Call options can be used as a financing tool for fixed-cost renewable energy technologies.
Daniel Simon holds an MBA (finance concentration) from Northwestern University in Evanston, Ill. Contact him at firstname.lastname@example.org. The author would like to acknowledge Shimon Awerbuch for his editing and advice improving the charts and figures.
An unexploited benefit of renewable energy is the predictability of operating costs over the long term. A renewables operator knows today how much it will cost to produce energy decades in the future. This future price certainty has a value that can be transferred to electricity buyers or other market participants.
Long-term call options, akin to electricity price insurance, can capture some of this value. Short-term call options—options that expire in three years or less—are traded commonly on numerous markets. These include options on energy inputs commodities like coal, oil, and natural gas, as well as energy products, like electricity.
How much value can a renewable-plant operator capture from selling long-term call options, given several future price and volatility scenarios? What will be the cost and benefit to an individual buyer or seller?
Knowledge of Future Costs
Most renewable energy plants require a large upfront equipment and installation cost, followed by smaller, predictable annual costs for operations and maintenance (O&M). To the extent that O&M costs are predictable, a plant operator knows today what it will cost to produce electricity in 10, 15, or even 20 years. This is quite remarkable and valuable information. By contrast, more than 90 percent of the electricity industry does not know its costs beyond a year or two into the future because of the price volatility of fossil fuels.
Energy markets (including electricity) are complex and volatile, with numerous suppliers, inputs, technologies, and other factors that affect electricity prices.
Given current technology, the grid operates best when there is a balance between supply and demand. “Load balancing” is challenging because electricity is difficult to store. The current electricity derivative markets have focused on meeting this challenge.
Market participants are interdependent. Each faces varying degrees of regulation and constraint. Regulation can determine which participant within a given supply chain bears the burden or cost of volatility. Changes in regulation can shift the burden around, but cannot eliminate volatility.
One notable constraint within the North American electricity market is limited transmission capacity among regions. This creates multiple independent regional markets. Also, the U.S. electricity market has been segmented by regulation so that different users pay different prices for the electricity used (i.e. residential, commercial, and industrial rates). Electricity users often respond only after the fact to price signals (i.e., after customers get their monthly bills) if at all. Taken together, all these factors contribute to a complex, volatile marketplace.
Electricity Price Insurance
How do you capture the value of cost certainty? A good way would be to sell electricity price insurance, in the form of long-term call options. A call option gives the buyer the right (but not the obligation) to buy the asset at a fixed price at a fixed time in the future. The seller agrees (for a price) to cap the user’s future electricity cost. The electricity buyer now has a ceiling on future electricity costs, while the seller of the call option gets paid today for providing insurance. Both buyer and seller obtain a clear benefit.
Different renewable energy technologies produce electricity with different costs (peak vs. baseline). Moreover, peak costs may change at a different rate than baseline costs. So the type of energy supplied will affect what electricity cost a call seller can insure against. Also certain buyers in some regional markets will gain more value from a call option than will other buyers. All these factors should be considered when matching a call buyer and seller.
Setting a price for long-term call options is challenging. The price will depend on how these factors vary over time, and on each party’s:
• Risk tolerance;
• Views and assumptions about inflation;
• 10- to 20-year forecasts for electricity supply and demand; and
• Assumptions about energy prices decades hence.
Since no reliable way exists to predict these items even from one year to the next, there is obviously no way to do so over a period of decades. The Black-Scholes options valuation method provides a ballpark estimate of the option value. The method allows one to price the risk of future events, such as an asset rising or falling in value. As noted above, options and futures already trade for most fossil fuels and even for electricity on a time scale of hours and up to a year or two in the future. Using the Black-Scholes method and longer time scales, we can estimate the value of long-term electricity price call options.
For this purpose the relevant inputs to a Black-Scholes calculation are:
• current asset price—present electric rate per kilowatt-hour;
• future or ceiling price of the asset—the buyer’s future price cap;
• expected electricity price volatility—usually based on historic volatility;
• years to option expiration; and
• risk-free interest rate—frequently the 10- or 30-year U.S. Treasury rate.
To quantify the potential value of these long-term options, let’s select some values for these key variables. We assumed a 5 percent risk-free interest rate (a higher rate will increase call value). The time to expiration is important in valuing a call option. We will look at the value today based on several different expiration periods: 10, 15, 20, and 25 years into the future. The value of the call increases as the time to expiration increases (all else held constant).
For two main reasons we use options that expire in 10 or more years. First, call options that expire sooner are worth less than options covering more time. Second, many renewable electricity producers enter into 10-year power purchase agreements (PPAs) to sell all production to their local electricity utility. Investors basically demand these agreements because they guarantee a market exists for the power the plant will produce. In proposing a new financial tool, we think it makes sense to propose one that works with (or around) such existing and proven financing arrangements.
The volatility of the asset—how much its price is likely to change in any given year—is a critical parameter in call-option valuation. Aggregate U.S. retail energy usage data shows total nominal electricity price volatility was 4.7 percent and 10.2 percent over the past 5 and 25 years, respectively.1
Unfortunately, aggregate U.S. energy data is not terribly useful for calculating volatility because averaging eliminates much of the volatility of interest within and across markets. Figure 1 shows average retail electricity price data by sector 1973-2005 and monthly 2003-2005. Electricity price (and, to a lesser extent, price volatility) depends in part on buyer size, as can be seen by comparing residential to industrial buyer pricing in Figure 1. Buyer location also affects price volatility. The best way to determine volatility is to look at actual electricity prices paid in the past. According to Figure 2, average city electricity prices have risen almost 22 percent (from 45 percent to 54.8 percent) during the last 6 years; data is for 500-kWh blocks of electricity sold in U.S. cities.
We present call-option pricing data for two scenarios. In the first, the volatility is assumed to be 10 percent, and in the second, 15 percent. Since different users pay different prices in different regions, using a ratio (future price cap/current price) actually is more helpful than creating multiple tables, each with different current and ceiling prices. The price cap/current ratio of 1.5 means the ceiling price is 50 percent above the current price (2.0 means the ceiling price is twice the current price).
Plugging the variables into a Black-Scholes calculator returns a call price expressed as a fraction of the current asset (electricity) cost. For simplicity, let’s assume the buyer currently pays 10 cents/kW-hour for electricity. To illustrate how to read the call-option price table, look at the first calculated number in Table 1 below: 0.17. This number means that this call option would cost 1.7 cents/kWh today. This call will cap the buyer’s electricity cost at 15 cents/kWh in 2016.
Tables 1 and 2 show that option value grows significantly over time, and selecting a higher future price cap will lower the call cost. Comparing call options with insurance, the price cap/current ratio works much like an insurance deductible: You can lower your insurance premium by selecting a higher deductible. In this case, the higher deducible exactly translates to a higher future energy price you are willing to pay. In most insurance products, you pay an annual or monthly premium for as long as you desire the insurance. In contrast, the call option is a single lump-sum payment for full protection for the given year. Of course, one can take this lump-sum payment and divide it up into smaller periodic payments by adding in the cost of financing.
One caveat in using a Black-Scholes valuation technique to value electricity call options is that Black-Scholes was developed primarily for valuing call options on stocks or other physical assets (i.e., an asset that can be purchased and held/stored indefinitely). Electricity differs from a stock or physical asset because it is hard to store and hold indefinitely. The Black-Scholes formula cannot return a value greater than the current asset price (1.0), because this would mean the right to buy the asset is worth more than the asset itself, which is clearly nonsense. In such a case, the rational investor simply would purchase the asset today and hold it until needed. Therefore, care should be taken if a Black-Scholes calculation returns a large value (>0.7). In practice, most people try to minimize the current cost of insurance and select a ceiling price and time frame to balance their budget/insurance need (e.g., people often will select a higher deductible, to lower their insurance premium/cost).
Numerous risks and factors outside of the four inputs to the Black-Scholes equation (current and future asset prices, volatility and interest rate) will affect each party’s willingness to reach an agreement. These include the trust of each party entering into the contract that the other can fulfill the terms. Will the wind farm be in operation in 10 or 20 years? Will the wind farm produce as much energy in 20 years as it does now? Will the buyer be in business in 20 years and still interested in purchasing electricity? Many markets devise screening (a minimum credit rating) or security requirements (a bond or risk adjusted margin deposit) that each participant must meet to be allowed to join and trade. Although providing such security initially limits the number of market participants and increases transaction costs, it builds confidence and reduces the risk of default. Another factor that could have a significant impact on call values is the limited liquidity or the ease with which a participant can enter or exit a position. These questions and problems are present whenever a market is in the early stages of development and can be resolved, but they will have an effect. Often, these concerns can influence the price that parties are willing to offer or accept. A Black-Scholes call valuation can offer a starting point for such negotiations that necessarily will be affected by supply and demand for energy price insurance, along with many other factors.2
Electricity users concerned about future electricity price volatility would be interested in buying protection each year that they can. In this example, we have a user that wants to insure that its future electricity costs do not go above twice its current cost (10 cents/kWh) for the decade starting 10 years from now. If we assume 15 percent volatility, we can use the second column of Table 2 to understand how much this protection would cost. The values in the first three rows of the second column of Table 2 are 0.12, 0.25, and 0.38; if we add these values and divide by 3 we get 0.25. This means it will cost on average 0.25 times current price (= 2.5 cents/kWh) each year to cap costs at 20 cents/kWh. In total, it will cost 25 cents/kWh to insure that future electricity costs do not exceed 20 cents/kWh for the decade of 2016 to 2025.
If we assume prices rise 5 percent a year, then by the end of the 14th year prices will have doubled. See the middle two retail price curves (green lines) of Figure 3. In year 15 the call buyer will exercise the call option and only pay 20 cents/kWh for the remaining years. The buyer “saves” a cumulative 21.4 cents/kWh during the last years of the contract. Like a home owner who buys flood insurance, if the buyer’s basement floods, the insurance company pays the claim. The call-option buyer paid out more than he recovered, but got peace of mind and benefited from the price cap.
Price doubling and 15 percent volatility over a 20-year time frame may represent an aggressive scenario. Yet almost the same result (in terms of call premium) would be obtained if volatility was only 7.5 percent and the call buyer wanted to cap prices 65 percent above the current price for the same decade. In this reduced volatility world, one would see annual price increases of 2.6 percent (zero payout, calls never exercised), 3.8 percent (recover about half of premium paid), and 5 percent (1.6 times initial premium recovered).
How might a renewable plant operator benefit from selling call options? Take a 50-MW wind farm with the following operational data:3
• Capital cost: $50 million ($1,000/kW);
• Annual production: 150 million kWh—35 percent capacity factor;4 and
• Annual Revenue: $6 million, assuming 4 cents/kWh wholesale price.
We assume the operator sells call options at twice the current wholesale price for the decade beginning in 2016. We further assume that electricity price volatility is 15 percent. In the previous example we saw that this call option will cost on average 25 percent of the current price. Using the 4 cents/kWh current price, we see that the wind farm operator could make 1 cent/kWh for selling electricity insurance that caps the price of electricity at 8 cents/kWh for the decade 2016-2025.
If the wind farm operator sells calls on 80 percent of its annual production:
• 80 percent of annual production = 120 million kWh = 0.8 x 150 million kWh;
• Call revenue for each year = $1.2 million = 120 million kWh x 1 cent/kWh; and
• Call revenue for the decade = $12 million = 10 years x $1.2 million/year.
Thus, in this example, by selling one decade’s worth of electricity price insurance today, the wind-farm operator could recover $12 million, or nearly one-fourth, of the wind-farm operator’s capital cost.
The call seller “pays” for this premium if prices more than double. In this example, the operator gives up 80 percent of revenue above 8 cents/kWh for the contract decade. This lost revenue can be clearly seen in Figure 4 by comparing the solid line (no call selling) with the dashed line (with call selling) of the same color. For either the 3.5 percent or 5 percent annual wholesale price inflation case, the call seller clearly benefits (generates more total revenue) by selling calls. In the 3.5 percent case, the price never exceeds 8 cents/kWh, so the call premium is all profit. If wholesale price inflation is 7 percent a year, the call seller ends up with less total revenue, but still may prefer selling calls, since it shifts revenue forward in time.
The revenues above do not capture the benefit of reduced debt finance costs for the call-option seller. The cost of financing the initial project represents a large fraction of the wind operator’s annual cost (60 percent in the wind-farm example). Clearly, selling call options can reduce this cost significantly. Forgoing potentially higher future electricity prices is a risk. Nevertheless, it may be viewed as a desirable tradeoff considering the more certain benefit of recovering one-fourth of capital costs immediately.
If the wind farm would produce energy beyond 20 years, say for 30 or 40 years, and one could find willing call-option buyers for the later years, it would be possible to underwrite an even greater portion of the plant capital costs. Since the value of call options increases with more time or more volatility, one can imagine a situation where proceeds from call options are sufficient to pay the entire capital cost. At that point, all the actual electricity sold would be pure profit, whether it was sold at the price cap agreed to under the call-option contract or at prevailing market rates. Perhaps more realistic (given initial liquidity and default/security concerns) would be a situation where a wind farm recovers 5 percent to 10 percent of its investment from selling calls upon project completion, and recovers most of its O&M costs each year from selling a new option 25 or 30 years out.
If renewable-energy producers were to exploit (or at least effectively communicate) the value of predictable operating costs over the long term, they would change perceptions about the cost of renewable energy. Future electricity prices are uncertain because of many factors, but a significant one is the volatility of fossil-fuel prices. Examples illustrated both the costs and benefits available to long-term call option buyers and sellers. Renewable energy sources can and should capture the value that they inherently provide: stable energy prices.
Considerable time and effort has been spent lobbying legislatures for production tax credits and renewable portfolio standards as well as for creating “artificial” markets for green tags, renewable energy credits, and voluntary (in the United States) trading of carbon emissions. It is surprising that an inherently market-oriented solution such as selling call options based on predictable long-term operating costs of fixed-cost renewable electricity has not yet been exploited properly.
In the examples presented above, the call-option buyer paid a current electricity price of 10 cents/kWh and the call option seller received a price of 4 cents/kWh. In part, these different prices reflect the real cost of delivering energy (distribution) from producer to user as well as different pricing in retail versus wholesale markets. There is an opportunity to narrow that gap in the United States electricity market, and to do so profitably. One way would be for electric utilities to buy call options from renewable energy plants and resell them to their customers, capturing a generous margin. The value is considerable and real: What consumer or business wouldn’t want to cap future energy costs?
1. From the 2004 Annual Energy Review of electricity prices http://www.eia.doe.gov/emeu/ aer/elect.html.
2. Other markets have developed successful mechanisms for reducing many types of uncertainty. Renewable producers could pool their electricity output and sell participation in the pool, thereby reducing variable output risk—the risk that an unusually low amount of wind at one farm in a given month might reduce the total value of the electricity to a buyer. Similarly, an exchange clearing mechanism such as utilized by many stock and commodity futures markets would reduce the risk of default.
3. American Wind Energy Association’s “Economics of Wind Energy” fact sheet 2002, presentation of costs and revenues for a wind farm.
4. Capacity factor measures what fraction of time the turbine generates power. One- hundred percent capacity factor means the turbine generates the theoretical maximum year round.