Lending to hedged wind and solar projects

Lending to hedged wind and solar projects

February 10, 2020 | By Christine Brozynski in New York and Connie Gao in Los Angeles

Quasi-merchant projects that sell into the spot electricity market and use hedges to put a floor under the electricity price are becoming more common, particularly in ERCOT where power purchase agreements remain scarce.

Lenders financing these projects should be aware of how cash flows will be affected as well as of other risks inherent in these structures.

Common hedges

One of the most common forms of hedge in ERCOT (where most of the renewables hedges in the United States are concentrated) is a physical fixed-volume hedge.

Under this type of hedge, the project company sells all of its electricity into the grid for the spot price at a grid “node” and keeps the revenue.

At the same time, it enters into a hedge that requires the project company to purchase a fixed volume of power at the “hub” each hour for the hub price and immediately re-sell that hub power to the hedge provider for the contract price under the hedge.

The fixed volume of power is set when the hedge is signed and is not adjusted based on actual production at the project. The contract price is a fixed price per megawatt hour. The project company uses the merchant revenues received from its sales of electricity at spot prices to buy the electricity at the hub that will be sold to the hedge provider.

Fixed-volume hedges can also be financial instruments rather than physical transactions. This type of hedge is more common outside ERCOT. Physical hedging means that power is actually sold to the hedge provider as part of the transaction, while financial hedging means the parties settle financially with respect to a notional quantity of power determined when the hedge is put in place.

The main difference between the two hedges is the payments.

Under physical hedges, the project company must spend money each hour to purchase power at the hub. The hedge provider then purchases that power from the project company, paying the contract price for that power usually on a daily basis (although sometimes these payments are only made monthly).

Financial hedges, on the other hand, are usually structured as contracts for differences. The hedge settles financially each month on a fixed notional quantity of electricity that varies for each hour. The floating hub price is multiplied by the notional quantity of power for each hour. That amount across all hours in a settlement period is called the “floating amount.” The fixed price in the hedge contract (also called the strike price) multiplied by the notional quantity of power required in a settlement period is called the “fixed amount.” The floating amount and fixed amount are netted against each other at the end of each month. If the fixed amount is higher, the hedge provider pays the project company the difference. If the floating amount is higher, the project company pays the difference to the hedge provider.

Another common type of hedge is a proxy revenue swap. It is settled financially at the end of each quarter.

There are two main differences between proxy revenue swaps and financial fixed-volume hedges.

The first is that the fixed price in a proxy revenue swap is a lump sum per quarter (the “fixed payment”), unlike fixed-volume hedges, in which the contract price or fixed price is a fixed charge per megawatt hour.

The second difference is that the floating amount is not based on a schedule of fixed volumes attached to the hedge at the time of hedge execution; rather, it is based on the “proxy generation” from a project. For wind proxy revenue swaps, proxy generation is the actual electricity produced by the project, adjusted to assume fixed operational inefficiencies for each turbine.

The calculation is similar in solar proxy revenue swaps, although sometimes a time series is used to calculate production instead of measuring actual production from the project.

The assumptions about operational inefficiencies are determined when the proxy revenue swap is signed.

The proxy generation is multiplied by the hub price for each hour to calculate the “proxy revenue” for the settlement period. The proxy revenue is netted against the fixed payment. If the proxy revenue is higher, the project company pays the difference to the hedge provider. If the fixed payment is higher, the hedge provider pays the difference to the project company.

Cash flow risks

Lenders focus on several issues when financing hedged projects.

The first issue is the risk to cash flow caused by differences between the hedge payments and merchant revenue.

This can be sub-divided into three main risks when the hedge is a fixed-volume swap: basis risk, volume and shape risk and covariance risk.

Basis risk is the risk that the hub price will be higher than the nodal price where the power is sold, so that it costs more to buy electricity to resell to the hedge provider than what the project was paid for the electricity it sold into the grid.

Volume risk and shape risk is the risk that the project will produce less electricity than it is required to buy at the hub (volume risk) and that the periods of high and low output do not align in terms of timing with the high and low fixed volumes under the hedge (shape risk).

Covariance risk is the risk that the spot price for power will be depressed if all of the wind farms or solar facilities in a given area produce at the same time, assuming there is a high enough concentration of wind farms or solar facilities in the area.

Basis risk is also an issue for projects with proxy revenue swaps, but volume risk, shape risk and covariance risk do not come into play. The project company will receive a fixed lump-sum amount under the proxy revenue swap no matter how much electricity the project generates. The project company retains operational risk in the sense that a mismatch is possible between actual efficiency of the turbines and the efficiency of the turbines assumed to set the fixed payment when the swap was put in place.

Lenders should try to capture the complexity of these hedges in the model.

For fixed-volume hedges, it is not enough to assume in the model that the project will receive the fixed price for P99 volumes and then bank all revenues for production in excess of P99. Even after accounting for basis risk, the issues surrounding volume and shape risk and covariance risk can result in less revenue than anticipated. A white paper by REsurety, Inc. and EnergyGPS Consulting, LLC, called “The ‘P99 Hedge’ That Wasn’t,” analyzes historical data in ERCOT to find that hedge revenues were arguably overestimated by an average of 18%, while volumes produced in excess of the fixed-volume requirements under the hedge proved to be 38% less valuable than the average market price of energy during the same period.

Despite the potentially uneven cash flows, debt-service coverage ratios traditionally are no higher for hedged projects than for projects with utility power purchase agreements.

Mitigating risks

One way for lenders to manage basis risk is by implementing mandatory prepayment triggers.

The triggers can take various forms.

One such trigger for which the lenders could require a prepayment is where the average nodal price received by the project company over a predetermined rolling period of time drops below a threshold agreed to by the lender and the project company. Another type of trigger that could trigger a prepayment is where the average differential between the hub price and the nodal price (the “basis differential”) exceeds a pre-agreed threshold.

The mandatory prepayment itself can also be structured in different ways.

One is as a sweep of a percentage of cash on deposit in a revenue account in the waterfall. Another is a fixed payment. Lastly, lenders can also recalculate projected debt-service coverage ratios for the remainder of the term based on an updated market report. The prepayment would be in the amount required for the project company to meet a required minimum debt-service coverage ratio going forward.

Basis risk is often partially mitigated by a tracking account in a hedge.

A tracking account is essentially a working capital loan from the hedge provider to the project company in the amount of the difference between, on the one hand, the amount the project company owed under the hedge for that month and, on the other hand, the merchant revenue received by the project company for power for that month. The tracking account is capped at an amount negotiated by the parties, called the tracking account limit.

Lenders can require a separate mandatory prepayment if the outstanding tracking account balance reaches a certain threshold.

This prepayment can be structured as a one-time fixed amount paid by the project company or as a cash sweep at the appropriate place in the waterfall. The project company may negotiate for the right to hold the prepayment amount in a reserve account for a number of months to give it a chance to pay down the tracking account and cure the prepayment trigger event.

Reserve accounts can also be used to mitigate basis risk independently of the tracking account.

One approach is to require the project company or other borrower under the term loan to establish a reserve at term conversion to be used for working capital as a buffer against potential cash flow issues. If a tax equity investor is already requiring this under the tax equity documents, the lenders may take comfort in the existence of such a reserve instead of requiring a separate one under the loan documents.

Lenders could require springing reserves that must be filled upon a trigger event. A borrower may negotiate an automatic waiver of a springing reserve requirement if the historical and forward-looking debt-service coverage ratios exceed the minimum requirement by a pre-negotiated margin.

When evaluating potential cash-flow issues, another item lenders should look out for in a hedge is a distribution block. Hedge providers whose interests are secured by a lien on the project sometimes prohibit the project company from making distributions after an event of default or termination event under the hedge. Allowances are not typically made for debt service or preferred distributions to tax equity.

Interparty and collateral risks

Project companies entering into hedges are required to post credit support.

This may take the form of a letter of credit or cash. Alternatively, the project company may grant the hedge provider a first lien on the project company assets and the equity interests in the project company. For projects with construction financed by debt, the lien to the hedge provider is usually granted at commercial operation after the debt converts to back leverage. This is because construction is usually financed 90% with debt, if not more; in the event of a foreclosure, there would not be enough cushion to repay both the lender and the hedge provider if both were to share collateral.

The typical hedge contains a list of conditions precedent for the first lien to take effect and to reach commercial operation under the hedge.

Lenders should make commercial operation and the grant of the first lien conditions precedent to term conversion in the loan documents. They should also do careful diligence of the list of conditions precedent to ensure that the hedge provider does not have any “outs,” similar to the way a lender might review a list of conditions precedent to the tax equity funding. Ideally each condition precedent should be as objective as possible rather than in the discretion of the hedge provider. Lenders should also ask for forms of any certificates or opinions that must be delivered to the hedge provider at commercial operation to be attached to the hedge at hedge execution. This reduces the risk of potential delays or deadlock when the project is gearing up for commercial operation.

Consents to collateral assignment of the hedge often differ slightly from customary consents to collateral assignment given by third parties.

While lenders are usually granted a cure period for defaults, it is not uncommon for hedge providers to require the lenders to post collateral after part of the cure period has lapsed if the default remains uncured. The collateral amount is usually the difference between the hedge provider’s exposure and the collateral already posted. The collateral amount is adjusted up or down during the cure period as the hedge provider’s exposure fluctuates. If the default remains uncured at the end of cure period provided in the consent, then the hedge provider is allowed to draw on the collateral.

Lastly, hedge providers sometimes make the project company make representations or covenants in the hedge, particularly if the hedge provider has a lien. For example, a secured hedge provider might include representations and covenants about the security interest and preservation of the collateral. A common covenant requires the project company to operate the project in accordance with prudent operator practices or a similar standard of care. Lenders should review any covenants to ensure that the project company can satisfy all the obligations.