The physical nature of electricity imposes market constraints quite unlike
those seen in other energy markets. With today’s technology, electricity
storage is impractical and uneconomic. This creates a market that is bounded
by end users and generators; storage players and holding investors are
precluded from the physical power market. Residential power demand is
currently price-inelastic and grid managers are reluctant to interrupt
delivery. When supply is constrained, excess demand enables long players
to charge prices that are many multiples of generation cost. Transmission
limitations can isolate certain regions, leading to price spikes in the
island region while adjacent regions enjoy normal prices.

Some power trading shops that were established as branches of existing
crude or natural gas shops have encountered power-specific obstacles they
have been unequipped to overcome. As a result, the market has seen some
shops exit and others consolidate. The recent wave of consolidation will
most likely continue. Power traders and marketers face difficult analytical
problems in spot price estimation, forward price and volatility curve
construction, option pricing, and structured transaction valuation. Successfully
solving these problems requires techniques and skill sets somewhat different
from those used in the crude, products, and natural gas markets. Sophisticated
structured deals are becoming more prevalent as trading shops adapt to
the market’s risk characteristics. Risk management is now a key component
of every aspect of dealmaking and quantitative analysts are enjoying a
boom in employment demand.

The power market’s ongoing adaptation to electricity’s unique demands
is observable through several trends: the consolidation of industry players
continues; structured transaction volume is growing; risk management is
now a process-wide activity; and trading shops are demanding quantitatively-trained
analysts as never before. We describe the development of these trends.


The power market exhibits interesting and unique characteristics. Electricity
is a perishable commodity, market price is highly volatile, price distributions
are usually not lognormal as observed in capital and equity markets, supply
and demand dynamics are abrupt and volatile, transmission capabilities
and constraints are intermittent, and contract liquidity suffers dramatically
from a relatively small number of market participants. Because of these
market characteristics, success in trading and hedging demands price forecasting
techniques, sophisticated financial risk management, and advanced quantitative
analysis heretofore unseen in traditional energy markets such as crude,
products, and natural gas. Some power trading shops have failed and exited
the industry. Others have consolidated to survive adverse financial impacts
arising from failure to manage these difficult problems. The industry
is rapidly adjusting. Market players continue to both consolidate and
exit the industry. Structured product usage is increasing and is indeed
essential for producers. Risk management is now an essential role within
trading, credit, and physical performance as well as the traditional risk
management and financial reporting functions. Finally, quantitatively
trained personnel are in record demand on the energy job market. We highlight
aspects of these ongoing trends.

Figure 1
Growth in quarterly power sales

Consolidation in the Power Industry

McGraw-Hill’s Power Markets Week has tracked and ranked power marketers
by volume (megawatt-hour) sales since 1995. Since the emergence of broad
wholesale trading in 1997, the list of significant marketers (i.e., large
enough to be tracked) has grown from 56 players in Q1-1997, to a peak
population of 144 marketers in Q3-1999, to the most recent total of 117
in Q1-20001. While the population mix of marketers has changed dramatically
through the rankings, both the growth rate and total number of marketers
have peaked and are currently declining. Over the same period the volume
of power traded has grown steadily. The Power Report, an industry analysis
newsletter, calculated that 80 percent of the growth in U.S. energy demand
since 1990 has been met by electricity2. Figure 1 illustrates the evolution
of the power marketer population and volume of power traded since Q1-1997.
To provide some insight into the changing mix of power marketers, Table
2 lists current and past mergers on file with the Federal Energy Regulatory
Commission. The classical economic consolidation phase of a growing industry,
with the accompanying entrance and exit of firms, is clearly underway.
The broker services market reflects consolidation as well; Table 1 lists
broker shops that have merged or exited the power trading business.

Table 1
Broker shops exiting power trading or merging with other broker shops.
(Source: Industry survey of power brokers and traders; not intended to
be a comprehensive list.)

Table 2
List of Recent Power Marketer and Power-Related Mergers
Delmarva Power and Light Company approved 5/17/95

Public Service Company of Colorado

Southwestern Public Service Co.

approved 3/12/97

Union Electric Company

Central Illinois Public Service Co.

approved 10/15/97

Baltimore Gas and Electric Company

Potomac Electric Power Company

approved 04/16/97

IES Utilities Inc.

Interstate Power Co.

Wisconsin Power & Light Co.

approved 11/12/97

Enron Corporation

Portland General Corporation

approved 02/26/97

Ohio Edison Company


approved 10/29/97

Atlantic City Electric Company

Delmarva Power & Light Company

approved 07/30/97

San Diego Gas & Electric Company

Enova Energy, Inc.

approved 06/25/97

Duke Power Company

PanEnergy Corporation

approved 05/28/97

Long Island Lighting Company

Brooklyn Union Gas Company

approved 07/16/97

Destec Energy, Inc.

NGC Corporation

approved 06/25/97

PG&E Corporation

Valero Energy Corporation

approved 07/16/97

Morgan Stanley Capital Group Inc.

Dean Witter, Discover & Co

approved 04/30/97

NorAm Energy Services, Inc.

Houston Industries, Inc.

approved 07/30/97

Western Resources Inc.

Kansas City Power & Light Co.

hearing 03/31/99

Louisville Gas and Electric Co.

Kentucky Utilities Company

approved 03/27/98

Salomon Inc. (Phibro)

Travelers Group, Inc.

approved 11/26/97

Wisconsin Energy Corporation, Inc.

Edison Sault Electric Company

approved 04/22/98

Duke Energy Corporation

Nantahala Power and Light Company

approved 06/01/98

WPS Resources Corporation

Upper Peninsula Energy Corporation

approved 05/27/98

American Electric Power Company

Central and Southwest

approved 03/15/00

Consolidated Edison Co. of NY, Inc.

Orange and Rockland Utilities, Inc.

approved 01/27/99

MidAmerican Energy Holdings Co.

CalEnergy Company, Inc.

approved 12/16/98

Sierra Pacific Power Company

Nevada Power Company

approved 04/15/99

BEC Energy

Commonwealth Energy System

approved 07/01/99


The AES Corporation

approved 06/16/99

New England Electric System

National Grid Group plc

approved 06/16/99


ScottishPower plc

approved 06/16/99

New England Electric System

Eastern Utilities Associates

approved 09/29/99

El Paso Energy Corporation

Sonat Inc.

approved 09/29/99

Dominion Resources, Inc.

Consolidated Natural Gas Company

approved 11/10/99

Illinova Corp

Dynegy Inc.

approved 11/10/99

Northern States Power Co. (Minn.)

New Century Energies, Inc.

approved 01/12/00

Southern Indiana Gas & Electric Co.

Indiana Gas Co.

approved 12/20/99

Pennsylvania Enterprises

Southern Union Co.

approved 11/01/99

Energy East Corp.

CMP Group, Inc.

approved 04/03/00

Commonwealth Edison Co.

PECO Energy Co.

approved 04/12/00

UtiliCorp United, Inc.

St. Joseph Light & Power Co.

pending N/A

UtiliCorp United, Inc.

The Empire District Electric Co.

pending N/A

Consolidated Edison, Inc.

Northeast Utilities

approved 06/01/00

Florida Progress Corporation

CP&L Energy, Inc.

pending N/A

Sierra Pacific Power Co.

Nevada Power Co.

Portland General Electric

pending N/A

Consolidated Water Power Co.

Stora Enso Oyj

approved 06/15/00

PowerGen plc

LG&E Energy Corporation

pending N/A

Interstate Power Company

IES Utilities, Inc

pending N/A

El Paso Energy Corporation

Coastal Corporation

pending N/A

NiSource Inc.

Columbia Energy Group

pending N/A

Indeck Capital, Inc.

Black Hills Corporation

approved 06/16/00

Entergy Power Marketing Corp.

Koch Energy Trading, Inc.

pending 06/21/00  

Common reasons for recent power marketer mergers are cited in the industry
press. These include reducing costs, increasing earnings, improving competitive
position, and simply growing in size in order to compete when retail competition
ensues. Less frequently cited but prevalent of late are instances of poor
trading results and consequent industry exit or merger with a stronger partner.
The current environment is somewhat different from that in 1998 and 1999,
when many marketers were willing to sacrifice profits in return for larger
market share. Navigant Consulting, a Chicago-based energy analysis firm,
studied profit margins and volumes traded for the top ten marketers and
electric utilities and found that firms were valuing the establishment of
firm name and identity more than profit margins during that period3. Further,
Navigant forecast that by 2004, only about a dozen large marketers would
survive the industry shakeout. An earlier study for the US Department of
Energy by Policy Assessment Corporation4 forecast as few as five large survivors
following the industry’s transition to retail competition.

The volatile price, supply and demand, and liquidity problems in electricity
trading are undoubtedly contributory factors to loss-driven consolidation
– many firms have been simply unequipped to manage these technical challenges.
The recent wave of consolidation activity will continue until the physical
market’s characteristics change markedly – that is, until significantly
more generation is installed, transmission assets are expanded and constraints
relieved, and market inefficiencies due to incomplete deregulation are

Structured Product Necessity and Development

It is worth noting that since the volume of power traded is growing while
the number of marketers is nearly flat or declining (Figure 1), the volume
share of incumbents is growing. In other words, the number of active shops
is falling but the volume handled by each shop is growing. Larger volumes
magnify the financial impact of adverse market moves on an organization.
This fact necessitates an increased focus on structurally managing exposure
via shaped transactions, as well as improved risk management functions
and stronger quantitative analysis.

Power traders who transacted in 1997 recall that the $100/MWh price level
was commonly accepted as a practical market ceiling. Only a year later,
day-ahead prices as high as $4,000/MWh and hourly prices near $10,000/MWh
shocked market expectations and shuttered a number of shops who were exposed
to short positions. Several marketers also defaulted on their contractual
delivery obligations, propagating the damage to downstream trading partners.
Lawsuits are still ongoing from the price events of June 1998. Similar
price events occurred throughout the summers of 1998 and 1999. While 2000
has been unseasonably cool, prudent power marketers are more risk averse
in their trading practices due to the continuing possibility of similar
price spikes.

Ordinary long and short positions expose the position holder to unlimited
rising price risk (for short positions) and large, but limited, falling
price risk (for long positions). Against forward contracts prior to delivery,
vanilla European options on swaps provide collar mechanisms. Against forward
contracts taken to delivery, “daily” options provide collar mechanisms.
A daily option for a particular month is a portfolio of European options,
one option for each delivery day in the month’s contract, where each option
is exercised on the prior business day.

There are two major problems using these elementary option strategies
to manage the risk of forward contracts. The first problem is liquidity;
relatively few marketers actively trade power options and fewer still
make markets in them. One prominent power option broker estimated that
the volume of options transacted has tripled annually since 1998, but
added that days can pass with only a few trades across all Eastern Interconnect
markets. The second problem is market incompleteness. When forward option
contracts are written, the underlying security is actually a basket of
individual daily physical power contracts, one obligation for each delivery
day in the month of the contract. However, the market does not trade the
individual delivery days until the month of delivery. Technically, this
means the basis set of these securities is incomplete. What this means
is that traders cannot fully hedge daily options on a forward basis, and
also cannot fully hedge individual daily physical power contracts on a
forward basis. Since the largest determinant of a single day’s price spike
occurring is short-term weather, which at present can’t be reliably forecast
more than a few days in advance, this particular imperfection in market
structure will likely remain.

As an example of the difficulty in hedging these contracts, consider
a trader who enters into a short forward contract for June delivery, selling
the contract for $50/MWh in April, two months prior to delivery. If taken
to delivery, the position will lose money each day in June that the daily
physical power contract trades above $50/MWh and will make money when
the dailies trade below $50/MWh. A single day’s price spike at $2,000/MWh
could prove disastrous, but the only forward hedging mechanism available
is to purchase a daily call option to limit price increase exposure. Given
the price spikes seen in recent summers, such daily options are priced
by the market to reflect the possibility of many days in the thousand-dollar
price regime. As a result, the premium demanded for such options is a
significant liability for all days during June delivery when prices don’t
increase beyond the option’s strike price.


Figure 2
Forward power prices for the June Into TVA power contract reflected
the possibility of daily price spikes, but daily physical delivery prices
failed to meet that expectation, resulting in a severe forward/daily price
disconnect. The corresponding natural gas situation lacks such a disconnect.


As an example of the forward/daily physical price independence, consider
Figure 2 which illustrates the performance of the into TVA power contract
for June 2000 delivery. The behavior of the forward contract price exhibits
the market’s expectation of possible price spikes, but the daily prices
for June delivery reflect cool weather, weak demand, sufficient generation
capability, and the lack of transmission constraints – i.e. low prices.
Marketers who took long June TVA positions into daily delivery incurred
heavy financial losses. To contrast with another energy commodity, compare
the forward natural gas contract price levels seen in Figure 2 with the
daily gas delivery prices. The daily volatility and forward/daily price
disconnects seen in the power market are generally absent in the more
mature, efficient, and complete natural gas market.

Some marketers have tried to address these hedging problems by introducing
exotic options from the capital and equity markets: Asian, Bermudan, and
barrier options have been floated in the broker market but have been thinly
traded, if at all. Again, liquidity is a major constraint. Since derivatives
such as these have not yet solved such hedging problems, many marketers
have turned to more elaborate structured, or shaped transactions. Structured
“one-off” agreements are customized to the parties’ specific needs and
risk tolerances, but require lengthy valuation, negotiation, and contract
legal review cycles. Fuel tolling, must-take/optional-take, capped and
floored volume, capped and floored price, and weather-dependent payment
terms are examples of features currently seen in structured power transactions.
Such sophisticated structured contracts will continue to increase in volume,
especially as domestic markets proceed to full deregulation and retail

Proliferation of Risk Management Roles Across Trading Functions

A risk manager’s job in power trading used to entail producing a daily
position report for trading management. Events such as $4,000/MWh spot
prices, defaulting counterparties, failing generation units, and incorrectly
marked positions have stimulated broader applications for risk management
across trading organizations. We highlight a few key roles:

Market price risk: Spot power price volatility5 approaching 1,600
percent has occurred in summer months and forward price volatility lies
in the 40 percent to 60 percent range. Traders manage this price risk
with forward, daily, option, and structured contracts. Payoff shaping
with caps, floors, and collars is common. Daily determination of outright
power position (forward and spot contracts) and derivative positions requires
a risk team knowledgeable in determining forward-equivalent positions
for options (delta-equivalent) and capable of managing a wide assortment
of books across locations and delivery terms. Correctly pricing the derivative
components of a book is another complex task necessary for daily mark-to-market
reporting and Value-at-Risk exposure reporting. In some shops the risk
reporting team is larger than the trading team; this is reasonable if
many locations and products are traded. This functional area is growing
as fast as product types emerge.

Credit risk: The events of June 1998, which featured massive defaults,
resulted in the immediate executive review of the credit management function
in nearly every power shop. Since the power market today is dominated
by over-the-counter, phone-brokered trades, there is no performance guarantee
mechanism as seen in exchange markets6. In addition to standard OTC trading
credit mechanisms such as letters of credit, corporate guarantees, and
netting agreements, a prudent shop should now have real-time counterparty
exposure tracking. As traders enter deals into computer systems, net counterparty
exposure is monitored and automatically compared to trigger levels.

When exposure reaches defined trigger limits, credit action is usually
immediate: trading with the particular counterparty is halted until additional
credit is posted or outstanding balances are wired. Financial review of
prospective trading partners now occurs every quarter, typically, and
a group of credit professionals are wholly dedicated to counterparty selection
and rejection. This area is undergoing continual refinement.

Operational risk: Basing a summer trading portfolio upon flawless
operation of a generation asset could be catastrophic in the event of
plant failure. Power marketers with a large portfolio of generation assets
may choose to self-insure. Alternatively, power plant unit insurance is
now a viable product available from several large insurance concerns.
This insurance function is growing rapidly.

Accounting risk: An active power trading firm may trade positions
spanning 10 to 20 delivery locations, with corresponding transmission
positions and aligned fuel positions. These products may trade in monthly
contracts ranging from the current month out to two years, and in summer
contracts or calendar contracts out to five years. Further, the current
month contract is divided into ad-hoc delivery segments that change daily:
next-day, balance-of-week, next-week, and balance-of-month deals. Many
packaged and customized software systems are now offered to support financial
trading, trade capture, credit approval, position tracking, mark-to-market,
Value-at-Risk, exception reporting and on-demand data mining. However,
capturing the physical aspect of the industry remains a customized solution.
Use and support of these systems is an ongoing challenge, and cross-functional
systems integration will continue to evolve.

Power trading demands an increasingly broad skill base in these areas
of risk management and the industry will undoubtedly see ongoing refinement
of these roles.

Quantitative Requirements and Staff Demands

The Power Marketing
compiles a weekly online directory (
of power industry employment opportunities. Recently (07/31/00) the directory
listed 205 job openings of which fully 33 percent (67 openings) were for
quantitative analyst or risk analyst positions. In contrast, only 10 percent
(21 openings) were for trading or trading-related (e.g. trading management)
positions. This sampling of openings is reflective of the industry’s collective
realization that successfully trading power and managing the associated
risk is a highly technical endeavor. Power trading staff who were in the
industry in 1996 and 1997 recognize the staff transformation that has
occurred. While personal industry relationships and a fat Rolodex are
still helpful tools, entire quantitative analysis groups are now common
on most power trading floors.

Figure 3
Volatility comparison between power, crude, and natural gas


Figure 3 illustrates the volatility time series for the Into Cinergy
spot power, WTI Cushing prompt month, and Henry Hub spot natural gas daily
prices during the summer of 1999. The enormous volatility in spot power
is evident: the realized volatility for power in August approached 1,600
percent, compared to 30 percent to 40 percent for crude and natural gas.
Interestingly, those hydrocarbon products are avoided by many commercial
money managers due to their “extreme” volatility, which is dramatically
dominated by that of power. The volatility inherent in power prices necessitates
serious analytical firepower on the trading floor. There are several other
major analytical problems:

Spot price estimation: Spot prices during non-spike pricing periods
(usually non-summer months) are dependent upon the marginal cost of generation.
At each generation unit, this depends upon the characteristics of the
particular plant (heat rate, or amount of fuel required to produce one
megawatt-hour of power) and fuel costs (for fuel oil, natural gas, coal,
hydro motion, or nuclear energy). Forecasting the prevailing spot price
in a particular region then depends upon determining which plants are
on the margin, which is a difficult information problem by itself. Assessing
which regional plants are on the margin depends upon accurately modeling
load (power demand), which requires precise weather forecasts. It is also
necessary to forecast the price of fuel used by plants in the generation
stack. Unexpected events such as unplanned power plant outages and transmission
curtailment also play a large role. Accurately estimating spot prices
is not a trivial problem.

Forward price estimation/forecasting: Forward price forecasting
is another challenging problem. Forward prices depend upon forward fuel
prices, perceived future capacity/demand imbalances, and climate forecasting.
The power market is inefficient enough that a few large marketers can
also move prices in their favor, at least temporarily.

Option pricing: The payoff of daily options depends primarily
upon short-term weather phenomena, which are largely unknown on a forward
basis. Estimating the payoff of daily options is analytically similar
to estimating spot prices and estimating the payoff of monthly options
is analytically similar to estimating forward prices. Estimating the pre-delivery
value of such options, for forward trading purposes, also depends upon
correctly modeling implied volatility.

Volumetric estimation: Many types of physical structured transactions
involve a varying volume of delivered power. Price-based instruments cannot
hedge volume risk, since volume risk depends upon consumption demand,
which is at present almost perfectly price-inelastic. Demand in power,
being weather-driven, can be hedged with weather-linked instruments. Newer
structures such as cumulative cooling-degree day (CDD) and cumulative
heating-degree day (HDD) swaps, and options on those swaps, are directly
applicable to volume-related hedging problems. The quantitative problems
associated with historical and future weather analysis, prerequisite to
transacting such weather-related instruments, warrant a small team of
analysts wholly dedicated to the task.

As the variety of structured transactions and derivative instruments
grows, the demand for quantitatively trained analysts and traders will
increase commensurately. Much like the personnel evolution seen on Wall
Street in the 1990s, it is increasingly common to find doctorates from
the math, science, and engineering disciplines on the power trading floor.


The power industry is undergoing rapid structural changes. The nonstorability,
fragmented transmission, and volatile supply and demand characteristics
of power combine to yield an exceptionally volatile commodity. The broad
range of successes and failures among industry participants, as well as
advantages of scale, are spurring rapid consolidation, a trend that will
likely continue until full competition across the domestic market. The
financial complexity of transacting instruments with price ranges spanning
two orders of magnitude is spawning a wide and growing variety of structured
transactions. Power shops are evolving into Wall Street-style trading
concerns, with professional risk analysts and managers in nearly every
operational function and personnel rosters heavy with quantitative expertise.
The power trading business – a concept that required extensive explanation
as recently as 1998 – is rapidly transforming from “emerging market” status
to a fully developed sector of the global commodities industry.


1 Power Marketer rankings and data provided courtesy of McGraw-Hill Energy’s
Power Markets Week.

2 Mark P. Mills in The Power Report, published by Gilder Technology,
February 2000.

3 As reported in Power Markets Week, August 9, 1999.

4 The Dynamics of US Deregulation, October 1998, Policy Assessment Corporation,
for the US Dept. of Energy.

5 All volatility referred to herein is annualized, percentage price change

6 Several electricity futures contracts have been introduced on NYMEX
and CBOT; only three are currently traded. NYMEX Palo Verde and COB futures
trade fairly liquidly. NYMEX PJM futures trade sporadically.