A discussion of the hedging arrangements power project owners use to mitigate merchant risk and make their projects financeable. This Note also discusses why these arrangements are necessary and the benefits and drawbacks of these arrangements.
Traditionally, power projects that are built in the US are backed by long term power purchase agreements (PPAs). PPAs provide a predictable and reliable revenue source lenders can look to for the repayment of the loans. However, in recent years, PPAs have become very difficult to secure, especially for natural gas fired power plants.
An alternative to PPAs is to sell the electricity generated by the project in the spot market. These sales do not, however, generate fixed and reliable revenues. In these cases, the project's revenues are entirely dependent on the amount of electricity the project owner can sell and the price available in the market on the date of those sales. Because these sales are subject to market-based pricing and demand, which can vary widely, it is very difficult to estimate the revenues that will be available to the project owner to meet its operation and maintenance (O&M) obligations and to make debt service payments to the project’s lenders. In addition, if the project is curtailed, the project owner cannot recover lost revenues from any party, unlike in a PPA. As a result, lenders have generally been unwilling to finance these projects.
However, there is a lot of liquidity in the market with many lenders (from traditional project finance lenders such as European commercial banks to new entrants such as hedge funds and debt funds) looking for projects in which to invest. The abundance of capital, coupled with the decreasing number of projects with PPAs, have made lenders more willing to finance non-PPA projects. They are less willing, however, to finance purely merchant projects. In the absence of a PPA, lenders require some mechanism to mitigate merchant risk and reduce revenue volatility.
One of the mechanisms that is increasingly being used is hedge contracts. On the spectrum of cash flow certainty, with traditional PPAs on the far left side of the spectrum and pure merchant projects on the opposite end, hedging arrangements fall somewhere in the middle. Although they are less predictable than traditional PPAs, hedges give investors and lenders more clarity and certainty on project revenues than they would have with a pure merchant project.
This Note discusses:
• Why hedging arrangements are necessary.
• The benefits and drawbacks of hedging arrangements.
• The main hedging instruments project owners can use to mitigate merchant risk and make the projects financeable.
Why are Mitigation Mechanisms Necessary?
Project owners traditionally generate revenue through either long-term PPAs or spot market sales. In a PPA, the project owner agrees to sell to a creditworthy purchaser, such as a utility, the electricity generated by the project at a set price over some significant portion of the project’s life, typically 10 to 20 years. This guarantees the project owner a steady stream of revenue. As long as the plant and offtake party (or parties) operate as they should, the project will collect a predetermined amount of revenue under the PPA. However, project owners are not always able to find a creditworthy counterparty with a desire to enter into a long-term power contract. In addition, even if a power purchaser is willing to sign a long-term contract to buy power, there are many markets where that price may be too low to create appealing economics for investors. These low prices are attributable mostly to the low natural gas prices.
Natural gas prices have averaged less than $5 per million British thermal unit (mmBtu) for several years. According to the Energy Information Administration (EIA), an agency of the Department of Energy, average wholesale (spot) prices for natural gas at Henry Hub, a key benchmark location for pricing throughout the US, averaged:
• $3.73 per MMBtu in 2013.
• $4.39 per MMBtu in 2014.
The EIA also expects the natural gas spot prices to average $3.05 per MMBtu in 2015 and $3.47 per MMBtu in 2016. These low natural gas prices have made utilities and other power purchasers less willing to commit to long term PPAs. They are not the only entities that are unwilling to commit to long term fixed price sales contracts, however. Project owners are sometimes also reluctant to sign PPAs if it means locking in a price for power for the next 20 years that may be below projected electricity prices.
PPAs distinguish between capacity and energy:
• Capacity payments are payments for the ability of the utility to call on the project for power. Capacity payment PPAs were common in large geothermal power projects, but they are becoming increasingly hard to find. Capacity payments are intended to cover the power plants’ fixed capital and other costs not recovered through electricity sales.
• The energy price is a per megawatt hour (MWh) charge for the electricity actually delivered. The energy price generally covers operating costs, payment of principal and interest on long tenor debt and recovery of capital with a reasonable return.
Benefits of Hedges
Hedges do not generally cover 100% of the project's revenues or mitigate merchant risk entirely. But they provide a relatively stable stream of revenue for project companies that make the projects financeable, even if that stream is not necessarily as robust as that offered by a traditional PPA. Understanding these hedges and how to select and properly structure them increase project owner’s financing options. Hedges, however, cannot make a bad project good.
Traditionally, power hedge counterparties were dominated by banks. That is no longer case. Hedges are now being provided by a wide range of parties from banks to institutional investors such as large pension funds. Hedging counterparties are often sophisticated financial institutions that do not have an interest in receiving the electricity produced by the project. However, they are often associated with the project in some way (for example, an institutional bank that also serves as an arranger in the deal). Under certain circumstances, the hedging counterparty may be an unrelated third party. For example, the hedging counterparty for the Panda Power Temple project that closed in 2012 was the 3M Pension Plan.
Best Markets for Quasi-Merchant Projects
For projects that do not have a PPA, revenue risk can be mitigated by selling into a market:
• With a capacity market where generators can sell their power. Developers are unwilling to build a power project unless they can be assured they will be able to sell the electricity the project generates. Capacity markets have been set up in certain parts of the country to ensure there is enough electricity supply to meet demand when it is needed most. In these markets, project owners are paid a certain amount in exchange for agreeing to stand ready to supply power when needed. Capacity markets are used in Pennsylvania New Jersey Maryland Interconnection (PJM), Midcontinent Independent System Operator (formerly, Midwest ISO) (MISO) and ISO New England (ISO-NE). PJM has an established and transparent capacity market and auction process, and some growth.
• Where there is significant demand for electricity (such as Electric Reliability Council of Texas (ERCOT)). ERCOT is one of the few areas in which there is growing power demand for electricity. It bears noting that while there is significant demand in ERCOT for both contracted and uncontracted power, there is regulatory uncertainty in this market. The Texas Public Utility Commission (PUC) has been trying to sort out the issue of whether to establish a capacity market to incentivise new construction, or leave it to the energy markets to provide that incentive, an approach that has not been enough to motivate developers to build enough new capacity to keep up with demand.
Revenue puts have become a key component of the financing for gas-fired projects (for example, Panda Power’s Sherman, Temple I and Temple II projects). Although less common, revenue puts can also be a part of the financing structure for wind projects (for example, Pattern Energy’s Panhandle wind farm, and Airtricity’s Champion wind farm).
What is a Revenue Put?
A revenue put is a type of option contract between a project owner (the option buyer) and a hedge counterparty (the option seller). In this agreement, the parties specify a floor or an amount below which the revenues generated by the project cannot fall during any period during the term of the option agreement before triggering payment obligations on the part of the hedge counterparty. If the actual revenues generated by the project during this period falls below the floor, then the hedge counterparty must pay to the project owner the difference between the floor and the actual revenues. By establishing a floor for the revenues, the project owner is guaranteed a certain amount that it can use to meet O&M obligations and repay the loans.
Traditionally, the term of these hedges was fairly short compared to the useful life of a power plant, typically less than 5 years. In this case, the lenders would require that the loans be repaid before the hedge expired which puts refinancing pressure on the project owner. However, because of the increased interest in power projects as an investment, project owners can secure hedges for as long as 12 or 13 years, which greatly enhances the investment appeal of new power projects.
Determining the Floor
The arrangement for the contracted floor revenue can vary and is a function of:
• The negotiating strength of the parties.
• The market into which the electricity is being sold.
• The energy technology (for example, the floor for a gas-fired project would be different from that for a renewable energy project).
The floor can either be fixed, or floating, on a quarterly or annual basis.
Parties must take care in establishing the floor so there is not a large differential between the floor and [the prevailing market price for electricity]. For example, during the Polar Vortexes of Winter 2014, several gas-fired power plants in the US Northeast were on the short-end of a bad hedging arrangement because they had indexed their hedge at an injection point further downstream from their actual supply. When the differential in prices between the actual price of fuel and the indexed price exceeded projections due to unexpected fuel scarcity on the pipeline, the hedge went sideways and fixing the issue became an eight-figure problem for investors.
Calculating the Project’s Revenues
The project’s revenues can be calculated or estimated in different ways:
• In one method, the calculation is based on actual revenues earned, which is measured at the actual dispatch of the project at the hourly marginal price.
• In another method, revenues are measured using a contracted formula that may take into account various factors, including transmission congestion or other power generation sources. Query: Is this intended to take into account the likelihood of curtailment?
• A formula approach may also factor in fuel costs – either actual fuel costs, or fuel indexed at a point of injection that does not necessarily correspond to the injection point used for the power project’s fuel.
Also called a swap PPA, a synthetic PPA is an arrangement in which the project owner sells its power on a merchant basis, but enters into a hedging agreement, usually with a financial institution under which the financial institution in exchange for a fee pays to the project owner a certain amount depending on the movement of electricity prices in the market into which the electricity is being sold. This type of hedge provides insurance against declines in power prices (which is a fundamental purpose of any hedge) and gives investors and lenders more clarity on project revenues than they would have with a pure merchant project where the project owner will only be able to collect revenues based on electricity sold into the spot market.
These PPAs are not for the faint-at-heart and are not appropriate for all power markets. Synthetic PPAs are limited to deregulated markets with liquid spot markets for the sale of power (for example, (ERCOT), PJM, Southwest Power Pool (SPP), ISO-NE, and the New York Independent System Operator (NYISO). They should to be entered into with a healthy dose of caution because, on a spectrum of cash-flow certainty, with traditional PPAs on the far left side of the spectrum and pure merchant projects on the opposite end, synthetic PPAs fall somewhere in the middle.
How do Synthetic PPAs Work?
In a synthetic PPA the project company and the hedging counterparty agree to a benchmark for electricity prices in the relevant market. The benchmark can either be set to a specific amount, or more commonly, a price range or collar. If the electricity generated by the project is sold for price within the range, neither party is required to make a payment. If, however, the price:
• Rises above the range, the project owner pays an amount (typically, a share of the excess amount above the range) to the synthetic PPA provider.
• Falls below the range, the synthetic PPA provider pays the project company the difference between that price and the lowest amount in the range.
The key to these arrangements is determining the collar. It must be set in such a way that it adequately tracks electricity prices in the relevant market in order to minimize the likelihood that the project owner will make any payments to the synthetic PPA provider, which raises several issues.
Benefits and Drawbacks of Synthetic PPAs
In addition to any fees the synthetic PPA may receive for entering into these transactions, it also benefits if prices rise above the collar because it receives a share of increase. As a result, the cost of this hedge may be less than hedging instruments that only provide a price floor (see Revenue Puts). However, there are a limited number of potential hedging counterparties that are willing to enter into synthetic PPAs. Therefore, the cost reduction isn’t as significant compared to traditional hedges as the shared upside might suggest.
While traditional long-term PPAs rarely have index-based escalation factors because of the uncertainty caused by shifts in the power markets over time, parties to a synthetic PPA may be able to negotiate for an escalation factor with respect to the benchmark price because the term of the agreement is typically less than half that of a traditional PPA. By setting an escalation factor for the strike price over a relatively short period of time lasting fewer than ten years, the synthetic PPA will more accurately align the price of the agreement with that of electricity in the power markets, thereby reducing the exposure of all parties to volatile pricing movements.
Synthetic PPAs face some regulatory uncertainty. The Commodity Futures Trading Commission (CFTC), has not yet ruled as to what extent parties to synthetic PPAs will be subject to CFTC regulation, but it is clear that parties to hedges will face new limits on positions and capital exposure, as well as record-keeping and reporting requirements. There is a limited exemption for “end users.” The scope of the exemption is still being debated. Parties will need to factor these potential new regulatory requirements into their modeling for projects using synthetic PPAs.
Lenders have been willing to finance projects with synthetic PPAs, provided key issues are addressed in the agreement. The key negotiating points are:
• Whether and the extent to which the synthetic PPA provider shares in the project's collateral package.
• The placement of the synthetic PPA provider's payments in the project's waterfall.
• The synthetic PPA provider's rights upon a default under or termination of the synthetic PPA.
Rights in Collateral
While hedges do not cover 100% of a project's merchant risk, they still represent a material obligation for counterparties. If the market price for the electricity rises significantly above the range, the hedge counterparty may have significant exposure to the project owner. Because of the size of the settlement exposure, the hedging counterparty will want to the project owner to secure its obligations under the hedge. This is the most significant area of tension in negotiating a synthetic PPA because the project owner is likely to have already pledged all of its assets (project revenues, contractual rights and physical assets) to the senior lenders. Therefore, the pool of collateral available to secure the hedge agreement may not be large enough to protect the counterparty without creating overlapping claims between the counterparty and the senior lenders. Accordingly, the counterparty will seek a senior lien on specific collateral and step-in rights in order to secure its exposure on the hedge, while lenders will want to ensure that the provisions in the hedge agreement do not prejudice their rights under the intercreditor agreements or otherwise cause their protections to fail.
Priority of Payment
The counterparty will prefer that the payments associated with settlement of the hedge be treated on the same level as O&M expenses in the project waterfall, which are typically paid out at a priority over the senior debt (see Project Finance Waterfall Provision). However, lenders will argue against such treatment for the counterparty’s payments, while also requiring their consent for any material modifications to the project owner’s obligations under the synthetic PPA.
Rights Upon a Default and Termination Rights
Lenders may also push back on various provisions negotiated by the counterparty, including an obligation by the project owner to post liquid collateral with the counterparty upon the occurrence of certain trigger events. Lenders may also ask for a brief cure period after an event of default under the hedge agreement in order to give the lenders a chance to cure any default and thus preserve the value of the hedge.
To ensure that the project owner is not subject to differing standards, lenders want the termination events under the synthetic PPA to match termination events under the project loan documents.
Term of Hedge
The short term of a synthetic PPA, typically 10 or fewer years, is a concern for lenders because it creates a period of unhedged merchant tail and require the debt to be amortized in a relatively short amount of time. Nevertheless, lenders will finance projects using a synthetic PPA if there is sufficient price protection. Voting Rights. Under a project financing associated with a traditional long-term PPA, lenders vote on a weighted basis, according to their exposure to the transaction. Under a synthetic PPA, the lenders and hedging counterparty can choose to arrange voting rights in one of several ways:
• The counterparty may defer to the lenders and is not entitled to voting rights. The voting may be based on the exposure of the counterparty.
• The voting rights may be based on the occurrence of a particular event, such as acceleration of the senior debt.
Other Hedging Instruments
Other hedging instruments project owners can use include:
• A contract for differences.
• A put option.
• A call option.
Contract for Differences
In a contract for differences (CfD), the project owner enters into a swap with the hedge counterparty under which:
• The hedge counterparty pays to the project owner a fixed amount (the strike price) for a certain amount of electricity. The strike price is subject to escalation over the term of the CfD, which is typically three to five years. CfDs are usually contracts around a notional quantity of electricity.
• The project owner pays to the hedge counterparty the amount it receives in the spot market for that same amount of electricity.
There is no actual sale of electricity by the project owner to the hedge counterparty. The project owner sells the project's electricity into the open market, not to the hedging counterparty. Similarly, the hedging counterparty, which is typically a large consumer of electricity, independently buys electricity from the spot market to meet its own needs. The parties enter into the hedging arrangement because it allows:
• The project owner to sell its electricity in the open market at variable and unpredictable prices while receiving fixed prices from the hedging counterparty. Essentially the project owner is swapping variable revenues for fixed revenues. The predictability of these revenues increases the bankability of the project.
• The hedge counterparty to purchase electricity at fixed prices, while possibly earning a return. Because the project company pays it the actual price it receives in the spot market, if that price is higher than the fixed price it pays the project owner, it keeps the benefit of the upside. However, if that price is lower, the hedge counterparty bears the loss.
In practice, however, neither pays the full amount required under the CfD. Instead, the parties net the difference so there is a payment in only one direction: either the project company or the counterparty is paid. For example, if the spot market sale price is greater than the strike price, then the project owner pays the difference to its hedge counterparty.
This arrangement is made in a futures contract and paid through cash payments (or cash settled), rather than buying or selling the physical electricity commodity.
Project owners can also enter into options to mitigate revenue risk. Generally, these options give the project owner a base level of revenues which lenders can look to repay the loans. Depending on the movement of electricity prices and the term of the option, the project owner can also benefit from an increase in prices in the relevant market.
Under a put option, the prices for the sale of electricity are pre-set and are based on the proximity of the strike price to forward price forecasts in the relevant power market, and the term of the option. Under the term of the option, the project owner, or option buyer, purchases the right (but the obligation) to sell physical power at a certain strike price. If the market price for electricity per kilowatt hour:
• Falls below the strike price, then the option buyer will exercise the option to sell its power to the option seller.
• Rises above the strike price, then the option buyer will let the option expire and sell its electricity in the spot market at the higher price.
Similar to put options, call options are pre-set and are priced based on the same mechanics as a put option (for example, the proximity of the strike price to the forward price and length of the option term). However, call options work in the opposite way. The project owner (in this case the option seller) sells to another company the right (but not the obligation) to buy electricity from the project company at a certain strike price. If during any relevant period the price of the electricity:
• Rises above the strike price, then the option buyer will exercise the call option and require the option seller to the electricity at the strike price.
• Falls below the strike price, the option buyer will let the option expire and buy electricity in the spot market.
In this case, the project company bears the risk that it may be forced to sell its electricity at below market rates. However, provided that strike price was set at an amount that allows the project owner to earn enough revenues for O&M and debt service, the fact that it does not benefit from any upside in the market may not be fatal. Moreover, it receives a fee for selling the call option which gives it another revenue source that may offset part of the lost revenues. Finally, these options generally cover only a part of the project's output to give the lenders some security as to revenues.
Heat Rate Call Options
Heat rate refers to the efficiency of an electric generating plant. It is an expression of the number of MMBtus of natural gas that are needed to generate 1 KW of electricity. The lower the heat rate, the more efficient the plant and the higher the heat rate, the less efficient the plant.