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    Fitch Downgrades Inversiones Latin America Power Limitada's Notes; Maintains Rating Watch Negative

    November 18, 2022 - ENP Newswire


      Fitch Ratings has downgraded Inversiones Latin America Power Limitada's (ILAP) USD403.9 million senior secured notes, to 'BB-' from 'BB+'.

      Fitch also maintained the Rating Watch Negative.

      The notes are supported by cash flows from two windfarms in Chile, San Juan, S.A. (San Juan) and Norvind, S.A. (Totoral).

      The downgrade follows deterioration of ILAP's financial profile resulting from spot price volatility and pressured working capital driven by the extension of the electricity tariff stabilization mechanism. The sharp increase in international coal and fossil fuel prices has upwardly pressured spot prices, eroding ILAP's liquidity position via unfavorable price mismatches at injection and withdrawal nodes. Transmission congestion and ILAP's highly contracted position compared to its generation profile have amplified the financial margin declines.

      The Rating Watch Negative reflects the potential for further negative rating action should cash generation be insufficient to cover the next debt service due in January 2023 and liquidity keep deteriorating, driven by detrimental market dynamics.

      Higher-than-expected spot prices and decoupling costs that further erode project liquidity by significantly depleting the reserve account would trigger further downgrades, while generation of cash that is adequate to cover debt service without further drawing upon reserves could lead to rating stabilization.


      The rating for ILAP's portfolio of two windfarms in Chile, San Juan (81% of total generation capacity) and Totoral (19%), reflects its mostly contracted position, averaging 73% of its revenues contracted with distribution companies (DisCos) through regulated, fixed-priced, long-term power purchase agreements (PPAs) and short-term bilateral PPAs through 2033. The transaction is exposed to profitability erosion risk due to varying prices between the energy injection node and the DisCo withdrawal node, which is expected to be mitigated over the medium term due to transmission network expansions.

      The rating is not limited by counterparty risk, as the projects' most relevant counterparties are either investment grade or DisCos under regulated PPAs, which benefit from protective regulatory step-in provisions. The transaction will also have a mostly merchant tail once the regulated PPAs expire in 2033, although this is somewhat mitigated by the long remaining useful life of the larger plant, San Juan, which Fitch assumes will end in 2042 (25 years total). Together, both farms have a P90/P50 differential of 13%, indicating moderate wind resource variability, and have performed at around P50 in most years. The windfarms have some curtailment risk, which is expected to persist going forward.

      Both farms have presented an adequate operating track record and benefit from long-term, fixed-price service and availability agreements with Vestas Chile, guaranteed by Vestas Wind Systems A/S, which is considered an experienced O&M contractor. The overall debt structure is solid, with a mandatory amortization schedule complemented by a partial cash sweep up to a target debt balance. Refinancing risk exists by way of a balloon payment that is expected to be equal to roughly 16% of the original value of the notes under Fitch's cases.

      Under Fitch's rating case, debt service coverage ratios (DSCRs) are no longer commensurate with the previous rating of 'BB+', with an expected rating case DSCR of 0.5x for the second half of 2022, which implies the use of reserves will be critical, and an average and minimum rating case DSCRs of 1.2x and 0.9x, respectively from 2023 onward.


      Robust O&M Agreement Provides Comfort (Operation Risk - Midrange): Vestas Chile, which is supported by a guarantee of its parent company, Vestas Wind Systems A/S, is a provider of equipment and O&M contracts and has a long and proven track record with the plants' technology. The plants benefit from a comprehensive service and availability agreement (SAA) with fixed and defined costs, including scheduled and unscheduled maintenance covering the majority of the life of the debt.

      The SAAs also provide minimum availability guarantees of 97% for both windfarms in 2021 and of 98% for San Juan starting in 2022. However, the transaction will be exposed to re-contracting risk once these agreements expire, in 2037 for San Juan and 2029 for Totoral, which could lead to increases in costs or lower availability guarantees. Life extension programs are planned for both farms to add to their useful life, bringing them up to 30 years, although Fitch has assumed a maximum of 25 years for conservatism per applicable criteria. A three-month O&M maintenance reserve account (OMRA) supports the structure.

      Evolving Track Record (Revenue Risk - Volume: Midrange): Both farms benefit from a resource forecast that considers operating history, with a longer track record considered for the smaller windfarm, Totoral, having started operations on 2010. Both farms have P90/P50 differentials of 13%, indicating moderate wind resource variability. San Juan has a shorter operating track record and has been exposed to wake effect since 2020 due to the construction of neighboring windfarms.

      Although wake effect remains a risk for this plant, losses have been conservatively estimated by the project's independent engineer (IE), included in the resource forecast utilized by Fitch. Both plants are also exposed to some curtailment risk, which is expected to continue as additional renewables incorporate themselves into the system.

      Long Term PPAs Mostly Contracted with Fixed Price (Revenue Risk - Price: Midrange): The plants have some merchant exposure during the life of the notes given that the majority of revenues (around 70%) are contracted through long-term, inflation-linked, fixed-priced PPAs. Price exposure mainly originates from the differential between injection node and withdrawal node. This is because the company earns the injection price where the plants are located, north of Santiago, and pays the withdrawal price for most of its PPAs in Central Chile, where the majority of the energy demand is located. The withdrawal price is generally higher due to the concentration of energy demand.

      The transaction will have a merchant tail post-2033 to retire the remaining debt after the balloon payment is refinanced. Spot prices are expected to be capped in the long term through the entry of more renewable energy projects and newer technologies, such as batteries, that would lower the marginal cost of energy production.

      Solid Structure, Some Refinancing Risk (Debt Structure - Midrange): The debt is amortizing with manageable refinancing risk. The plants will benefit from a legal amortization schedule complemented by a partial cash sweep up to a target debt balance. Failure to meet the target debt balance is not an event of default, therein providing flexibility to the transaction in the event that certain years perform below original expectations.

      Under Fitch's base case, the balloon payment would be equivalent to 16% of the original amount of the notes, which is considered a moderate refinancing risk exposure. The transaction benefits from an adequate covenant and security package, including a 1.2x backward- and forward-looking dividend distribution test. The project's six-month debt service reserve account (DSRA) also provides some comfort to the structure.

      Financial Summary: Debt service coverage ratios (DSCRs) are no longer consistent with the previous rating of 'BB+'. DSCR for the second half of 2022 is expected to be 0.7x and 0.5x under our base and rating cases respectively. From 2023 onward, these metrics average 1.3x, with a minimum of 1.1x (in 2023) under our base case and an average of 1.2x with a minimum of 0.9x (in 2023) under our rating case. Refinancing risk is mitigated by a project life coverage ratio (PLCR) of 2.3x and 1.5x, for our base and rating cases respectively, at the time of the notes' maturity in 2033; this is considered adequate versus applicable criteria to offset potential merchant volatility after 2033.


      Fitch considers other wind energy generation projects in the region as peers for this project, such as Energia Eolica S.A. (Inka), rated 'BBB-', with a rating case DSCR minimum of 1.1x and an average of 1.25x under Fitch's rating case. Parque Eolico Tres Hermanas, S.A.C. is also rated 'BBB-', with a rating case DSCR minimum of 1.41x and an average of 1.53x.

      Like ILAP, these projects also have a large proportion of revenues originating from contracted energy sales. However, when compared to these investment-grade peers, ILAP has lower average and minimum rating case DSCRs. The lower metrics alongside ILAP's higher revenue risk profile (in terms of basis risk and exposure to DisCo demand) coupled with the deteriorating liquidity position and an exposure to refinancing risk are consistent with its lower rating.


      Factors that could, individually or collectively, lead to negative rating action/downgrade:

      Net spot revenue losses exceeding USD19 million during 2023 driven by adverse operating performance or market dynamics;

      Reserves being drawn for more than USD10million for the next debt service;

      Factors that could, individually or collectively, lead to positive rating action/upgrade:

      A positive rating action is unlikely, given the rating is on Rating Watch Negative. The Negative Watch could be removed if the decoupling costs are persistently below or equivalent to USD15 per MWh, yielding an average forecast DSCR above 1.2x and if project liquidity improves, leading to operational cash generation above debt service.

      Best/Worst Case Rating Scenario

      International scale credit ratings of Sovereigns, Public Finance and Infrastructure issuers have a best-case rating upgrade scenario (defined as the 99th percentile of rating transitions, measured in a positive direction) of three notches over a three-year rating horizon; and a worst-case rating downgrade scenario (defined as the 99th percentile of rating transitions, measured in a negative direction) of three notches over three years. The complete span of best- and worst-case scenario credit ratings for all rating categories ranges from 'AAA' to 'D'. Best- and worst-case scenario credit ratings are based on historical performance. For more information about the methodology used to determine sector-specific best- and worst-case scenario credit ratings, visit


      2022 has been a challenging year for power generation companies in Chile. The rising cost of commodities such as coal, diesel and LNG driven by world-wide trends, including the war in Ukraine, have increased the cost of power generation beyond previously expected levels. This has been exacerbated by a hydrology that has improved since 2021 but is still well below average. The increase in renewable generation has also presented challenges. Solar projects have been driving spot prices to close to zero during certain solar hours and have created congestion in a transmission system that has been outpaced by the new capacity coming online.

      The stabilized price program has been extended through the PEC II, which is expected to cap revenues from regulated PPAs creating an account receivable for the difference between the regulated price and the PPA price. Liquidity issues for generation companies is expected to be alleviated through a factoring line with the IDB currently being structured which is expected to be available in Q1 2023. The working capital cost is currently borne by the generators.

      Up to September 2022, the generation for the wind farms was below P50 generation but above Fitch's rating case expectation of P90 generation.

      On the revenue side, net spot energy losses through September 2022 were -USD16.6 million versus the expected -USD8 million in Fitch's rating case and USD3 million in the base case. This was partly caused by large energy purchases at expensive withdrawal nodes not fully offset by injection-node spot revenues. Margin erosion is driven by elevated spot prices and intraday volatility resulting from congestion and system imbalance, pushing prices down during sun hours and up during non-solar hours as thermal power plants set the marginal costs.

      The lower than expected generation during a few months also caused shortfalls versus contracted energy, which had to be bought at high spot prices further deteriorating results. Additionally, during July, 10-day repairs to transmission infrastructure isolated the north of Chile, materially increasing price differentials and greatly contributing to decoupling costs during this period. DisCo oversupply was lower than expected at 28% instead of Fitch's rating case 36%, which contributed to slightly higher PPA revenues.

      Through September 2022 total revenues (contracted sales, spot revenues and capacity revenues) of USD23 million were significantly lower than the USD40 million estimated in Fitch's base case and USD35 million expected in Fitch's rating case due to the losses experienced in the spot market.

      Opex was generally in line with expectations, although higher than expected inflation increased inflation-linked O&M costs slightly above our forecasts.

      Cash Flow Available for Debt Service (CFADS) through September 2022 was USD9 million, which was below Fitch's expectation of USD28 million in our base case and USD23 million in our rating case. This resulted in a DSCR of 0.34x versus the expected 1.17x and 0.9x in our base and rating case respectively. The shortfall in debt service was covered with an extraordinary contribution from project sponsors for USD5 million and working capital management.

      The lower than expected cash generation led to the drawdown of the O&M reserve by USD4.5 million during October, in order to cover a breach in liquidity derived from the poor performance of previous periods. The DSRA is fully funded at USD16.5 million.


      Fitch's base case reflects the agency's view of long-term sustainable performance. Fitch's base case assumes P50 generation with an additional production haircut of 3% to account for forecast uncertainty and potential wake losses before planned transmission expansion infrastructure comes online, which will significantly reduce congestion. After this point, the haircut will be 2%.

      The operational cost profile assumed is in line with the sponsor's original assumptions given the long-term, full-scope SAA. Fitch considers only five additional years of useful life beyond the expiration of the Vestas contracts, for a total of 25 years of useful life for each asset. For the refinancing of the balloon payment, Fitch did not stress the coupon rate of the notes in the base case. Inflows from the first program of stabilized price receivables were not considered in coverage metrics, but were considered as cash-flows to reach target amortizations.

      Fitch's rating case reflects a reasonably likely combination of uncorrelated stresses that could occur in any given year but which are not expected to persist. The rating case assumes P90 generation and the same generation haircut as the base case.

      The rating case assumes a 7.5% stress on operating expenses, excluding SAA costs. However, to reflect the agency's view that operating costs may increase after the typical 20-year useful life of a wind asset, Fitch stressed the SAA costs by 12.50% after year 20 of operation. Availability is also reduced to 96% for San Juan and 95% for Totoral after year 20 of operation of each farm to account for potential increases in major maintenance events during the last years of project life. For the refinancing of the balloon, Fitch assumed a higher rate of 7.5%, in comparison with the base case interest rate. All other assumptions mirror the base case.

      Fitch revised other projection assumptions to reflect expectations going forward and to be consistent with the reality faced by the project in current conditions. Fitch updated its U.S. inflation expectations to 7.0%, 3.60%, 2.7% and 2% for 2022, 2023, 2024 and long-term, respectively.

      Fitch's adjusted spot price curve for central Chile nodes (the main withdrawal nodes) was shifted upwards, consistent with Fitch's expectation of a spot price of around USD100/MWh for Q4 2022, given the currently high commodity prices. Followed by a decrease to USD66/MWh on average for 2023 and 2024, USD47/MWh on average for 2025 to 2028 and USD39/MWh on average for 2029 to 2033, caused by the new renewable generators coming online, the decarbonization process and lower expected commodity prices. To assess the refinancing risk, Fitch uses a spot price of real USD36/MWh on average.

      To account for basis risk and the prevalent volatility in injection and withdrawal prices, Fitch considered injection prices on USD20 below the mentioned spot prices for 2023 and injection prices USD15 below withdrawal prices from 2024 to 2030. Similarly, the agency increased its curtailment expectation to 5% from 3.5% until 2029, given the congestion caused by new renewable projects expected to come online. In 2029 and onwards, Fitch believe the COD of new transmission infrastructure will ease congestion concerns and close the spot price differential between northern and central nodes.

      Fitch considered the working capital effect of the PEC II price stabilization program throughout 2022, with an expected recovery of these receivables in Q1 2023 through the IDB credit line. Contracted revenues from PPA with DisCos are not projected to be reduced due price stabilization after this point given that ILAP expects to factor all future receivables from this program.

      DisCo oversupply was adjusted according to the most recent expectations, which averages 28% from 2023 to 2026 and is up from our previous expectation of 21% average from 2023 to 2025.

      Under Fitch's base case, average DSCRs are 1.3x with a minimum of 1.1x in 2023 with a PLCR at refinancing date of 2.4x. Under the rating case, these metrics erode to an average of 1.2x with a minimum of 0.9x in 2023 and a PLCR at refinancing date of 1.5x.

      Fitch also ran break-even analyses to evaluate the project's financial resilience to extreme stresses. These analyses indicated, under Fitch's base case conditions, that the project could withstand a sustained minimum real merchant price of 25USD/MWh before PLCR is below 1x at refinancing date. This result is strong, as it is below historical spot prices and the expected levelized cost of energy for a renewable plant.

      Even though project metrics are mostly consistent with the assigned rating and has a strong PLCR at the time of refinancing, the near-term low coverage is a concern, although the DSRA is expected to cover forecasted shortfalls.


      The principal sources of information used in the analysis are described in the Applicable Criteria.

      ESG Considerations

      Unless otherwise disclosed in this section, the highest level of ESG credit relevance is a score of '3'. This means ESG issues are credit-neutral or have only a minimal credit impact on the entity, either due to their nature or the way in which they are being managed by the entity. For more information on Fitch's ESG Relevance Scores, visit


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