By harnessing its great wind and solar power potential, Chile has set a target of producing 80% of its energy through renewable sources by 2030, while decommissioning all of its coal plants by 2040 to achieve carbon neutrality by 2050.

The government created the Small Distributed Generation Means (Pequeños Medios de Generación Distribuida (PMGD]) framework in 2006 for projects generating up to 9 megawatts (MW). Distributed energy is a type of decentralized electrical generation performed by small grid-connected or distribution system-connected generators. The projects that operate under this framework are self-dispatched, receive transmission toll reductions, and have access to a stabilized price regime, which is less volatile than the spot market prices. As a result, the framework allows smaller players to participate in the energy market, while helping to diversify the pool of generators in the system and to expedite the energy transition process.

Wind and solar farms were almost nonexistent in Chile 10 years ago. However, according to the National Energy Commission's (CNE's) March 2022 report, they currently generate 9,718 MW (or make up almost 35% of the country's energy capacity). In addition, projects totaling 4,090 MW are currently under construction and will likely start operations before December 2024. The number of assets operating under the PMGD framework has risen at an average compound annual growth rate of 36% in 2006-2021, reaching close to 1.7 gigawatts (GW) as of March 2022, accounting for around 17% of the non-conventional renewable projects in Chile (see chart 1).

Chart 1

The multilateral lending agencies and Chilean commercial banks have been financing the construction of such plants, setting a precedent in the country's energy market and making PMGDs a viable option for developers and investors. Currently, S&P Global Ratings rates privately six project finance entities operating under this framework, all of which are solar power parks with investment-grade ratings. Here, we address the frequently asked questions that we have received from the investor community regarding our views of the regulation, stabilized prices for power generated by PMGD projects, and our rating approach to PMGD assets.

Frequently Asked Questions

Which type of projects are eligible for the PMGD regime?

The framework applies to power generation projects, with a total capacity between 500 kilowatts (kW) and 9 MW, operating under the Dec. 8, 2020, Decree 88 that superseded the 2005 Supreme Decree 244. There are two types of assets that can operate under this framework:

• PMGDs that are connected to the facilities of a distribution company or those of a company that owns electricity distribution lines; or
• PMGs (Pequeños Medios de Generación or small generation means) are connected to the main transmission, sub-transmission, or additional transmission grid.

As of March 2022, installed capacity of both types of assets totaled 1,706 MW and 321 MW, respectively (see charts 2 and 3). While the predominant asset type for PMGs are small hydropower plants, solar parks are the most frequent type for the PMGDs, accounting for about 71% of this framework's installed capacity in Chile (see chart 3).

Chart 2

Chart 3

What are your views on the stabilized prices?

The price under the PMGD framework has historically been more stable and predictable than the spot price, given that approximately 75% of the former is correlated to the average power purchase agreements (PPA) prices in the Chilean electricity market. The remaining 25% of the stabilized price is based on a 48-month projection of the system energy marginal cost (basic price of Energy), which CNE calculates every six months (January and July) using average hydrology conditions in the country.

The projects can opt between operating under the PMGD/PMG framework or sell energy at the spot price, but they can make such a decision once every four years. During 2006-2016, no generator opted for the stabilized price regime, mainly because real hourly marginal costs were expected to be higher than stabilized prices. Market expectations began to change in 2015, mainly due to the construction of the high number of renewable projects, as well as lower projected demand growth.

The chart below shows our forecasts of the stabilized and spot prices in Chile in the Polpaico 220 kV node. The stabilized price accrued by each project will ultimately depend on the node of energy dispatch. In this sense, we might expect some marginal variations depending on each project's location.

For the calculation of short-term stabilized prices, we consider a contract price of $50 per megawatt hour (MWh) for the non-contracted energy, which in our view, is in line with the latest contract renegotiations. For the medium- to long-term prices, we consider a range of $50-$60 per MWh because we believe that future auctions would promote the development of new base-load thermal units, given that at certain point the existing ones wouldn't be sufficient to supply the growing demand securely and economically because of a high number of operating renewable projects.

The stabilized prices tend to decrease following the trend of the existing PPAs. For instance, in the medium term, the regulated PPAs awarded in the 2015 and 2017 auctions will be in force with average contract prices of $48/MWh and $32/MWh, respectively, pushing the prices down. After mid-2034, we forecast a 10%-15% price decrease associated with the new calculation formula (see below the question about the framework's regulatory risk).

Chart 4

What are your views of construction and technology risks for these small solar and wind assets?

In our view, counterparty risks make up the bulk of construction risk, given that contractors are typically small companies with highly leveraged balance sheets. Although we believe they are generally replaceable, given the short construction period of solar and wind farms and their low technological complexity, along with multiple readily available alternative contractors, we analyze construction by assessing the amount of available liquidity embedded in the project for the potential counterparty replacement. For example, the rated PMGD projects have a liquidity cushion (excess funds) of almost 20% of the engineering, procurement, and construction (EPC) contract price. That, in our view, is sufficient for these projects to be rated at investment-grade level, even if the creditworthiness of the construction companies is weaker. We have also seen that some PMGD projects faced delays to be connected to the grid by the distribution companies. We expect that this would continue to be the case, particularly because of the high and increasing number of PMGD projects in process of connection. From a rating perspective, this is currently not an issue because we view the distribution companies in Chile overall at investment-grade level.

Technology risk is another important credit factor, given the innovative and rapidly evolving nature of wind and solar energy technology. For instance, the PMGD projects that we have analyzed have been increasingly using bifacial photo-voltaic (PV) panels, and we expect this trend to continue. We view technology as satisfactory, although the bifacial PV panels are relatively new in the market, and field data isn't sufficient to provide as accurate information on costs and performance estimates as that of monofacial panels. We also believe that the panel quality can vary by manufacturer. We typically capture these risks in the degradation assumptions that we incorporate into our base- and downside-case scenarios. (For more, see below the question about these scenarios).

Finally, most of the PMGD projects that we have rated have obtained all the necessary environmental and right of way permits. The latter are also an important rating factor, given that large areas are necessary to build the wind and solar parks, while potential delays in receiving approvals can push back the start of operations.

Some of the projects we analyzed include simultaneous construction of several assets in the portfolio, in some cases under different EPC contracts. In these situations, we generally assess each construction process separately and we determine the construction phase of the project as the weakest link.

What's your view of the framework's regulatory risk?

In October 2020, the government amended the PMGD regime through the Decree 88. The price calculation now incorporates six four-hour time intervals during a given day with respective pricing, in contrast to the previous calculation that didn't make distinctions based on time of dispatch. Once the new price scheme comes into force, it could hurt several projects that will be forced to sell energy when the system's prices are lower, such as solar parks that generate during the day. We estimate that, under the new formula, the price that PMGD solar assets charge could decrease by 10%-15%.

The new price scheme includes a transition period, under which the PMGD assets that obtain the construction declaration before October 2022 would continue to sell under the previous price formula until October 2034. All the projects that we have analyzed so far fall under the pricing transition period.

We will continue monitoring any development in the PMGD framework. We expect that any potential modification of the framework would be accompanied by a grandfathering period compatible with long-time investments and financings, preventing harm to performance of projects that are already in operations and/or under and advanced level of construction, similarly to the transition phase of the changes imposed in October 2020. This is also consistent with our view of the Chilean regulatory framework that has a long track record of maintaining stable, and transparent and predictable rules.

What are the main assumptions in your base- and downside-case scenarios?

The main factors of our financial analysis of PMGD projects are the following:

• Energy production forecasts: No or limited operating data for PMGD assets exists. Therefore, our assessment incorporates information that can provide us with a long-term view of resource adequacy, including reliable data available for the project site, and an experienced independent expert's statistical assessment of the resource and electricity production. For solar projects, the typical base-case assumption for power production probability is P90--an electricity production amount that would be exceeded 90% of the time when assessed statistically over a one-year period. We tend to use a one-year average period, rather than 10 years or longer, because financial structures of the projects require them to service debt once or twice a year. Our downside-case scenario stresses the solar resource according to a P99 one-year average rate of production.
• Degradation rates of the solar panels: Solar panel degradation refers to the reduction in power output over time, given the panel's reduced ability to convert sunlight into electricity, typically expressed as a percentage of total output per year. This factor reduces our base- and downside-case assumptions for production, and consequently, cash flows. Our view of degradation depends on many things, including quality of materials used, the manufacturing process (the more manual one increases the risk of performance issues such as soldering problems), the choice of technology, the quality of installation, and our assessment of operations and maintenance (O&M) costs. Based on the independent expert opinion on the panel quality among the rated PMGD projects, we have used annual degradation rates of close to 0.5%, This is because high-quality manufacturers, such as Trina Solar Co. Ltd. and Canadian Solar Inc., have provided the panels. In the downside-case scenario, we increase the annual degradation rate by 25 basis points reaching 0.625% per year.
• Plant availability and O&M expenses: For newly constructed assets, we consider the amount of output and performance that's likely to be typical for solar assets in Chile and the independent expert opinion, when available. Over time, our base-case scenario also takes into account actual operating results. In addition, the O&M contracts generally end prior to the debt's maturity. This is an important factor to monitor because as the renewable energy industry grows rapidly, demand for specialized labor can ratchet up O&M expenses. In the downside-scenario, we generally increase O&M expenses by 12%.
• Inverters' replacement: Based on track record of existing assets, we typically consider a 10-year lifecycle for inverters. We consider if the transaction structure provides for cash reserves that are accumulated over time and sized to fund the replacement or refurbishing of the inverters at a certain time. In some cases, such reserves are funded with the debt proceeds, and in other cases, with the project's cash flows. In the latter case, we would include such expenses in our debt service coverage ratio (DSCR) calculation, given that inverters are mandatory for the proper operation of the solar assets.

Table 1

Do PMGD projects have any material revenue counterparties?

The counterparties responsible for the payment of the revenues are the power generators. If any counterparty ceases to operate, the industry regulator would ensure the continuity of the service and the payment chain. Although we don't view any counterparty as material, we wouldn't rate any PMGD project above 'BBB', the rating level of Enel Generacion Chile S.A., the Chilean power generator that has the strongest creditworthiness among its domestic peers.

How do you assess the projects' relatively small size?

Given the relatively small size (up to 9 MW) of the assets eligible to operate under the framework, the PMGD projects generally have a portfolio of various assets. Typically, there's a certain number of existing assets in the portfolio at the financial close, while the project would incorporate additional ones after it issues debt, subject to the fulfilment of its Assets Eligibility Criteria. The Eligibility Criteria covers key technical, permitting, and legal requirements, including a debt sizing criteria. This is to ensure that, once the project adds assets to its portfolio, they wouldn't change our view of the project's business and/or financial risks. For instance, 5 out of 6 rated PMGD projects have assets that are likely to generate approximately 20% of the capacity that projects expect to reach in the next 12-18 months. We assess this as a credit-neutral factor due to the projects' adherence to the Eligibility Criteria.

Are there any relevant topics related to the financing structure of these assets?

The financing structure of the PMGD projects generally have the following additional characteristics:

• Gradual disbursement of the committed debt, which is subject to the incorporation of assets in the portfolio that meets the Eligibility Criteria. We view this as neutral from a credit standpoint, because if the size of the portfolio is finally lower than originally expected, the total debt amount will also be lower, and DSCRs wouldn't change.
• Many of the rated projects are exposed to refinancing risks, because we don't expect that they will have sufficient cash flows to pay down the debt at maturity. On average, the rated projects will have a balloon of 60% at legal maturity. Consequently, we define a refinancing period that increases risks for the project, particularly in relation to the refinancing rate. In general, we generally add an extra spread of 2.5% during that period.
• The debt among the rated projects has a variable interest rate, with a hedge of around 80%. Our downside-case scenario includes certain stress to the benchmark rate. This has no rating impact, given the projects' sufficient liquidity reserves, in the form of a six-month debt service reserve account (DSRA).
• All the rated projects have a backward- and forward-looking dividend lock-up test, averaging 1.25x.

How do you rate the PMGD projects, considering all the mentioned factors?

The key steps in our project finance rating process are summarized in paragraphs 10-12 of our "Project Finance Framework Methodology" (see also chart 1). First, we establish a project's stand-alone credit profile (SACP)--an assessment of its intrinsic creditworthiness. The SACP is the lower of our assessments of the project's construction phase SACP and operations phase SACP. To arrive at the final rating, we adjust the SACP according to our assessment of factors related to the transaction structure, the likelihood of extraordinary government support, relevant sovereign ratings, and full credit guarantee, if there's one.

The chart below shows in greater detail how we determine the operations phase SACP.

In assessing the operations phase SACP, we first determine the project's business risk profile, the operations phase business assessment (OPBA). The OPBA can be thought of as a measure of how risky a project's operations are. This assessment ranges from '1' to '12', with '12' representing the highest risk. Then, we evaluate the financial risk and other factors such as counterparty risk.

The following are the main factors in determining the OPBA:

• Performance risk assessment: We determine this by analyzing asset class operations stability (ACOS)--the risk that the project's cash flow will differ from our expectations--and then adjusting for several factors including resource risk.
• Market risk assessment: Market risk only applies when the project's cash flow available for debt service (CFADS) could decline by more than 5% from our base case to our downside case due to market risk. In such cases, we assess the project's market exposure (an assessment of its CFADS volatility due to market forces) and its competitive position.
• Country risk.

For solar PMGD projects, we assess the ACOS at '2', which mainly reflects the risk of operating small-scale solar parks, which we view as less complex than operating wind farms, for example. We also assess the exposure to resource risk as modest, which is the standard for solar assets, given the typical characteristics, track record, and volatility of the resource availability. Overall, we assess the OPBA of PMGD projects at '4' or '5', depending on our assessment of market risk, which would range between very low and low, given that the CFADS would vary less than 20% in the long term under a market downside scenario.

We combine the OPBA with minimum DSCR from our base-case financial forecast (as described in the reply to the question about the scenarios) to arrive at the preliminary operations phase SACP, as detailed below. We view the rated PMGD projects' financial strength as consistent with the 'bbb' category.

Table 2

To determine the operations phase SACP, we also assess the likelihood of the project meeting its financial obligations in a downside-case scenario. It includes stresses to macroeconomic, operating, and industry variables, as outlined in the reply to the question about scenarios. The rated PMGD projects generate DSCRs close to 1x in a downside scenario, relying on a six-month DSRA to finance any potential cash shortfall, which we view as a rating strength.

Appendix