increasing focus on transition and climate risks has led some investors to divest all existing positions in fossil fuel-based electric companies, put a cap on new positions, or adopt transition funding.

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Do you apply a project finance methodology or a corporate methodology when determining ratings?

It depends. Many Australian renewable power companies, for instance, are evaluating different funding structures. In our view, ringfenced structures with identified assets (either under construction or operational), cash flows, and covenant packages can be considered for project finance ratings.

Structures that have minimal additions to the initial asset base may still align with our project finance methodology. This depends on factors such as strict qualifying conditions (covering factors such as asset technology, counterparty risk, market risk, etc.), a rating affirmation test, and clearly defined debt limits.

However, we may use our corporate methodology where the following factors occur: structures with loose restrictions, with the flexibility to inject a large pool of assets into a ring-fenced structure or restricted group over time with different technology, counterparty, and credit risk considerations.

What assumptions do you apply to the renewal of contracts for power-purchase agreements (PPA), in terms of price and quantity?

We would generally not assume that contracts are renewed at the end of the PPA term as generally the PPAs in Australia give option to both parties. However, there could be exceptions depending on the terms and conditions of the PPA contract. We will make assumptions for both volume and prices at the end of the contracted phase/onset of the merchant phase. This would not only drive outcomes for the debt-service coverage ratio (DSCR), but also affect the market risk and resiliency assessment.

Both factors are important. Market risk increases the overall risk profile through an operations phase business assessment (OPBA) of the project. Weak resiliency to downside can effectively cap the rating outcome.

To what extent does the track record of the sponsors influence your view?

It's a key input and can positively influence the way we assess risk under our corporate framework. For project financing, other factors also come into play. The project would still face price risk, which we would consider when conducting the market risk and resiliency assessment. We take into account any contractual framework that requires minimum contracted volume amounts. This can mitigate volume risk.

How do PPAs help renewable projects manage the effect of changing market prices?

Most of the renewable energy projects we have seen in this market tend to either fully or partly mitigate merchant price exposure through PPAs.

Some projects could enter into contracts for 100% of their capacity if they were part of a portfolio, whereas others might want to optimize profits and contract only a portion of their capacity. That said, the PPAs entered into by these projects are generally for a duration of five to 10 years, which is much shorter than the average expected life of these renewable assets (more than 20 years). This exposes the project to a long merchant tail and potentially to spot prices once the PPA term ends.

Structural changes in the market mean we cannot forecast power prices by using historical correlations. Volatility of wholesale spot power prices has jumped over the past few years because of the influx of large renewable energy capacities (both solar and wind), as well as the withdrawal from the market of certain baseload coal-fired generation capacity.

We also believe the forward prices will have to be adjusted periodically subject to the addition of new renewables projects to the grid, transmission constraints or enhancements, or a rise in storage options, to name a few factors.

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How does this affect your merchant price assumptions?

We make our forecasts based on our view of the forecast power prices of the rated portfolio. Further, we focus on the capture price for the project rather than the wholesale power price. We consider the market structure, demand supply situation (and other factors) as well as forecast merchant prices based on the independent expert's report/opinion and subsequent discussions.

That said, we would review the underlying assumptions used by the independent report provider. We would expect this report to consider factors such as:

• Demand outlook;
• New development pipeline;
• Retirement of existing thermal generation fleets;
• Fuel prices;
• Cost of new technologies (hydrogen, offshore wind farms) and existing ones (onshore wind farms, solar photovoltaic, batteries); and
• Government policies.

How would you differentiate market pricing according to time, resources, and other factors?

We may adjust our forecast prices to reflect key differences in our assumptions and will frequently revisit these assumptions to adjust our forecasts over the life of the project.

Over the long term, we expect power prices to move according to the pace of growth of renewable energy and their levelized cost of electricity. Many factors can cause big variations in power price forecasts. These may include change in weather patterns, delays in approval, construction/expansion, and the commissioning of new generation capacities and transmission networks. Unplanned outages of older less reliable coal-fired plants will also affect prices.

Moreover, merchant renewable projects may face a price cut compared with the average daily baseload price. This is because almost all the renewable energy plants would generate electricity during similar hours of the day (unless battery storage becomes economically viable to smooth the supply). As a result of this cannibalization, the supply could increase, causing downward pressure on prices during those hours.

Why do merchant renewable projects, particularly grid-scale solar plants, generally experience lower average weighted prices compared with average baseload prices?

This is a key consideration for grid-scale solar plants, compared with wind. That's because most solar output, both rooftop photovoltaic and grid-scale solar, occur in the same periods. Long-term energy service agreements (LTESAs) aim to provide an indexed floor for downside. If the future baseload prices fall, then these plants would call on the LTESAs.

This discount on average baseload price is even less of a risk for geographically diverse wind farm portfolios. This is because wind speeds in one area may only be moderately correlated with those in other regions. By contrast, solar loads are highly correlated within and across the mainland national electricity market (NEM) regions and highly concentrated at midday. This explains their larger discount to the average base-load price and to the average weighted prices for wind.

We expect the difference between the average baseload prices and the average dispatch prices for renewable energy projects to persist unless large battery and pumped hydro capacities are added. These additions could help manage periods of high supply, particularly during the day when we expect more instances of negative or low prices.

How do you measure and factor in curtailment risk?

Economic curtailment usually happens when supply is high and demand remains low. Our merchant price assumptions typically account for economic curtailment. Curtailment can lead to lower earnings and cash flows that can suppress the DSCRs. Grid constraints as well as the number of negative price occurrences in the NEM region have jumped, leading to higher curtailment.

We factor in curtailment risk in our analysis based on the track record in the local market, our assessment of the grid stability, market conditions and additional inputs from the independent expert's report/opinion. We would also examine the underlying assumptions used by the independent report provider for forecasting curtailment risk.

These assumptions should consider a variety of factors, including:

• The coincidence with solar photovoltaic output and other wind outputs within the region;
• New generation projects in the region;
• Capacity and condition of the existing transmission line;
• Expansion/upgrade plans for the network;
• Any new transmission lines expected to be built in the region to relieve congestion;
• The effect on the supply curve with battery/storage solutions, etc.

Given that renewable energy plants have nil to very low marginal running costs, it would be economic for them to produce until the power price is positive. Renewable energy producers would continue to produce even when prices are negative, given the current environment and legislation on large-scale energy certificates (LGCs) in place until 2030. This is on the condition that the negative price is more than offset by the price of the certificates that the generator can obtain by selling them in the market.

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How do you assess the market risk of solar versus wind?

Our view of market risk for merchant renewable energy projects primarily stems from the exposure of the project to power prices, transmission-related curtailment and the competitive position of the project.

We generally use the same energy yield estimates that we would use under the base-case assumptions: that is, one-year P50 (generation level likely to be achieved at least 50% of the years) or P90 (generation level likely to be achieved in 90% of the years). We typically apply the price stress for a period of two to five years, in line with our criteria. We also factor in cyclicality associated with power projects, where we may incorporate multiple stress periods to simulate business cycles over the life of the project.

The market risk outcomes for solar and wind projects could be materially different. The starting point of the prices used for merchant solar versus wind under our base case would likely be different. Similarly, the stressed prices would also reflect the varying generation profile, time of day, price etc., which can result in different outcomes.

Why do you see solar energy projects as having a slightly weaker competitive position than wind projects?

For two reasons. First, on the demand side, peak demand in Australia generally occurs in the evenings when solar is not generating. Secondly, on the supply side, utility-scale solar competes directly with rooftop solar photovoltaic panels. In addition, solar loads are highly correlated within and across the country's mainland NEM regions.

In comparison, wind speeds are not completely correlated within regions and could lead to a different generation profile. Also, wind farms could be generating during the evening peaks, which works well as demand-supply would be more at balance during these times compared with solar farms.

As a result, the OPBA of a merchant solar project may be comparable with a merchant wind project. This is because solar photovoltaic panels are comparatively easier to operate than wind farms and their lower asset class operation stability risk may offset greater market risk.

Can these merchant risk projects obtain investment-grade ratings?

It depends. The outcome depends on the nature of protection afforded by the contractual position and the coverage ratios to offset the higher market risk for merchant projects.

Some of the mitigating factors on the financing aspects could include: (1) large amortization of debt within the contracted period of the PPA; (2) strong liquidity with plenty of reserves that can support long periods of stress; and (3) a flexible debt repayment structure to manage price volatility, including cash sweeps during periods of high DSCRs.

Of course, there could be exceptions to this higher DSCR threshold, under which the starting point could be lower.

The overall risks associated with merchant renewable energy projects, be they solar or wind, can lead to an OPBA assessment of at least 7 or 8, in our view. Based on this indicative level of OPBA, the required minimum DSCRs to get to an investment-grade credit profile would be at least 1.60x, along with an expectation that the project would also survive our moderate downside resiliency assessment. Higher market risk, curtailment etc. can further push up the OPBA and the required DSCR levels to achieve investment grade rating.

What are the specific factors for your downside assessment of renewables?

For our resiliency analysis, our starting point is use of P99 generation profile. However, we could adopt a P90 generation profile, in cases of significant historical track record, significant site specific data spread across a portfolio of assets.

We would also simulate additional stresses such as lower availability, as well as performance degradation, both of which would affect generation volumes.

The NEM in Australia, for instance, has undergone many structural changes. Historically, coal-fired generation, together with gas, has formed most of the power supply and hence more frequently set the prices across the regions.

This has changed over the past few years. Wind, solar, and batteries have set the prices for about 10%-25% of the time. This essentially means the historical 20-year low price is not indicative of future prices. The intermittency of renewables has also caused increased volatility, which makes it harder to establish a particular price to use when forecasting downside sensitivity.

What assumptions do you use for amortization of debt?

All projects must retire the debt before the estimated useful life of the project. We will consider the actual debt amortization profile for projects with a fully amortizing debt structure.

While we calculate DSCR based on contracted amortization for projects with cash flow sweep, we will reflect significant overdependence on cash flow sweeps by notching down. We do this to reflect inflated DSCRs (due to lower contracted amortization), since overall project cash flows remain the same.

And what about projects that lack a debt amortization profile or that have a bullet structure?

In this case, we will assume an amortization profile. We can consider a notional debt amortization profile as per an issuer's expectations if it reflects the expected amortization.

For projects exposed to merchant risk, we generally assume the debt will fully amortize three to five years before the end of life. This is because the tail period can provide the project with additional flexibility to service debt in case of unforeseen stress and lack of cash flow visibility far in the future. We also consider refinancing risk for projects with bullet/unamortized debt.

Alternatively, we could also adopt amortization with fixed repayments that each comprise both principal and interest. We may also consider project debt amortization in proportion to project cash flows for lack of a better measure.

For solar photovoltaic and onshore wind farms, we typically assume an asset life of up to 25 years. That said, we may consider longer asset life for assets/technology with a longer track record based on certain project-specific factors or an independent engineer's opinion/report.

Either way, we assume that at the end of the period, the principal is fully repaid.

Editor: Lex Hall

Related Research

• Credit FAQ: Assessing Project Finance As Way To Unlock India's Renewables Potential, Feb. 22, 2024