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2.
Derivatives and Risk in Energy Markets
Introduction
The general types of risk faced by all businesses can be
grouped into five broad categories: market risk (unexpected changes
in interest rates, exchange rates, stock prices, or commodity prices); credit/default risk; operational risk (equipment failure,
fraud); liquidity risk (inability to pay bills, inability to buy
or sell commodities at quoted prices); and political risk (new
regulations, expropriation). In addition, the financial future of a business
enterprise can be dramatically altered by unpredictable events—such
as depression, war, or technological breakthroughs—whose probability
of occurrence cannot be reasonably quantified from historical data.4
Businesses operating in the petroleum, natural gas, and
electricity industries are particularly susceptible to market risk—or
more specifically, price risk—as a consequence of the extreme
volatility of energy commodity prices. To a large extent, energy company
managers and investors can make accurate estimates of the likely success
of exploration ventures, the likelihood of refinery failures, or the performance
of electricity generators. Diversification, long-term contracts, inventory
maintenance, and insurance are effective tools for managing those risks.
Such traditional approaches do not work well, however, for managing price
risk.
With the onset of domestic market deregulation in the 1980s,
stable, administered prices for petroleum products and natural gas gave
way to widely fluctuating spot market prices. Similarly, in the late 1990s,
deregulation of wholesale electricity markets revealed that electricity
prices, when free to respond to supply and demand, can vary by factors
of more than 100 over periods of days or even hours. Spot prices for natural
gas and electricity can also vary widely by location. International crude
oil prices have long been volatile.
When energy prices fall, so do the equity values of producing
companies; as a result, ready cash becomes scarce, and it is more likely
that contract obligations for energy sales or purchases may not be honored.
When prices soar, governments tend to step in to protect consumers. Thus,
commodity price risk plays a dominant role in the energy industries, and
the use of derivatives has become a common means of helping energy firms,
investors, and customers manage the risks that arise from the high volatility
of energy prices.
Derivatives are particularly useful for managing price
risk. Their use in the energy arena is not surprising, in that they have
been used successfully to manage agriculture price risk for more than
a century. Deregulation of domestic energy industries has shown price
risk to be greater for energy than for other commodities; in a sense,
energy derivatives are a natural outgrowth of market deregulation. Derivatives
allow investors to transfer risk to others who could profit from taking
the risk, and they have become an increasingly popular way for investors
to isolate cash earnings from fluctuations in prices.
Energy price risk has economic consequences of general
interest because it can decisively affect whether desirable investments
in energy projects are actually made. Investments in large power plants
run from $200 million to over $1 billion, and the plants take 2 to 7 years
to construct. Following general discussions of risk management without
and with the use of derivatives, descriptions of various kinds of derivative
contracts, and a brief analysis of energy price volatility, this chapter
presents an illustration of the potential impact of price volatility on
the economics of investment in a natural-gas-fired combined-cycle electricity
generator. Combined-cycle generators are of particular interest because
the Energy Information Administration (EIA) and other forecasters expect
them to be the dominant choice for investments in new generating capacity
over the next decade.5 The example
shows that an economically efficient investment, one that is in society’s
interest to undertake, could generate large cash losses that must be managed.
Risk Management Without Derivatives
When investors, managers, and/or a firm’s owners are
averse to risk, there is an incentive to take actions to reduce it. Diversification—investing
in a variety of unrelated businesses, often in different locations—can
be an effective way of reducing a firm’s dependence on the performance
of a particular industry or project. In theory it is possible to “diversify
away” all the risks of a particular project;6 in practice, however, diversification is expensive and often fails because of the complexity of managing diverse businesses.7 More fundamentally, the success of most projects is strongly tied to the
state of the general economy, so that the fortunes of various businesses
and projects are not independent but move together. In the real world,
therefore, diversification is often not a viable response to risk.
Another method of managing the risk created by fluctuating
prices is to use long-term fixed-price contracts: the owner of a firm
that invests in a natural gas combined-cycle plant could simply sign a
long-term contract with a gas supplier. For example, in January 2002 it
would have been possible to lock in gas prices of $2.59 per thousand British
thermal units (Btu), $2.92 for 2003, and so on. However, such a hedging
strategy still would leave some risk. If the spot market price for natural
gas in 2003 turned out to be only $2.70 as opposed to $2.92, power from
the firm’s plant might not be competitive, because other plant owners
could purchase natural gas at $2.70 and undercut the price of power from
the plant with a higher fuel cost of $2.92. Conversely, if natural gas
prices in 2003 rose to $4.00, the seller might choose to default on the
plant’s gas supply contract.
Insurance contracts can also be used to manage risk. For
example, there is some probability that the natural gas plant in the previous
example might malfunction and be taken out of service. The owner of the
plant could purchase an insurance contract that would provide compensation
for lost revenue (and perhaps for repair costs) in the event of an unplanned
outage. The insurance would essentially shift the risks from the owner
of the plant to the “counterparty” of the contract (in this
case, the insurance provider). The counterparty would accept the risk
if it had greater ability to pool risks and/or were less averse to risk
than was the owner of the plant.
The plant owner could also reduce the risk of adverse movements
in future natural gas prices by purchasing the fuel in the current period
and storing it as inventory. If prices fell, the firm could buy the fuel
on the open market; if they increased, it could draw down the inventory.
This could be an expensive way to manage risk, because storage costs could
be considerable.
Managing Risk With Derivative Contracts
Derivatives are contracts, financial instruments, which
derive their value from that of an underlying asset. Unlike a stock or
securitized asset, a derivative contract does not represent an ownership
right in the underlying asset. For example, a call option on IBM stock
gives the option holder the right to buy a specified quantity of IBM stock
at a given price (the “strike price”). The option does not represent
an ownership interest in IBM (the underlying asset). The right to purchase
the stock at a given price, however, is of value. If, for instance, the
option is to buy a share of IBM stock at $40, that option will be worth
at least $60 when the stock is selling for $100. The option holder can
exercise the option, pay $40 to acquire the stock, and then immediately
sell the stock at $100 for a $60 profit.
The asset that underlies a derivative can be a physical
commodity (e.g., crude oil or wheat), foreign or domestic currencies,
treasury bonds, company stock, indices representing the value of groups
of securities or commodities, a service, or even an intangible commodity
such as a weather-related index (e.g., rainfall, heating degree days,
or cooling degree days). What is critical is that the value of the underlying
commodity or asset be unambiguous; otherwise, the value of the derivative
becomes ill-defined.
The following sections describe various derivative instruments
and how they can be used to isolate and transfer risk. Most of the discussion
is in terms of price risk, but derivatives have also been developed with
other non-price risks, such as weather or credit. When used prudently,
derivatives are efficient and effective tools for reducing certain risks
through hedging.
Forward Contracts
Forward contracts are a simple extension of cash or cash-and-carry
transactions. Whereas in a standard cash transaction the transfer of ownership
and possession of the commodity occur in the present, delivery under a
forward contract is delayed to the future. For example, farmers often
enter into forward contracts to guarantee the sale of crops they are planting.
Forward contracts are sometimes used to secure loans for the farming operation.
In energy markets, an oil refiner may enter into forward contracts to
secure crude oil for future operations, thereby avoiding both volatility
in spot oil prices and the need to store oil for extended periods.
Forward contracts are as varied as the parties using them,
but they all tend to deal with the same aspects of a forward sale. All
forward contracts specify the type, quality, and quantity of commodity
to be delivered as well as when and where delivery will take place. In
addition, forward contracts set a price or pricing formula. The simplest
forward contract sets a fixed (firm) price. More elaborate price-setting
mechanisms include floors, ceilings, and inflation escalators. By setting
such a price, the buyer and seller are able to reduce or eliminate uncertainty
with respect to the sale price of the commodity in the future. Knowing
such prices with certainty may allow forward contract users to better
plan their commercial activity. Finally, the contract may contain miscellaneous
terms or conditions, such as establishing the responsibilities of the
parties under circumstances where one party fails to perform in an acceptable
manner (lack of delivery, late delivery, poor quality, etc.). Overall,
forward contracts are designed to be flexible so as to match the commercial
merchandising needs of the parties entering into them.
A direct result of the forward pricing and delivery features
of forward contracts are default and credit risks. In the case of long-term
forward contracts, the exposure to default and credit risks may be substantial.
Parties to forward contracts must be concerned about the other party’s
performance, particularly when the value of the contract moves in one’s
favor. For example, if an oil refiner has contracted to purchase oil at
$19 per barrel, its level of concern that the other party will perform
by delivering oil rises progressively as the price of oil rises above
$19 per barrel and the incentive for the counterparty to “walk away”
from the contract increases. To deal with the risk of default, parties
scrutinize the creditworthiness of counterparties and deal only with parties
that maintain good credit ratings. They may also limit how much they will
buy from or sell to a particular trader based on his credit rating. In
some circumstances parties may also ask counterparties to post collateral
or good faith deposits to assure performance. Ultimately, how parties
deal with default and credit risk in a forward contract is up to them.
Futures Contracts
Futures trading in the United States evolved from the trading
of forward contracts in the mid-1800s at the Chicago Board of Trade (CBOT).
By the 1850s, the practice of forward contracting had become established
as farmers and grain merchants in the Midwest sought to reduce their exposure
to changes in the price of grain they were producing or storing.8 After the CBOT standardized forward contracts, speculators began to purchase
and sell the contracts in an effort to profit from the change in the value
of the contracts. Actual delivery of the commodity became of secondary
importance.9 Eventually this practice
became institutionalized on the CBOT, and the modern futures contract
was born. Today futures contracts are traded on a number of exchanges
in the United States and abroad (Table
1).
Forward contracts have problems that can be serious at
times. First, buyers and sellers (counterparties) have to find each other
and settle on a price. Finding suitable counterparties can be difficult.
Discovering the market price for a delivery at a specific place far into
the future is also daunting. For example, after the collapse of the California
power market in the summer of 2000, the California Independent System
Operator (ISO) had to discover the price for electricity delivered in
the future through lengthy, expensive negotiation, because there was no
market price for future electricity deliveries. Second, when the agreed-upon
price is far different from the market price, one of the parties may default
(“non-perform”). As companies that signed contracts with California
for future deliveries of electricity at more than $100 a megawatt found
when current prices dropped into the range of $20 to $40 a megawatt, enforcing
a “too favorable” contract is expensive and often futile. Third,
one or the other party’s circumstances might change. The only way
for a party to back out of a forward contract is to renegotiate it and
face penalties.
Futures contracts solve these problems but introduce some
of their own. Like a forward contract, a futures contract obligates each
party to buy or sell a specific amount of a commodity at a specified price.
Unlike a forward contract, buyers and sellers of futures contracts deal
with an exchange, not with each other. For example, a producer wanting
to sell crude oil in December 2002 can sell a futures contract for 1,000
barrels of West Texas Intermediate (WTI) to the New York Mercantile Exchange
(NYMEX), and a refinery can buy a December 2002 oil future from the exchange.
The December futures price is the one that causes offers to sell to equal
bids to buy—i.e., the demand for futures equals the supply. The December
futures price is public, as is the volume of trade. If the buyer of a
December futures finds later that he does not need the oil, he can get
out of the contract by selling a December oil future at the prevailing
price. Since he has both bought and sold a December oil future, he has
met his obligations to the exchange by netting them out.
Table 2 illustrates
how futures contracts can be used both to fix a price in advance and to
guarantee performance. Suppose in January a refiner can make a sure profit
by acquiring 10,000 barrels of WTI crude oil in December at the current
December futures price of $28 per barrel. One way he could guarantee the
December price would be to “buy” 10 WTI December contracts.
The refiner pays nothing for the futures contracts but has to make a good-faith
deposit (“initial margin”) with his broker. NYMEX currently
requires an initial margin of $2,200 per contract. During the year the
December futures price will change in response to new information about
the demand and supply of crude oil.
In the example, the December price remains constant until
May, when it falls to $26 per barrel. At that point the exchange pays
those who sold December futures contracts and collects from those who
bought them. The money comes from the margin accounts of the refiner and
other buyers. The broker then issues a “margin call,” requiring
the refiner to restore his margin account by adding $20,000 to it.
This “marking to market” is done every day and
may be done several times during a single day. Brokers close out parties
unable to pay (make their margin calls) by selling their clients’
futures contracts. Usually, the initial margin is enough to cover a defaulting
party’s losses. If not, the broker covers the loss. If the broker
cannot, the exchange does. Following settlement after the first change
in the December futures price, the process is started anew, but with the
current price of the December future used as the basis for calculating
gains and losses.
In September, the December futures price increases to $29
per barrel, the refiner’s contract is marked to market, and he receives
$30,000 from the exchange. In October, the price increases again to $35
per barrel, and the refiner receives an additional $60,000. By the end
of November, the WTI spot price and the December futures price are necessarily
the same, for the reasons given below. The refiner can either demand delivery
and buy the oil at the spot price or “sell” his contract. In
either event his initial margin is refunded, sometimes with interest.
If he buys oil he pays $35 per barrel or $350,000, but his trading profit
is $70,000 ($30,000 + $60,000 - $20,000. Effectively, he ends up paying
$28 per barrel [($350,000 - $70,000)/ 10,000], which is precisely the
January price for December futures. If he “sells” his contract
he keeps the trading profit of $70,000.
Several features of futures are worth emphasizing. First,
a party who elects to hold the contract until maturity is guaranteed the
price he paid when he initially bought the contract. The buyer of the
futures contract can always demand delivery; the seller can always insist
on delivering. As a result, at maturity the December futures price for
WTI and the spot market price will be the same. If the WTI price were
lower, people would sell futures contracts and deliver oil for a guaranteed
profit. If the WTI price were higher, people would buy futures and demand
delivery, again for a guaranteed profit. Only when the December futures
price and the December spot price are the same is the opportunity for
a sure profit eliminated.
Second, a party can sell oil futures even though he has
no access to oil. Likewise a party can buy oil even though he has no use
for it. Speculators routinely buy and sell futures contracts in anticipation
of price changes. Instead of delivering or accepting oil, they close out
their positions before the contracts mature. Speculators perform the useful
function of taking on the price risk that producers and refiners do not
wish to bear.
Third, futures allow a party to make a commitment to buy
or sell large amounts of oil (or other commodities) for a very small initial
commitment, the initial margin. An investment of $22,000 is enough to
commit a party to buy (sell) $280,000 of oil when the futures price is
$28 per barrel. Consequently, traders can make large profits or suffer
huge losses from small changes in the futures price. This leverage has been the source of spectacular failures in the past.
Futures contracts are not by themselves useful for all
those who want to manage price risk. Futures contracts are available for
only a few commodities and a few delivery locations. Nor are they available
for deliveries a decade or more into the future. There is a robust business
conducted outside exchanges, in the over-the-counter (OTC) market, in
selling contracts to supplement futures contracts and better meet the
needs of individual companies.
Options
An option is a contract that gives the buyer of the contract
the right to buy (a call option) or sell (a put option) at a specified
price (the “strike price”) over a specified period of time.
American options allow the buyer to exercise his right either to buy or
sell at any time until the option expires. European options can be exercised
only at maturity. Whether the option is sold on an exchange or on the
OTC market, the buyer pays for it up front. For example, the option to
buy a thousand cubic feet of natural gas at a price of $3.40 in December
2002 may cost $0.14. If the price in December exceeds $3.40, the buyer
can exercise his option and buy the gas for $3.40. More commonly, the
option writer pays the buyer the difference between the market price and
the strike price. If the natural gas price is less than $3.40, the buyer
lets the option expire and loses $0.14. Options are used successfully
to put floors and ceilings on prices; however, they tend to be expensive.
Swaps
Swaps (also called contracts for differences) are the most
recent innovation in finance. Swaps were created in part to give price
certainty at a cost that is lower than the cost of options. A swap contract
is an agreement between two parties to exchange a series of cash flows
generated by underlying assets. No physical commodity is actually transferred
between the buyer and seller. The contracts are entered into between the
two counterparties, or principals, outside any centralized trading facility
or exchange and are therefore characterized as OTC derivatives.
Because swaps do not involve the actual transfer of any
assets or principal amounts, a base must be established in order to determine
the amounts that will periodically be swapped. This principal base is
known as the “notional amount” of the contract. For example,
one person might want to “swap” the variable earnings on a million
dollar stock portfolio for the fixed interest earned on a treasury bond
of the same market value. The notional amount of this swap is $1 million.
Swapping avoids the expense of selling the portfolio and buying the bond.
It also permits the investor to retain any capital gains that his portfolio
might realize.
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Figure 1 illustrates
an example of a standard crude oil swap. In the example, a refiner and
an oil producer agree to enter into a 10-year crude oil swap with a monthly
exchange of payments. The refiner (Party A) agrees to pay the producer
(Party B) a fixed price of $25 per barrel, and the producer agrees to
pay the refiner the settlement price of a futures contract for NYMEX light,
sweet crude oil on the final day of trading for the contract. The notional
amount of the contract is 10,000 barrels. Under this contract the payments
are netted, so that the party owing the larger payment for the month makes
a net payment to the party owing the lesser amount. If the NYMEX settlement
price on the final day of trading is $23 per barrel, Party A will make
a payment of $2 per barrel times 10,000, or $20,000, to Party B. If the
NYMEX price is $28 per barrel, Party B will make a payment of $30,000
to Party A. The 10-year swap effectively creates a package of 120 cash-settled
forward contracts, one maturing each month for 10 years.
So long as both parties in the example are able to buy
and sell crude oil at the variable NYMEX settlement price, the swap guarantees
a fixed price of $25 per barrel, because the producer and the refiner
can combine their financial swap with physical sales and purchases in
the spot market in quantities that match the nominal contract size. All
that remains after the purchases and sales shown in the inner loop cancel
each other out are the fixed payment of money to the producer and the
refiner’s purchase of crude oil. The producer never actually delivers
crude oil to the refiner, nor does the refiner directly buy crude oil
from the producer. All their physical purchases and sales are in the spot
market, at the NYMEX price. Figure
2 shows the acquisition costs with and without a swap contract.
Many of the benefits associated with swap contracts are
similar to those associated with futures or options contracts.10 That is, they allow users to manage price exposure risk without having
to take possession of the commodity. They differ from exchange-traded
futures and options in that, because they are individually negotiated
instruments, users can customize them to suit their risk management activities
to a greater degree than is easily accomplished with more standardized
futures contracts or exchange-traded options.11 So, for instance, in the example above the floating price reference for crude oil might be switched from the NYMEX contract, which calls for delivery
at Cushing, Oklahoma, to an Alaskan North Slope oil price for delivery
at Long Beach, California. Such a swap contract might be more useful for
a refiner located in the Los Angeles area.
Although swaps can be highly customized, the counterparties
are exposed to higher credit risk because the contracts generally are
not guaranteed by a clearinghouse as are exchange-traded derivatives.12 In addition, customized swaps generally are less liquid instruments, usually
requiring parties to renegotiate terms before prematurely terminating
or offsetting a contract.
Energy Price Risk
Energy prices vary more than the prices of other commodities
and are also sensitive to location. Price variation increases the difficulty
of cash and credit management and of assessing the worth of prospective
investments. Historical price data clearly illustrate the relatively high
volatility of energy prices.
Figure 3 compares
the spot prices for sugar, gold, and crude oil and an index of stock prices
(S&P 500) from January 1989 to December 2001. The price of sugar can
be seen to be fairly constant at around 10 cents per pound, except for
a spike in late 2000 and early 2001. Gold prices, which ranged between
roughly $350 and $420 per ounce from 1989 through 1995, have generally
fallen since mid-1996. The S&P 500 index has generally risen in fits
and starts to a peak in the early part of 2000, followed by a steep decline.
In contrast to the patterns apparent in other spot prices,
energy commodity prices show no discernible trends. For example, Figure
4 shows spot market prices for crude oil (West Texas Intermediate
at Cushing, Oklahoma), heating oil (New York Harbor), unleaded gasoline
(New York Harbor), and natural gas (Henry Hub, Louisiana). The price of
crude oil appears to fluctuate randomly around an average of about $20
per barrel, and heating oil and gasoline prices tend to move with the
oil price. The spot market price of natural gas peaks periodically with
no obvious warning.
Wholesale electricity prices since 1999 (Figure
5) in the Midwest (ECAR) and Pennsylvania-Maryland-New Jersey (PJM)
regions, at the California-Oregon border (COB), and at Palo Verde, a major
hub for importing electricity into California, have shown a number of
very large “spikes” during the summer months. In addition, wholesale
electricity prices on the West Coast were extremely volatile in the winter
and spring of 2001.
Natural gas and electricity are particularly subject to
wide price swings as demand responds to changing weather. Inventories
are of limited help in damping price spikes, because natural gas users
typically do not maintain large inventories on site, and the options for
storing electricity are few and expensive (pumped hydro, reservoirs, idle
capacity, etc.). Shipping low-cost supplies to areas where prices are
high can be very difficult in these industries because of limited capability
on the physical networks connecting customers to suppliers. Limited storage
capacity and the lack of cheaper alternative supplies from other areas
can cause prices to soar in areas where demand increases suddenly.
Daily price volatility is the standard deviation of the
percentage change in the commodity’s price. The standard deviation
is a measure of how concentrated daily percentage price changes are around
the average percentage price change. For a normal distribution, approximately
67 percent of all the percentage price changes will be within one standard
derivation of the average percentage change. Volatility is usually
expressed on an annual basis, where a year is understood to be the number
of trading days, usually 252, in a calendar year. Annual volatility is
calculated by multiplying daily volatility times 15.87, which is the square
root of 252.
Price volatility is caused by shifts in the supply and
demand for a commodity. Natural gas and wholesale electricity prices are
particularly volatile for several reasons. Demand increases quickly in
response to weather, and “surge” production is limited and expensive.
In addition, neither can be moved to where it is needed quickly, and local
storage is limited, especially in the case of electricity. Public policy
efforts to reduce volatility have focused on increasing reserve production
capability and increasing transmission and transportation capability.
Recently there has been an emphasis on making prices more visible to users
so that they will conserve when supplies are tight, thus limiting price
spikes.
The average of the annual historical price volatility for
a number of commodities from 1992 to 2001 is shown in Table 3. The financial group has the lowest overall volatility, and the
electricity group has by far the highest. Generally, energy commodities
have distinctly higher volatility than other types of commodities. The
following example illustrates the impact of price volatility on the profitability
of investments in electricity generation capacity.
Price Risk and Returns to Investment in a New
Combined-Cycle Generator
EIA forecasts indicate that meeting U.S. demand for electricity
over the next decade will require about 198 gigawatts of new generating
capacity. About 7 gigawatts of the required new capacity is projected
to come from coal-fired plants, 170 gigawatts from natural-gas-fired combined-cycle
and combustion turbine plants, and the remainder from other technologies.13 Investment in the new projects will depend on how investors assess future
natural gas and electricity prices and the consequences of price variation
for cash earnings and project returns.
The case of a typical gas-fired combined-cycle plant shows
what is at stake. Investors compare the cost of a new plant with the cash
it is expected to generate over the life of its operation. The conventional
way of making the comparison is called net present value (NPV) analysis.
The stream of cash payments to investors is called the net cash flow.
Each year’s net cash return is adjusted for the time value of money
(the implicit interest on delayed receipt) and for risk—i.e., discounted
at the firm’s cost of capital. The discounted net cash flows are
added up, and the resulting sum is called the present value of net cash
flows. If the present value of future net cash flows exceeds the initial
investment, then the project is economical and should be undertaken.14 Such projects are said to have a positive net present value and projects
with a negative net present value should not be undertaken.15
Table 4 shows the
cash flows that a new generator would be expected to produce under a recent
EIA forecast of natural gas and electricity prices.16 Details of this and other calculations in this example are included in
Appendix B. Over its 20-year life, the project has a positive NPV of $2,118,017.17 Thus, the power plant should be built because it would be profitable,
generating an additional $2 million for the investment after satisfying
obligations to debt holders (interest payment at 10.5 percent) and equity
holders (equity cost of dividends and/or capital gains of 17.5 percent).
Moreover, after the initial investment it generates positive net cash
flows in every year.
When input and output prices are uncertain, the NPV is
no longer a single number but a distribution. Under wholesale price deregulation,
investors in generators face not only fuel price risk but also electricity
price risk. As shown in Figure 5 above, electricity prices have been very volatile in California and PJM
for the past few years. From a generator’s point of view, increased
electricity price is not a concern; however, lower price can affect the
viability of the new investment. Simulating future outcomes by assuming
historical volatilities is one way to calculate the probability distribution
of a project’s NPV.18 Among
other things, the distribution of NPV shows the probability that an investment
will turn out to be profitable after the fact.
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Figure 6 shows
the impact on the NPV of the investment when electricity and natural gas
prices are varied by plus and minus 77 percent and 47 percent, as a standard
deviation, from their expected prices, respectively.19 In this simulation, there is an 83-percent probability that the project’s
NPV would be at least zero, with mean of $110 million, and a 17-percent
probability that it would be unprofitable.20 A summary of the simulation results is shown in Table 5. Despite the significant probability of failure, it makes economic
sense for society to invest in the generator, because the project has
a single positive NPV of $2,118,017.21 The problem is that individual investors, not society as a whole, bear the risk if the investment goes wrong.
To the extent that prices vary because of rapid changes
in supply and demand, energy price volatility is evidence that markets
are working to allocate scarce supplies to their best uses. As shown by
the example, however, price variation also has the effect of making energy
investment risky. Investors have difficulty judging whether current prices
indicate long-term values or transient events. Bad timing can spell ruin.
In addition, even good investments can generate large temporary cash losses
that must be funded.
Chapter 2 - Tables 
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