IEA-ELECTRADE.WPD

1
IEA Information Paper
Electricity Trade, the Kyoto Protocol
and Emissions Trading
Richard Baron, Jenny Hou1
International Energy Agency, Paris, France2
October 1998
Abstract
Two policy trends appear to contradict each other in the electricity sector. On
the one hand, increasing demand, improved economic efficiency and market
liberalisation have increased international trading of electricity for most developed
countries. This has served the purpose of an economically efficient and secure
electricity system. But it has also resulted in increased emissions for exporters of
fossil-based electricity. Since 1997, all industrialised countries, as Annex I Parties to
the United Nations Framework Convention on Climate Change, have taken individual
commitments under the Kyoto Protocol to limit their greenhouse gas emissions by
2008-2012.
The power sector is a major and growing source of CO2 emissions
internationally. Annex I exporters of electricity produced from fossil fuels would be
1
Richard Baron is administrator on climate change at the International Energy Agency, Energy
and Environment Division (richard.baron@iea.org); Jenny Hou is a consultant with
Hagler-Bailly Consulting Inc. (jennyhou@alumni.stanford.org). This paper expands on an
earlier study by Richard Baron and Jane Ellis (1998): “Trading emissions and electricity -
implications of the Kyoto Protocol”, Power Economics, April, Volume 2, Issue 3, pp 33-35. The
authors are indebted to Sandrine Duchesne for research assistance and to Scott
Sullivan and Jennifer Gell for edition.
2
This paper does not necessarily represent the view of the IEA Secretariat or that of any of its
Member countries.

2
disadvantaged under national emission caps whereas electricity importers have no
emission disadvantage from the trade. Will structural changes of the power sector, and
the increase in electricity trade that they may generate, be compatible with the newly
agreed targets for greenhouse gas emissions at domestic level?
The current paper studies this question. It explores the ways in which
participation of power producers in an international emission trading system may help
to reconcile increasing competition with the climate change obligations of the Kyoto
Protocol. Electricity trade is a ‘problem’ if it causes increased emissions in exporting
countries. But it could, in fact, become a solution to the increase in electricity-related
emissions. The economic efficiency brought about by international electricity trade, if
harnessed to an international emissions trading system, could contribute to
cost-effective emissions reductions. There are however minimum requirements for
setting such a system at the international level.
1 Introduction
Liberalisation and competition in the power sector have affected most world regions over the
past few years. In the European Union, the opening up of a minimum of 25% of electricity and gas
markets to competition will take place on 9 February 19993
. Canada, Mexico and the United States have
entered the North American Free Trade Agreement (NAFTA). Competition in the domestic
electricity-supply industry has developed rapidly in the United States, and it now extends to full retail
competition.
The introduction of competition in the power industry has been carried out without any explicit
recognition of the greenhouse gas-implications of such far-reaching structural change. For the past 30
years, electricity has contributed most of the increase in energy-related CO2 emissions in IEA countries.4
Its share in total OECD emissions grew from 33% to 35% between 1990 and 1995.5
Very few countries
can leave the power sector out of their GHG mitigation strategies, if they are to meet their Kyoto targets.
The picture is obviously not as clear-cut as it seems when seen from an aggregate viewpoint.
Some Annex I countries are considering an increase in the domestic production of fossil-fuel-based
electricity in order to satisfy a growing demand for electricity exports and to generate revenues6
. This
could, on the one hand, contribute to significant increases in domestic greenhouse gas emissions (GHG),
as in Norway. Such exports could put the exporting Party in a difficult situation to meet its Kyoto target.
On the other hand, it could also result in decreased regional or global emissions of greenhouse gases if,
for example, imported gas-fired electricity displaces domestic electricity generation from a more
carbon-intensive source.
Under the Kyoto Protocol, however, each country is accountable for its own domestic emissions,
regardless of the destination of the product which directly or indirectly causes them. The exporting
country has to report any emissions associated with its exported electricity as domestic emissions, and
3
For details, please see Council Directive 96/92/EC on common rules for the internal
electricity market, which came into effect on 19 February, 1997.
4
IEA Member countries are: Austria, Australia, Belgium, Canada, Denmark, Finland, France,
Germany, Greece, Hungary, Ireland, Italy, Japan, Luxembourg, the Netherlands, New Zealand,
Norway, Portugal, Spain, Sweden, Switzerland, Turkey, the United Kingdom and the United
States.
5
Source: CO2 Emissions from Fossil-Fuel Combustion (1997 edition), IEA, II.55.
6
The same question arises for Canada, whose natural gas production contributes to GHG
emissions, while its exports of gas enable other countries to substitute natural gas for more
carbon-intensive products.

Electricity Trade and Emissions Trading - IEA Information Paper - October 1998
3
will have to offset any increase in these emissions elsewhere.7
7
This applies to any other exported product and associated GHG emissions. Electricity is no
special case in that respect.
Electricity trade brings higher economic efficiency and improved security of supply. But can
international electricity trade go on increasing without impeding some countries’ strategies to limit their
greenhouse gas emissions? This paper examines how the environment and electricity trade interact with
each other, and considers how international emissions trading could contribute to reconcile them.
Section 2 describes the implications of individual GHG mitigation obligations, the current
electricity trade within different groups, and the potential impact of GHG reduction obligations on
inter-system competition and trade in the international electricity market.
Section 3 starts with a study of electricity trade flows among Denmark, Norway and Sweden,
pointing out recent situations where electricity trade greatly affected a country’s greenhouse-gas position.
The paper then highlights how the introduction of international GHG emission trading in the power
sector could turn electricity trade into a powerful tool for cost-effective achievement of environmental
goals, while contributing to energy security. Section 4 addresses implementation issues for international
emission trading in the power sector. Concluding remarks and further issues for discussion are provided
in Section 5.
2 GHG Mitigation Goals and International Trade in Electricity
2.1 The Kyoto Objectives
In 1992, the Rio Earth Summit established the United Nations Framework Convention on
Climate Change, whose ultimate objective is to prevent the dangerous accumulation of greenhouse gases
in the atmosphere. At Rio, industrialized countries agreed to undertake actions to stabilize their
emissions in the year 2000 at 1990 levels. Recognizing the inadequacy of such commitments, Parties to
the UNFCCC agreed in 1997 to the provision of the Kyoto Protocol. This agreement sets legally binding
emissions objectives for each of the industrialized nations listed in Annex B of the Kyoto Protocol. The
objectives, also called assigned amounts, were adopted for a basket of greenhouse gases (CO2, CH4, N2O,
PFCs, HFCs and SF6) for the period 2008 to 2012, expressed as percentages of actual 1990 emission
levels. The combined result of individual country targets should result in an overall reduction in Annex
B countries’ GHG emissions of 5.2%, and around 7% for IEA Member countries as a whole.

4
Figure 2.1 - IEA Countries’ Energy-Related CO2 Emissions (1971-1996)
1971 75 80 85 90 1996
0
2,000
4,000
6,000
8,000
10,000
12,000
Mt CO2
Electricity Transport Other emissions
- 7% from
1990 level
For most countries, reaching this goal will require reductions of GHG emissions from
business-as-usual emission trends (see Figure 2.1). Among all sectors, the energy sector (from
primary extraction to end use) has been the major source of CO2 emissions. So, the energy
sector can make a significant contribution to meeting the climate-change challenge. Fossil fuels
currently amount to 84% and 92% of commercial energy use8
, in IEA countries and in the rest
of the world, respectively. If effective action is not taken to deal with climate change, the IEA
World Energy Outlook projects a 45% growth in energy-related CO2 emissions in IEA
countries by the year 2010, from 1990 levels (World Energy Outlook, 1998 Edition). Once the
Kyoto Protocol enters into force, each of these Parties is accountable for the emissions of
greenhouse gases on their territory, including emissions from power generation that is traded
internationally.
The Kyoto Protocol introduces four mechanisms for international cooperation to
achieve the Party’s commitments in a cost-effective and flexible fashion:
- A “bubble” (article 4). Two or more Annex I Parties can group together to meet their
emissions’ objectives, through notification of their agreement to the Secretariat of the
UNFCCC. If they fail to meet their commitments jointly, Parties’ objectives set in the
agreement will provide the basis to assess which Party is not in compliance.
- Joint implementation (JI) among Annex I Parties (article 6) Emission reductions
achieved through individual projects in Annex I can be credited for their emission commitments,
if they can demonstrate that they reduce emissions beyond what would have otherwise occurred.
Companies (legal entities) are allowed to undertake such activities. The contribution of JI to
8
There are non-commercial, and commercial energy uses. Non-commercial use refers to
fuel-wood and other non-marketed fuels for heating and cooking. Marketed fossil fuels
and electricity account for the bulk of commercial energy use, the remainder being
made up of nuclear, biomass, hydropower and other renewable energy sources.

5
meeting a Party’s emission goal should be supplemental to domestic action.
- Clean development mechanism (article 12). The protocol defines a clean development
mechanism designed to help non-Annex I Parties towards sustainable development. Certified
emissions reductions achieved on the territory of non-Annex I Parties through individual
projects, beyond what would have otherwise occurred, can be counted by Annex I Parties in
their assigned amounts. Certified emission reductions achieved between 2000 and 2008 can be
credited for commitments under the first commitment period.
- Emissions trading (article 17). Parties listed in Annex B may participate in emissions
trading, which should be supplemental to domestic actions to achieve emission objectives. The
Conference of the Parties will define the relevant principles, modalities, rules and guidelines, in
particular for verification, reporting and accountability for emissions trading. Under both
emissions trading and joint implementation, Parties trade “parts of their assigned amounts”
(PAA), that is, emission reductions under their Kyoto targets.
These mechanisms can be used to offset some of the increased emissions from the
power sector, and we will return to this question in Section 3. The following two sections will
describe the trend towards increased electricity trade activities within IEA member countries
and describe the possible interactions between such trade and Kyoto targets.
2.2 International Electricity Trade
After three decades of steady growth, electricity trade to and from OECD countries reached
roughly 250 TWh in 1996, about 3% of the OECD’s total electricity output. Trade grew by more than
10% every year from 1960 to 1973, and by more than 5% annually over the past twenty years.9
Figure
2.2 displays the increasing trend towards electricity exchange among IEA member countries between
1960-1995.
Figure 2.2 - Trend of Electricity Trade in IEA Member Countries
9
See IEA Electricity Information 1996, IEA/OECD, Paris, July 1997.

6
1960 1970 1980 1990 1996
0
50
100
150
200
250
300
0.5
1
1.5
2
2.5
3
3.5
TWh %
Trade among
IEA countries
Trade with other countries
Share of total power generation
2.2.1 Existing International Electricity Connections
Electricity can only be traded amongst entities which are physically connected by transmission
links, and the boundaries of the various systems often cross national borders. In North America, there are
co-operative “pools”, interconnected areas in which utilities optimize power generation and trade power,
but not necessarily in competition with each other. These pools cover several US states and Canadian
provinces, as well as some parts of Northern Mexico. Completion and upgrading of existing
interconnections with Canada and Mexico are planned.
In Europe, there are four networks connecting different areas of the continent: UCPTE10
,
NORDEL, CENTREL and UPS/IPS. The Western part of the European mainland is connected
to the UCPTE system. The UK is connected to the UCPTE through France. In Northern Europe,
Denmark, Finland, Iceland, Norway and Sweden have formed a co-operative electricity market,
NORDEL since 196311
. Work towards the creation of a joint Nordic electricity exchange began
in August 1997. The Nordic electricity exchange, NordPool, is the first international electricity
exchange which allows for trading electricity on the day of dispatch as well as for longer-term
contracts.12
NORDEL is connected to the UCPTE via two sea cables from Norway to Denmark,
10
The Union for the Coordination of Production and Transmission of Electricity (UCPTE)
is the body responsible for the operation of the interconnected electricity network. The
role of the UCPTE involves the security of network operation within the broader context
of the development of competition. The UCPTE network includes 14 countries of
Western Europe: Austria, Belgium, Croatia, the Federal Republic of Yugoslavia, the
former Yugoslav Republic of Macedonia, France, Germany, Greece, Italy, Luxembourg,
the Netherlands, Portugal, Slovenia, Spain and Switzerland. Albania, Bulgaria,
Romania, and the Southern region of the former Yugoslavia have applied for UCPTE
membership. Turkey is interconnected to Romania and Bulgaria.
11
NORDEL is an association for electricity co-operation in the Nordic countries.
Established in 1963, NORDEL is an advisory and recommendatory body; its primary
task is to create optimum conditions for the efficient use of the Nordic electricity
generation and transmission systems (http://www.nordel.org/eng/index.html).
12
About the profiles and statistics of NordPool, see: http://www.nordpool.no

7
and two further cables from Sweden to Denmark. CENTREL links together the Czech and
Slovak Republics, Poland and Hungary, with the Unified Power Systems / Integrated Power
Systems joining other Central and Eastern European countries.
Some major power- supply systems, such as those of Australia, New Zealand and Japan,
operate in isolation and will therefore not be considered here, although some of the
implementation issues discussed later may be of interest for purely domestic emissions trading
systems as well.
In the past, despite rising electricity trade within IEA countries, electricity trade
between national power systems was rather limited, and exchanges of electricity occurred in an
environment of co-operation rather than competition. Over the past two decades, there has been
hardly any competitive trade between different national power systems in the IEA. Even
co-operative power trade has played a minor role, although it has grown faster than demand. In
Europe, less than 7% of the power supplied was imported from other European IEA countries,
and imports from non-member countries were below 1%. The US imports roughly 2% of its
power from Canada, and less than 0.1% from Mexico. Figure 2.3 shows electricity import and
export flows for countries of the UCPTE network.
Figure 2.3 - Physical Electricity Exchange of UCPTE in 1997
SI
BiH
S
N
CH
I
P
E
IRL
UK PL
D
NL
B
JIEL
BG
RO
SL
CZ
HA
F
HR
GR
AL
FYROM
DK
4077
413
815
1396
5284
2480
2068
2114
16644
13712
1572
1031
3213
MA
3174
360
17313
4
12
19948
200
650
398
537
82
1361
27
1452
26
748
136
759
92
456
6321
461
3653
8135
4210
673
16540
18
9320
966
805
35364225
848
61
5806
2091
417
5097
88
2608
324
46
1938
588
986
959
128

8
Only a few IEA countries are systematic traders. France and Canada are the largest net
exporters, although Norway and Switzerland also export power. Italy, the UK and the US are
net importers (Figure 2.4). Both France and Canada envisage increasing their exports slightly
up to the year 2000.
Figure 2.4 - Net Electricity Trade Among IEA Countries (1994-1996 average)
Austria
Belgium
CanadaDenm
ark
Finland
FranceG
erm
anyHungary
Italy
Luxem
bourg
Netherlands
NorwayPortugal
Spain
SwedenSwitzerland
United
Kingdom
United
States
-60
-40
-20
0
20
40
60
80
TWh

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2.2.2 Electricity Trade: Likely to Grow in the Future
In North America and Europe, elimination of transmission “bottlenecks” and interconnection
with neighbouring regions are under way or planned.13
Gaps in international electricity connections are
being closed between France and Spain; France and Italy; Italy and Austria; Italy and Greece; Spain and
Portugal, and inside Denmark. The UK is expected to be linked to Northern Ireland (250 MW) and to
Ireland via sea cables before 2010. NORDEL will be further interconnected with UCPTE and CENTREL
through a number of new links. The UCPTE network is currently connected to Central and Eastern
Europe, with further interconnection in progress. The East German trans-mission network was
synchronised with the rest of the UCPTE region in September 1995.
In future, the Baltic states, Belarus, Russia, and possibly Ukraine and Moldova, could be linked
with the extended UCPTE system. A “Baltic Ring”, connecting NORDEL, the Baltic states, Poland and
UCPTE via Germany is under discussion, and would not require extensive investment beyond the
interconnections outlined above. Finland is already directly linked to the Russian Federation, and a 1,800
km power line linking Germany and Russia via Poland and Belarus is under consideration with operations
to start between 2005 and 2010.
The infrastructure is clearly in place to enable increasing international electricity trade, through a network
that would allow for a more secure and efficient power supply. With market liberalisation expanding in
Europe and elsewhere, substantial increase in CO2 emissions is very likely to take place in the European
power transmission system and neighbouring regions over the next 10 to 15 years. This increase will
have to be taken into account in designing national strategies to meet the Kyoto objectives.
2.3 Kyoto Constraints: a Barrier to Electricity Trade?
2.3.1 The Role of the Power Sector in Greenhouse Gas Emissions
The mix of fuel inputs in electricity generation differs greatly by country. Figure 2.5 illustrates the
variation found in different Annex I countries in 1996. On average for the OECD, coal provided 37% of
the electricity; nuclear generated 24%; hydro 18%; and gas 13%, with oil and non-hydro renewable
supplying the remainder. However, individual countries’ dependence on different fuels varies markedly.
Norway currently generates 99% of its electricity from hydropower. Australia and France are dependent
on coal and nuclear respectively for over three-quarters of their electricity. The Netherlands generates
just over half its electricity from gas, and oil is the generating fuel of choice in Italy.
13
Across the West European UCPTE region, existing transmission capacities are generally
between 1,000 and 2,000 GW.
But the fuel mix for electricity generation can alter rapidly. Nuclear power expanded rapidly in France in
the 1980s. Coal has significantly extended its relative importance in Portugal and Ireland over the last
10 years. In the United Kingdom, natural gas generated over 17% of total electricity in 1995 compared to
under 2% in 1992. Given the importance of electricity generation in total man-made CO2 emissions,
relatively small changes in the use of fuels for electricity generation can have significant impact on a
nation’s CO2 emissions. Since energy-related CO2 accounts for the majority of OECD emissions of
greenhouse gases, changes in their fuel mix can therefore have a substantial effect on total emissions of
greenhouse gases, as has been the case in France and the UK over the past twenty years.
Although the average CO2-intensity of IEA countries’ electricity generation has decreased since 1990, it
is uncertain whether this trend will continue. Indeed, in countries such as Spain and Sweden, the

10
CO2-intensity of electricity generation has increased sharply and significantly since 1990. This trend
may be extended, particularly for countries now relying on nuclear power or hydropower to generate the
majority of electricity. The short-term expansion plans of several such countries include increasing
gas-generated power.
For most countries, power generation is a major source of total greenhouse gas emissions. For those
countries with significant non-carbon based power generation, the power sector could be a source of
additional emissions in the future, when these countries have exhausted their non-fossil potential.
Energy-efficiency measures are likely to accompany supply-side measures, as the full burden of reducing
emissions should not fall exclusively on either demand or on supply. With a few possible exceptions,
some form of effort will be required of power generators in IEA and other countries if Kyoto targets are
to be met between 2008 and 2012.

11
Figure 2.5 - Share of Fuels in Electricity Production for Annex I Countries, 1996
Ice Nor NZ Aut Can Lat Swi Por Tur Swe Fin RomSpa Lux Ita Rus Slo Fra USA Aus Jap Gre Ger Ukr Den Cze Ire Bul Nld UK Lit Bel Pol Kor Hun Bela
0
10
20
30
40
50
60
70
80
90
100
Percent
Coal Oil Gas Nuclear Hydro Others

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2.3.2 Market Liberalisation, the Kyoto Protocol and Electricity Trade
Analysing the overall effect of increased competition in the power sector, and how competition will interact
with the new greenhouse gas constraint, is a complex affair. Individual Member countries will have to
balance their GHG mitigation targets with the requirements of electricity trade. The attitude of various
countries towards flexible mechanisms to achieve such reductions is still not always clear. The following
factors will have to be weighed by each country:
• the level of its GHG emissions target compared to its business as usual emission projections;
• the fuel structure of its power generation industry, and whether this is likely to change substantially
before or during the first commitment period;
• the economic effect of electricity trade on the cost of GHG emissions reduction;
• the scope, accessibility and reliability of flexible mechanisms;
• the possible penalty or penalties attached to emission levels that exceed the binding target at
domestic level.
While it is not possible to predict the types of measures that will be taken in different countries, it is
worthwhile to ask whether a constraint on GHG emissions could hinder the current trend toward increasing
trade in electricity across countries, and whether it is indeed desirable from both efficiency and environmental
standpoints to hinder such trade.
Regulatory changes in the electricity market, and the prospect of GHG emission constraint, can
affect the sector in three ways. Firstly, the Kyoto Protocol could significantly affect the flow of investments
to the electricity sector, as planning for new generation plant and processes will need to take GHG emissions
into account. Secondly, continued growth in electricity demand in a more competitive environment offers the
opportunity to introduce plants generating electricity with a lower CO2-intensity, through co-generation,
renewable energy, etc. In some cases, plants currently operating with a high carbon-intensity would have to
be closed before the end of their planned lifetime, entailing considerable “stranded” costs. Cost-effective
GHG regulation will be required at the same time as there is increasing demand on liberalizing the electricity
market. Thirdly, governments can use the legislation introduced to restructure their domestic electricity
industry to recommend or require certain actions that may affect either the overall CO2-intensity of
electricity generation, or electricity trading provisions.14
It is yet to be determined how the new GHG limitation targets will affect the trading
activity of power industries in IEA member countries. Two scenarios can be envisioned:
14
For example, a number of IEA countries have incorporated measures encouraging the increased use
of renewable electricity in their restructuring provisions or guidelines. See Renewable energy policy
in IEA countries, Volume II: country reports (IEA, 1998)

13
• Foreign producers rely on existing international connections to market their power in other
countries; local retailers can also market foreign producers’ power. This scenario results in
more electricity trade than would have happened otherwise;
• Foreign generators install new production capacity in other countries in order to capture
local markets. This means less international trade than under the previous scenario, but
more than would have developed under the past regulatory regimes.
How would such trade interact with greenhouse gas constraints applied to individual
countries? In the first scenario, emissions are produced in the exporting country and not where the
power is being consumed. So the country of the exporter is responsible for controlling these
emissions. In the second scenario, competition drives more power generation in the consuming
country, and more emissions which would be subject to local regulation. In what follows, we
consider the situation of sustained electricity trade, which is probable, given the current policy
developments in the electricity markets.
2.3.3 Electricity Trade Could Help Meet Kyoto Targets
Increased trade does not necessarily mean increased emissions at regional or global level. Indeed, if
imported electricity replaces more carbon-intensive forms of power generation, the traders taken as a group,
are better off from an environmental standpoint than they would have been were such trading not possible.
Increased electricity trade can help to reduce GHG emissions from the electricity sector by optimizing the
performance of electricity-generating capacity at a regional level. For example, thermal stations running at
full capacity are more efficient than those running at half capacity. Where two neighbouring countries are
each running their own thermal power station inefficiently, enhanced trade could enable one country to
generate electricity at a higher efficiency (with lower associated fuel use and emissions) and export its surplus.
On a larger scale, since different countries experience peak loads at different times, the load curve for a group
of countries is likely to be flatter than that for a single country. Meeting electricity demand for a flatter load
curve would reduce the need to run many peaking plants which are usually inefficient. It may also help to
increase the potential for the electricity system to handle power from intermittent renewable sources, although
the current level of these sources is too low in most countries to pose any problem. Trade can also be used to
export power from stations without much capability to follow the electricity load, such as nuclear power
stations.15
Yet, domestic policies may hinder increased trade in low-carbon-intensive electricity if
such trade is not in line with domestic emissions objective, whereas it may be beneficial for the
group of trading countries considered as a whole. A producing country might gain economically
from increasing production for export purposes, but might refuse to do so if such activity goes
against its environmental objectives. In the first case, limiting trade could be detrimental to the
regional environmental objective; in the second case, it would endanger security of supply.
15
As in the case of France, where exports of electricity amounted to 15% of total production
in 1995.

14
The next section illustrates the environmental stakes of the international electricity trade. Starting
with some of its problematic aspects, it then argues that international emissions trading can bring
cost-effective greenhouse gas reductions without restricting electricity trade, so that security of
supply as well as ecological benefit are ensured.
3 Scenarios for Electricity Trade and International Emission Trading
This section starts with an illustration of the problem: Denmark, whose production of electricity is largely
coal-based, has increased its emissions due to increased exports to its trade partners. How can a country like
Denmark handle such situation in the future, under the Kyoto constraint, without impeding electricity trade?
Interestingly, Denmark just announced that its fossil-fuel power stations have been allocated CO2 quotas that
they will be able to trade among themselves and bank from one year to the next.
Secondly, we draw on modelling analysis to show how in fact electricity trade can add flexibility to
international emissions trading and indeed contribute to cost-effective reductions among electricity trading
partners. From a potential problem, electricity trading can become part of the solution to the Kyoto
greenhouse gas constraint.
3.1 How Electricity Trade Affects Domestic Emissions:
Case Study of Denmark, Norway and Sweden.
Denmark, Norway and Sweden are the first three countries to have entered an international electricity
exchange. Their recent experience illustrates some of the main issues described above.
3.1.1 The Different National Power Mixes of Denmark, Norway and Sweden
The Norwegian power system is almost entirely based on hydropower and supports per capita consumption
of electricity of 25,000 KWh/year. For Sweden, nuclear power supplies just over half of all electricity.
Remaining electricity demand is mainly covered by hydropower. Per capita consumption of electricity in
Sweden is 17,000 KWh/year. Denmark produces most of its power in coal-fired power plants, with a large
share of combined heat and power and a non-negligible contribution from wind power. Per capita Danish
consumption of electricity is much lower than in Norway and Sweden – 6,700 KWh/year16
.
16
Source: Larsson, Grohmheit, and Unander, Common Action and Electricity Trade in
Northern Europe, Journal of International Transactions in Operations Research,

15
Varying efficiencies of generation, but still more the different fuel mixes used in electricity
generation in these three countries, translate into widely different CO2-intensities as shown in Figure 3.1.
forthcoming.
Figure 3.1 - CO2 Intensities of Electric Power in Denmark, Germany,
Norway and Sweden
0
200
400
600
800
1000
1200
1971 1975 1979 1983 1987 1991 1995
gCO2/kWh
DENMARK
GERMANY
NORWAY
SWEDEN
It so happens that much electricity trade currently occurs between countries with extremely diverse
CO2-intensities. For example, there is significant trade among Denmark, Sweden, and Norway. On an annual
basis, electricity trade is a two-way flow. However, the actual amount of electricity traded, and how much
between which countries, varies enormously from year to year. This is depicted in figure 3.2 and 3.3, where
CO2 emissions corresponding to the traded electricity are also shown.

16
Figure 3.2 - Denmark Electricity Trade and Associated Domestic CO2 Emissions (1995)
-3
-2
-1
0
1
2
3
4
MtCO2andTWh
Electricity
CO2ExportsfromDenmark
ImportsintoDenmark
Germany Norway Sweden
Figure 3.3
Trends in Denmark’s Net Electricity Trade and CO2 Emissions from Electricity
-8
-6
-4
-2
0
2
4
6
1990 1991 1992 1993 1994 1995
MtCO2andTWh
Electricity
CO2
Net exports from Denmark
Net imports into Denmark
Since the electricity systems of Norway and Sweden are heavily dependent on
contributions of hydro or nuclear, variations in the rainfall patterns cause significant
swings in generation capability and, therefore, yearly shifts in trade patterns. In 1996, a
lack of rainfall reduced the possible outputs from nuclear plants (because of cooling-water
discharge requirements) as well as from hydro stations. Provisional figures indicate that

17
Denmark exported almost four times as much electricity in 1996 as in 1995 to make up for
the low level of supply in its Scandinavian neighbours.
This, of course, has huge implications for Denmark’s CO2 emissions, implications
which are acknowledged in the country’s National Communications to the UNFCCC,
where the estimates of GHG emissions presented include adjustments for the extra
emissions from electricity for export as well as for climatic variations. Actual emissions
from electricity production in the base year, 1990, were relatively low, as Denmark then
imported significant quantities of electricity from Norway and Sweden. Denmark’s second
National Communication17
estimates that actual emissions of CO2 from the whole energy
sector in 1990 would have increased by almost 12% from the observed level if it had sold
more coal-based electricity as it does on typical years.
For energy-security and commercial reasons, certain countries may export large
amounts of energy to other countries through the existing connections. In the case of
Denmark, this has resulted in a significant increase in its GHG emissions. Such trade,
because of its related emissions, would pose serious problems for Denmark during the
commitment period of the Kyoto Protocol. The situation may not be as dramatic in other
countries which also sell electricity to other countries, yet the Danish case illustrates the
need to consider the power sector beyond national boundaries, despite the fact that
commitments under the Kyoto Protocol are national.
3.2 International Solutions
The GHG emissions associated with the electricity trade within Denmark, Norway and Sweden
resemble those of many other emission sources engaged in international trade. For the purpose of this paper,
the emissions of greatest concern are those stemming from the fluctuations of electricity generation associated
with international trade. The reason for concentrating on those emissions is that the power sector is likely to
seek to reduce its emissions. Another reason is that electricity trade plays a key role in improving economic
efficiency and ensuring security of supply.
The five-year commitment period adopted in the Kyoto Protocol will smooth out some of the
variations in national energy use, and therefore in emissions resulting from swings in economic growth or
climate. Had a single target year been chosen, some Parties would find themselves in non-compliance even
if they had made significant progress in reducing their emissions. Any significant variation from projected
economic growth could cause this paradox, as could a period of “atypical” weather. But even a five-year
target period may not be long enough to smooth out variations caused by the economic cycle or the weather.
3.2.1 Flexibility in the Kyoto Protocol: Emissions Trading and the Power Sector
17
Denmark’s Second National Communication on Climate Change, Ministry of Environment
and Energy, Denmark, 1997.
Because of the diversity of fuel sources and technologies used in power generation, the marginal cost
of reducing the CO2-intensity of electricity production should vary greatly across utilities, regions and

18
countries. Other factors leading to variations include the residual economic life of installed capacity, the
technologies available in different regions, and the ways in which reduction efforts are allocated, implicitly
or explicitly, within countries. Wherever there are differences in marginal cost of controlling pollution, there
is scope for improved economic efficiency through a system of tradeable pollution permit. Such a system, if
widely used by covered emission sources could allow those with high marginal cost to purchase emission
reductions from other sources with lower cost, for the benefit of both parties.
Other than through domestic action, there are a number of mechanisms under the Kyoto Protocol on
which Parties could rely singly or in combination to correct an increase in emissions resulting from the
international electricity trade.
Bubble agreement: A Party may decide to solve the potential problem of increased emissions on a
nation-wide basis, by entering a ‘bubble’ agreement with other Parties, without specific treatment of its
electricity sector. A ‘bubble’ would cover all Parties’ greenhouse gas emissions, including those from
electricity. But such an agreement must be concluded and notified to the UNFCCC before the beginning of
the commitment period in 2008. Hence, it could not accommodate unexpected changes in electricity trade
when they happen.
Government-level emissions trading: The Party acquires emission reductions (here “parts of
assigned amounts” or PAA) from an international greenhouse gas emission market to offset an increase in its
own emissions.
Project-based activities under joint implementation and the clean development mechanism: A Party,
together with its electricity generators, may undertake projects in other countries to offset possible increases
in its own emissions (Articles 6 and 12 of the Kyoto Protocol).18
However, such projects have a certain
lead-time and would not necessarily be designed to respond to an urgent demand for PAA;
Governments could also allocate PAA to power generators and authorise them to participate in
international emissions trading. Participation of power producers in international emission trading would:
• reveal the marginal cost of greenhouse gas abatement for power generators, by allowing agents with
direct knowledge of such costs to participate in the market;19
18
This is a solution envisioned by Naturkraft, the Norwegian company who aims to produce
power from natural gas in Norway. Its parts of assigned amounts would come from projects
implemented in Poland and Russia (Norway Post, 17 September 1998).
19
Emission trading at government level risks lowering the economic efficiency of emission
trading as governments would not necessarily have accurate information on the marginal
cost of reduction for their countries. See Mullins and Baron (1997): International GHG
Emission Trading, Working Paper 9, Annex I Expert Group on the UNFCCC. OECD/IEA,

19
• input greenhouse gas emission constraint into planning decisions as early as possible through price
signals and the creation of an asset in the form of tradeable PAA.
• not preclude the implementation of additional GHG mitigation projects and other domestic policies
and measures acting to reduce emissions from the power sector;
Paris.
• reduce the need for government intervention, while assuring that the sector achieves the agreed goal,
provided that appropriate allocation, monitoring, compliance and enforcement measures are taken
domestically.
3.2.2 Illustration of an International Emission Trade between Two Utilities
What could be a standard transaction in an international GHG emission trading system, between two
utilities based in different countries? Let us assume that Utility 1 in Country 1 buys electricity from the
gas-fired power plants of Utility 2 in Country 2. The Country 2 government has given Utility 2 an emission
objective which it must fulfil under domestic law. The export of electricity to Utility 1 increases the revenue
of Utility 2. But it also pushes the company’s CO2 emissions above its assigned objective. Utility 2 needs to
offset this increase through the purchase of PAA from the market:
• Utility 2 can price its electricity to reflect the cost of acquiring the needed PAA. Utility 1 then need
not worry about supplying PAA to Utility 2. It simply pays Utility 2's cost of compliance through the
cost of the corresponding PAA. This is how most of trades of SO2 allowances are conducted in the
United States.

20
• Utility 1 may have been allocated some parts of assigned amount by its government, and decide to
trade them with Utility 2 when it buys its electricity.20
The form of the transaction would depend on how the two countries have chosen to implement their
Kyoto targets domestically. In both examples the utilities must be authorised to engage in international
emission trading (or in projects that generate emission reductions) to meet their objectives. Parts of the
assigned amounts must be devolved by the government at least to the exporting utility.
At the moment, the only full-scale example of emissions trading is the domestic SO2 allowance
trading program in the United States, the results of which are broadly positive so far. It relies on fixed limits
on plants emissions, and includes strong penalties for non-compliance. Few, if any, countries have designed
policies to handle emissions from the power sector that explicitly addresses emissions caused by increasing
trade of electricity. In the next section, we cover the results of model-based work that highlight the potential
economic gains from a system which allows continued electricity trade and emissions trading under a
greenhouse gas constraint.
3.3 Electricity Trade and International Emissions Trading: an Illustration
Larsson (1998) conducted some quantitative analysis on the potential benefits from electricity trade
under CO2 constraints in Northern Europe (Denmark, Norway, Finland and Sweden)21
. This section
combines the findings from this work together with the various trade options in individual countries
under the Kyoto constraints.
20
Again, the government may decide to offset the increase in emissions for the nation as a
whole and leave utilities out of it, but here we assume that utilities would be part and parcel
of the national strategy.
21
Tomas Larsson, 1998, Benefits from Electricity Trade in Northern Europe under CO2
Constraints, working paper, Energy System Technology, Chalmers University of
Technology, Goteborg, Sweden.
As mentioned earlier, the electricity systems of IEA countries differ significantly,
depending on their local fuel resources, geography and technology. These structural differences
make electricity trade across national borders very attractive as the electricity systems can be quite
complementary. The future of electricity trade could be four-fold:

21
• Limited electricity trade, albeit large scale in regional terms, as trade among the existing
systems22
is still at the experimental stage. The system would not evolve into a fully
integrated market by 2008-2012. The market would not be fully competitive.
• Unlimited electricity trade, using the infrastructure of the different regional electricity
networks. In this scenario, it is expected that electricity (and gas) markets would be fully
competitive within 10 years.
• Limited, mostly bilateral electricity trade, based on non-competitive agreements.
• Unlimited bilateral trade. Markets would be open and competitive, but electricity trade
would remain largely bilateral.
On top of these four possible scenarios, comes the environmental dimension. Countries
could choose to conduct their greenhouse reductions domestically, or to participate in international
emissions trading.
3.3.1 Description of Scenarios
There is no quantitative analysis combining the above scenarios for all IEA countries. Larsson et al.
(1998) have carried out modelling analyses comparing four major scenarios for three Nordic countries, with
the aim of reaching a greenhouse gas emission reduction objective of 20% below 1990 levels. The countries
are Denmark, Norway and Sweden and the period studied is 1990-2020. The scenarios are as follows:
• Limited electricity trade, with emissions trading to reduce GHG emissions by 20%;
• Limited electricity trade, with country-by-country reductions of 20%;
• Unlimited electricity trade, with emissions trading to reduce emissions by 20%;
• Unlimited electricity trade, with country-by-country reductions of 20%.
These scenarios are compared to a baseline which assumes limited electricity trade, without any
emission constraint.
22
NORDEL, UCPTE, CENTREL and within NAFTA.
The study covers the stationary energy systems of Denmark, Norway and Sweden. As mentioned in
Section 3.1, these three countries are similar in wealth but different in their energy systems. Since 1963, all
five Nordic Countries have co-operated through NORDEL. Initially, the main incentive for power exchange
was to use the excess power available in Norway and Sweden during the spring floods and to balance power
supply between dry and wet years. In 1993, the electricity exchanged among Denmark, Finland, Norway and
Sweden amounting to 18 TWh, or 5% of total generation. Trade between countries is usually two-way,
although Denmark has recently become a net exporter. Only a limited part of the trade was based on long

22
term contracts. Short-term trading was based on bilateral agreements with prices calculated on the basis of
short-run marginal costs. This picture is about to change as the electricity markets in both Norway and
Sweden have been deregulated, and the Danish market is likely to follow soon. Here the markets are assumed
to be fully integrated with no institutional barriers caused by legislation or market imperfection.
3.3.2 Methodology
The energy system is represented as a reference energy system (RES). This system describes the
energy flows from extraction of energy via centralised conversion, transmission and distribution to final
conversion to useful energy. The existing energy system is described together with alternative technologies
and energy flow paths. By describing the energy systems as an RES one can study competition and synergies
between different parts of the energy system such as the competition between energy supply, conservation
goals, and combined heat and power. This study has applied the dynamic linear IEA-MARKAL model to
describe the RES.23
Energy demand in this study is distinguished by country, sector, load characteristics, and
available final conversion technologies. The load curve is aggregated into six periods (three
seasons and day/night) with an additional peak capacity included as a safety margin. Energy
conservation technologies are indicated as optional technologies for Norway and Sweden; the
assessment of the energy conservation potential for Denmark is based on external analyses24
. For
each demand sector, a set of final energy conversion technologies is described with their costs,
technical and environmental performance, residual installed capacity, limits on output, etc.
Sweden’s existing nuclear power plants have been assumed to have a total technical life of
40 years, with major refurbishment scheduled after 25 years. It is assumed that 60% of the capacity
in domestic transmission systems is used for long-term trade in energy, while the remaining 40% is
reserved for momentary load-balancing purposes. The electricity exchange between the countries
is balanced for each season and between day and night. The investment cost for new international
power lines is taken into account, with different costs reflecting different international links.
23
See IEA (1998): Mapping the energy future, IEA/OECD Paris, for an overview of the features of
MARKAL and other models used for climate-related energy analysis.
24
Morthorst, P.E., 1994, Constructing CO2 Reduction Cost Curves, Energy Policy, Vol.22,
No.11, pp.964-970.

23
Under common action, the emission target can be met by domestic reduction and/or
through purchase of emission permits (PAA) from one of the other two countries, which must in
turn decrease their emissions so that the overall objective is still met.
3.3.3 Results and Discussion
The following insights can be drawn from this scenario analysis for Denmark, Norway and Sweden:
• The most advantageous scenario in terms of total electricity system cost is common action
with unlimited trade. It is most costly to try to achieve reductions country by country in a
context of limited electricity trade. The ability to trade electricity, with all transmission
costs accounted for, and to trade PAA assures an efficient outcome in terms of cost to the
power sector;
• For a 20% reduction objective by 2020, the marginal cost of GHG emission reductions is
US$ 200 per ton of carbon in the case of common action with unlimited electricity trade. It
is US$ 240 dollars per ton with limited trade. In the absence of electricity trade, the price
would rise to US$ 260 per ton of carbon;
• Without common action (the ability to trade emissions internationally), Norway would not
be able to meet the 20% reduction objective by 202025
;
• The direction and magnitude of electricity and emission trading vary significantly across
scenarios. Norway is a net exporter of electricity and a net importer of emission rights in
all cases. Exports of electricity rise as high as 30 TWh under unlimited trade and common
action (emissions trading), and emissions are reduced by 40%. In most cases, the export
figure is around 15 TWh;
• Denmark is a supplier of PAA for all levels of CO2 reductions. However, its supply of
PAA declines when the emission constraint becomes more stringent;
• For Sweden, the picture is more mixed. With moderate emission constraints, Sweden is a
net importer of electricity, but becomes a net exporter in the more stringent CO2 scenarios.
The same applies to emission permits: Sweden moves from being an importer in the less
constrained cases to becoming an exporter of emission permits in the more constrained
cases. These changes are mainly due to the increased cost-effectiveness of nuclear power
under highly constrained conditions.
• The value of traded electricity is in all cases higher than the value of traded emission rights.
Norway, therefore, always has a positive trade balance. Limited electricity trade and
common action lead to reduced differences in trade balance for the three countries. The
main explanation for this is that Norway buys emission permits from, while exporting
electricity to, Denmark.
25
This is partly reflected in the 1% growth in emissions objective negotiated by Norway at Kyoto.

24
In brief, electricity trade provides flexibility which will allow the power sector to
contribute significantly to meeting overall GHG constraint; but this is only made possible under a
system of international emission trading. The study supports the idea that unlimited electricity
trade combined with international CO2 emission trading is the most efficient strategy to achieve
GHG commitments in an international setting (note that these results take into account the
difference in revenues caused by changes in the pattern of electricity trade).
The results of this study should be considered preliminary for the following reasons. The
equal-percentage reduction among these three countries does not correspond to the actual
provisions of the Kyoto agreement. Also, national objectives are met at common marginal cost
across sectors, which is desirable but unlikely to become the case without the implementation of a
uniform carbon tax or a tradeable-permit system applied to all emission sources. The modelling
approach does not include the effect on energy demand from the increased cost of energy supply.
In some cases, the marginal cost for CO2 reduction becomes very high, especially for Norway when
international emissions trading is not allowed. Adaptation through changes in final energy demand
are likely to occur in those cases. The present model does not explore that question.
Setting up an emissions trading system in addition to the existing electricity trade regime
would not be a simple task. First, in order to reap the benefits of emissions trading in electricity
trade, the system has to be international in scope. But governments may not readily surrender their
sovereignty over the amounts of emissions assigned to them in the Kyoto Protocol, if they fear that
international emissions trading may interfere with other policy goals.
Second, the cost implications for electricity exporters and importers are likely to change
the conditions of electricity trade across countries, as shown by Larsson et al. These changes are
difficult to foresee at the moment, since governments have yet to allocate the GHG abatement effort
among different activities. It is not clear whether current electricity trade agreements between
utilities in different countries allow for passing through to the importer of any additional cost
related to a constraint on CO2. Sound economics would, of course, favour this argument. These
questions are not explored further in this paper, but they do point to the role of existing electricity
exchange agreements in the implementation of an international system of emission trading among
generators.
The following section discusses and summarises some of the implementation issues that would
arise if the electricity generators of various countries were to be integrated into an international
GHG emission trading system.
4 Implementation Issues for International Emission Trading in the Power Sector
The previous sections considered conflicting trends in electricity trade and in domestic efforts to
meet the GHG constraints in the Kyoto Protocol. We have also examined the economic and environmental
benefits that could be drawn from electricity trade, if an international emissions trading system were
introduced to constrain emissions. The infrastructure for increased electricity trade is in place to deliver a
more efficient power system among neighbouring countries.
The implementation of international GHG emissions trading has been considered in other papers26
.
26
See Mullins F. (1998): “International emissions trading under the Kyoto Protocol”, OECD

25
In what follows, we focus on specific design questions related to the power sector in an international setting27
.
Our approach focusses on minimum requirements, and touches on some peripheral issues. Minimum
requirements need not be sophisticated. For instance, there would be no need to monitor or record the carbon
content of electricity being traded internationally. Monitoring could in fact be left to domestic regulators. In
an ideal emission-trading regime, power producers would combine both the cost of their electricity and the
cost of PAA to cover their emissions in the price they charged to consumers.
4.1 Requirements for International Emission Trading by the Power Sector
Some of the matters discussed here will depend on the future status of emissions trading under the
UNFCCC, especially the principles, modalities, rules and guidelines to be adopted by the Conference of the
Parties. Decisions on participation by legal entities, the rules for liability in the case of non-compliance, and
possible international enforcement mechanisms will be of particular importance, but they cannot be assessed
in full here.
The minimum requirements for power sector participation in an international GHG emission
trading system include the following:
• allocation to generators of parts of a country’s assigned amounts;
• definition of a common unit of trade;
• authorisation to trade; and
Information Paper, Paris. For an earlier discussion, Mullins F., Baron R. (1997): “International GHG
emission trading”, Working Paper 9, Annex I Expert Group on the UNFCCC. See also:
CCE/CCA/CEC: “Analysis of the Potential for a Greenhouse Gas Trading System for North
America”, Montreal Canada; Ellerman D. et alii (1997): “Emissions trading under the U.S. acid rain
program - Evaluation of compliance costs and allowance market performance”, Massachusetts
Institute of Technology, Center for Energy and Environmental Policy Research, Cambridge, MA;
and Mullins F. (1997): “Lessons from existing trading systems for international GHG emission
trading.” Annex I Expert Group on the UNFCCC, OECD, Paris.
27
Useful ideas for this part can be found in EPA-NSW (1998): “Tradeable credits scheme for
greenhouse gases - New South Wales electricity sector”, Environment Protection Agency of New
South Wales, Chatswood, Australia.

26
• monitoring and enforcement of caps.28
4.1.1 Allocation, New Entrants
28
For a broader discussion of minimum requirements see: OECD/IEA (1997): Questions and
answers on emission trading among Annex I Parties, Information Paper, December 1997,
Organisation for Economic Co-operation and Development, International Energy Agency,
Paris.

27
Relatively little work has been done so far on the initial allocation of permits to emitters of
greenhouse gases.29
Where emission standards or caps are already in place, they provide a possible
basis for allocation, as the Emission Reduction Credit system in California. So far, such standards
have not been introduced for greenhouse gas emissions, so governments would first need to decide
on the amount of effort they should ask from different sources of emissions (power, industry,
transport, residential) in view of their available policy options and technologies. This may imply a
source-by-source emission constraint in some cases, a lengthy political process as was shown in the
case of the US SO2 allowances program, but a critical step to building the support from potential
participants in an emission trading system.
Equity over time, market power as well as the allocation mode will require careful
consideration. The parts of assigned amounts could be allocated for free to sources, i.e.
grandfathered, or sold at auctions. We can draw some insights from the US SO2 allowances
program:
• Simple allocation rules can be found for a sector like the power sector, but setting those
rules requires information on past emission levels which may not be readily available.
Surrogate indicators like total power sales or customer numbers (see EPA-NSW, 1998)
could be used.
• Grandfathering poses fewer problems than auctioning, as the latter is equivalent to a tax
imposed on emitters, and market power may be more easily exercised with an auction
mechanism than with a grandfathering system. However, auctions of a limited amount can
help launch the market, and also help reveal the market price of emission rights.
• Even for a relatively homogenous sector and a limited set of available technologies, some
adjustments will not doubt be required to accommodate political concerns at local levels,
but not necessarily at the expense of the overall environment objective.
• Allocating emission caps to agents who are closer to detailed decisions on abatement
measures assures that trading will be based on cost considerations, and that the market
price will reflect the marginal cost of abatement among participants at any point in time.
Power generators would hence be probable candidates for such allocation.30
Participation of new producers in the emission trading system is an important element in
the elaboration of allocation rules, especially in a liberalized and open power market. Once an
overall cap on the sector has been agreed, and allocated to existing sources, new entrants should
logically acquire their emission permits from other sources. This is sometimes viewed as unfair, as
29
See Haites (1997): “Intertemporal Allocation of Allowances in Emissions Trading Systems”,
Draft paper
30
The Environment Protection Agency of New South Wales discusses another option, with an
allocation done at the level of power retailers. This seems at first a more complicated scheme as it
requires the careful calculation of the carbon content of power sales. See EPA-NSW (1998) for a
complete discussion.

28
other sources were granted emission permits for free. In an auction system where all sources
acquire the emission permits on an annual or pluri-annual basis, it would seem that all participants
are treated equally. The issue is not that clear cut, however:
• A producer with grandfathered emissions who wishes to expand his carbon-based power
production also needs to buy emission permits from the market;
• A new entrant has full knowledge of the new constraint and can choose the best available
technology to minimise its emissions; pre-existing generators had to adjust their existing
capital stock to a target for which it was not designed, obviously at a certain cost. They
were therefore disadvantaged by an auction system.
• The grandfathering element of the allocation could be decreased over time, to slowly
evolve into a full auction system, while offering a transition period for producers who were
operating before the emissions constraint was introduced.31
Ideally, the domestic allocation mode should not introduce undue entry barriers, while
assuring that all new participants share the burden carried by pre-existing generators.
Would allocation rules need to be identical for all participants in an international system,
or should they remain at the discretion of governments? Grandfathering is often presented as the
preferred option since it is seen as imposing less cost on emission sources. Some argue that if
grandfathering is chosen in country A, it should be adopted everywhere else. But the opposition
between grandfathering and auction systems is misleading. Indeed, the auctioning of a generous
quantity of parts of assigned amount in country A may give a competitive advantage to country A’s
generators against those in country B where PAA were grandfathered, but reduction efforts are
much more stringent.
4.1.2 Defining a Common Unit
Article 3 of the Kyoto Protocol defines Parties’ emission reduction objectives for a basket of
greenhouse gases, expressed in CO2 equivalents based on the global warming potential of each gas.
This clause of the Protocol sets the common unit for international GHG emission trading as parts of
assigned amounts expressed in tons of CO2 equivalent.32
To allow the power sector to trade off
emission ‘rights’ with other sectors and Parties, the emission limit and the corresponding reductions
have to be measured in tons of CO2 equivalent. Adopting a different unit would create an artificial
barrier to emissions trading with other sectors, with a clear loss of economic efficiency.
Certain voluntary agreements define goals in energy efficiency terms, or energy
consumption per unit of output. Some trade associations have suggested this as the basis for
trading. Defining emissions on the basis of carbon content per kilowatt-hour would not be useful in
international emissions trading under the Kyoto Protocol. Emissions should first be translated by the
31
Association of Electricity Producers, UK (1998): Greenhouse gas emissions trading -- Issues to
consider in setting up a trading system. April.
32
See Mullins F. (1998).

29
Party (government) of the seller into PAA measured in tons of CO2 equivalent. Such process would
add unnecessary transaction cost as the government would need to determine for each trade
whether the quantity intended for sale is consistent with its domestic emission target. If the
government allocates PAA, as opposed to CO2 per kilowatt-hour, it will evaluate the effort required
from the power sector once, and for the full duration of the commitment period.
4.1.3 Participation: Emitters and Non-Emitters?
The right to trade parts of their assigned amounts can only be devolved to power generators by
governments. As the only Parties to the UNFCCC, governments are responsible for meeting their assigned
amounts under the Kyoto Protocol. Article 17, on emissions trading, does not mention participation by legal
entities. (Article 6 on project-based joint implementation among Annex I Parties does explicitly allow
authorised legal entities, including private companies, to engage in projects leading to transfers of PAA).
Participation by private entities in international emission trading would improve market efficiency, reduce the
abuse of market power and broaden the range of sources participating in trading. The result would be lower
abatement cost for all.
Some allocation of an emission cap seems, at first glance, a prerequisite for participation in
international GHG emission trading. Some entities which do not emit greenhouse gases may nonetheless
wish to participate. In most cases, however, power generators engaged in emissions trading are likely to
acquire PAA when needed, and to include the cost of the additional emissions permit on the electricity price
they charge to importers. However, it may be useful to allow non-emitting power producers to acquire PAA,
especially if their plans for future generation are based on fossil fuels. One could also envision that producers
subject to a carbon tax could deduct PAA acquired on the market from their tax basis.
4.1.4 Monitoring Emissions and Assuring Compliance
a) Monitoring
Devolving PAA to power generators and other emission sources would require proper monitoring of
emissions from these sources, as sources would only be able to trade PAA based on their emission levels
under the allocated cap.
Strict monitoring would assure other participants in the trading system that emission caps are
respected and that acquired PAA are valid. In addition, enforcement mechanisms, including penalties, would
guarantee that no participant is given undue advantage by being allowed to emit more than its allocation.
Power generators can measure their CO2 emissions in at least two ways, either through continuous
emission monitoring systems, or through fuel sampling or fuel assay.33
It may not be necessary for all
countries to agree on the same method, although a minimum standard would be necessary to provide a means
of certainty on the environmental effectiveness of the trading system.
b) Compliance
33
Brian Jantzi, Presentation at Third Session of the Greenhouse Gas Emission Trading Policy Forum,
London, 13-15 May 1998.

30
Governments who devolved PAA to their generating companies will also want to ensure that these
companies comply with their objectives. Non-compliance by a generator engaged in international emissions
trading could bring the government itself into non-compliance.
International emissions trading provides capped emitters with an additional means to meet their
domestic objectives. Still, some enforcement mechanisms may be required, such as the penalty used in the
US SO2-allowances trading program.
There are very few precedents of financial penalties in international legal agreements, and still fewer
examples of such sanctions being applied34
. Penalties would most probably be applied by domestic
governments, and would not have to be equal among countries. It is sometimes argued that the penalty could
act as a ceiling for the international market price. This would only be the case if the penalty cancelled the
obligation to meet the emission objective, as no participant would want to acquire PAA from the market at a
higher price than the penalty. But if paying the penalty does not cancel the environmental debt,
non-complying emission sources would still need to acquire PAA from the market and the penalty would not
play the role of a market ceiling for the price that companies are ready to pay to comply.
4.2 Other Design Issues
4.2.1 Links to Other Policies and Measures in the Power Sector
Power generators can control their own CO2 emissions, but they are not necessarily in a position to
affect their consumers’ electricity demand. Energy efficiency on the end-use side is also an important option
to reduce GHG emissions from the power sector. It will, however, be very difficult to allocate reduction
objectives, or to give PAA, to companies, or electricity users who reduce overall electricity demand. Hence,
their efforts to reduce emissions, if PAA are distributed at the generation stage, would benefit generators from
the standpoint of their environment objectives, although they would reduce the generators’ overall electricity
sales. Some work needs to be done to assure that all, producers and consumers, share the burden for reducing
emissions and that economic efficiency provided by trading benefits to all.
4.2.2 A System Open to Other Sectors
One objective of greenhouse gas emission trading is to assure that all participants have access to the
cheapest potential for GHG mitigation. Participation in an international emission trading system where other
Parties’ power producers are active will go some way in that direction. Other emission sources covered by
domestic trading systems would also want to gain access to this system, in order to buy or sell PAA for their
own compliance. To achieve economic efficiency, any system designed for the power sector would be fully
integrated in trading systems covering other sources. Here again, a common tradeable unit would be
warranted to avoid transaction costs when trading across sectors or countries.
4.2.3 Time-Frame for Emission Limit: Monitoring Compliance at Domestic Level
A government which devolved parts of its assigned amount to domestic power generators may need
to monitor compliance by these entities before the end of the commitment period in 2012, in order to avoid
34
See OECD (1998) “Responding to Non-Compliance under the Climate Change Regime”, OECD,
Paris.

31
being in non-compliance with its UNFCCC emission commitment.
For this reason, the compliance period of power generators may be assessed on an annual or
bi-annual basis at the domestic level, with the possibility of banking unused assigned amounts for the next
year in the same budget period (e.g. 2008-2012). While this would take away some of the time flexibility
introduced by the 5-year budget period, some of the fluctuations in power trade caused by climate are annual.
A bi-annual period may be enough to accommodate the climate fluctuations that could affect a large group of
countries, and hence their utilities for shorter periods of time.
4.2.4 Emissions Trading “Supplemental to Domestic Action”: an Issue at Micro-Level?
Article 17 of the Protocol on emissions trading specifies that compliance through acquired PAA
should be supplemental to domestic actions. This provision could raise questions about the participation of
legal entities. But with few exceptions, no single company is likely to acquire large enough quantities of PAA
to put their country in non-compliance with this principle, however defined.
Will governments want to control international trade by their power generators before the fact, to
guarantee that such a situation will not occur? While this would constitute an impediment to emission trading,
the fact remain that governments are solely responsible for compliance with the provisions of the Kyoto
Protocol. This question will need addressing once the terms “supplemental to domestic action” are clarified
in the Protocol.

32
5 Summary and Further Discussion
Open and competitive markets for electricity have been introduced throughout IEA Member
countries and beyond, creating a more efficient supply of electricity. Interconnections between regional
electricity networks are also developing, sometimes along with electricity exchanges. International
electricity trade represents a growing share of power produced. These developments occurred independently
of any concern for increased greenhouse gas emissions. The Kyoto Protocol now constrains individual
Annex I countries’ emissions, including, of course, emissions caused by exports of electricity. From the
example of Denmark, Norway, and Sweden this study explores the problems arising from the apparent
conflict between the economic efficiency and security delivered by international electricity trade, and
national GHG constraints.
These new constraints can be seen as potential barriers to electricity trade. But it is also true that
electricity trade can help increase the economic (and environmental) efficiency of power production.
Introducing international GHG emissions trading into the electricity trade opens up the possibility to combine
the economic efficiency of liberalized and open international markets with the environmental goal of the
Kyoto Protocol.
The power sector is increasingly integrated across countries, and it has a tradition in trading
electricity between different producers. Its local emissions of pollutants are also under strict control and the
sector has a tradition of monitoring its own emissions. These elements provide a good starting point for the
implementation of a GHG emission trading system including the power sector. There is a first example of
such initiative in Denmark, where fossil-fuel-based power producers have been allocated quotas for their
emissions which they can trade or bank for use in the next year.35
Of course, such an initiative can only be taken by governments, who remain the only Parties to the
UNFCCC and who are responsible for compliance with their emission objectives under the Kyoto Protocol.
Preliminary quantitative analysis for three Scandinavian countries supports the idea that free electricity trade,
combined with international GHG emission trading, could provide a cost-effective means to limit GHG
emissions among trading partners.
The economics of mitigation options available to the power sector are not covered here.36
The
choice of mitigation measures would affect the time frame and the cost profile of abatement. Fuel switching,
renewable energy and energy efficiency are available to utilities and regulators, but their implementation will
35
Information provided to the IEA by representatives of the Danish Energy Agency, October 1998.
36
See Canadian Electricity Association (1997): “Greenhouse gas management and the Canadian
Electric utility industry”, and EPA-NSW (1998) for assessments of the options and economics of
GHG mitigation for the power sector in Canada and Australia, respectively.

33
depend on local circumstances. The possible price attached to PAA is another element of uncertainty in the
power sector’s economic decisions. Without knowing the mitigation effort that will be required from the
power sector, it is not yet possible to determine what would be the price of PAA traded by power producers,
let alone traded under a market with the broad participation of other private sector sources.
In spite of these uncertainties, it is important to recall that with under a domestic or international
emissions-trading system, electricity generators could tap other participants’ mitigation potential, minimizing
their own and the sellers’ cost of meeting any greenhouse gas objective that would be assigned to them. The
generators could also sell PAA to other participants, and make a profit from such trade.
The following questions are also of importance:
• Regulatory frameworks: Do existing electricity market regulations and agreements between utilities
affect the possibility of including the cost of a CO2 emission target in electricity prices?
• Role of market re-structuring: How will the restructuring of the electricity industry, currently
underway in many IEA countries, affect electricity trade and trading patterns in the light of a
country’s emissions commitments under Kyoto? Would producers lose customers to their
competitors if these competitors rely on low-carbon technologies?
• Government control over international emissions trading: How much government
intervention is required to allow electricity trade to optimize GHG reductions from this
sector, given the national government’s accountability on greenhouse gas emissions under
the Kyoto Protocol? To what extent will governments insist on achieving greenhouse gas
emission reductions ‘at home’ and so seek to limit the participation of their sub-national
entities to a trading system?
Pilot emissions trading schemes are already planned or underway, such as the Greenhouse
Gas Emission Reduction Trading Pilot in Canada, or New South Wales’ discussion of a Tradeable
Reduction Scheme for electricity retailers in Australia. Norway is discussing the introduction of a
six gas emission trading system, and we have already mentioned Denmark’s new initiative for the
power sector. These early efforts may indicate how power generators, other large stationary
emission sources and governments could benefit from such systems, while clarifying some of the
practical implementation issues for an international emissions trading system.

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