Environmental Engineering Reference
In-Depth Information
from selling 1 MW of electricity and buying
both the gas required for generating it and the
corresponding number of emission allowances
that ensure compliance. In an analogous manner,
the calculus for a coal-fired plant in Europe is
nowadays driven by the
clean-dark-spread
, i.e.
the net income from selling 1 MW of electricity
and buying both the coal required for generating
it and the corresponding number of emission al-
lowances.
4
Coal-fired and gas-fired plants reveal
differing efficiency levels. Hence, price levels
and volatilities in emissions markets became a
major driver of the fuel switching decisions in the
electricity sector.
5
Also, within each category of
fuel technology there are remarkable differences
in carbon efficiency. Hence, emissions markets
became a driver of the price levels and elasticity
of electricity supply.
spot and derivatives markets as well as across
markets.
8
This holds in spite of the very different
nature of the underlying commodities. Electricity
prices, for example, are very volatile due to the
unique physical attributes of electricity such as
non-storability, uncertain and inelastic demand
curves and very steep short-term supply curves
(Deng and Oren, 2006; Weron, 2000). Hence, no-
arbitrage models to price futures and forwards are
not applicable for electricity (Vehviläinen, 2002).
For circumventing this problem, equilibrium con-
siderations are applied and forward/futures prices
are typically split into two components: a forecast
on future spot prices and an expected electricity
risk premium; the latter being a compensation
for the risk of spikes frequently observed in spot
and day-ahead electricity prices and unexpected
demand and supply shocks (Bessembinder and
Lemmon, 2002; Longstaff and Wang, 2004). To the
other extreme, emission allowances are a perfect
underlying to apply no-arbitrage pricing models.
As storage of allowances is virtually costless and
allowances pay neither interest nor dividends, a
long futures position can easily be replicated by
buying allowances on credit. In theory, futures
prices for emission allowances should entirely
be derived from the cost-of-carry no-arbitrage
equation.
Prominence of Derivatives Trading
The restructuring of the European electricity sector
from a vertically integrated and tightly regulated
industry to a more open and competitive market
has created demands for derivatives at all levels
of the value chain to manage price risks.
6
While
prior to deregulation, the price of power was set
primarily by government agencies on the basis
of generation, transmission and distribution cost
considerations, now electricity prices and prices
in the interconnected underlying markets for coal,
gas, freight, oil, and emissions largely reflect eco-
nomic fundamentals and market forces at a local
and global level. A whole new set of stakehold-
ers, demands, risks and opportunities led to the
emergence of vividly traded derivatives markets
across the European energy markets.
In general, futures markets rather than spot
markets are the leading source of price discovery
in the European energy markets. This is consis-
tent with results known from many financial and
commodity markets.
7
There is also empirical
evidence of the efficient functioning of price
Institutional Design Challenges
In contrast to theory, there is indeed a latent carbon
risk premium comparable with and reinforcing
to the electricity risk premium accounted for in
pricing electricity futures. This risk premium
results from substantial uncertainties in emis-
sions markets with regard to politically contrived
supply and demand disruptions in the underlying
emissions allowances. This risk premium comes
at a social cost. Market efficiency suffers and the
cost of hedging and risk management increases
for electricity producers and consumers alike. The
uncertainty created by improper market design
