Citation: 3 J. Network Ind. 375 2002
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JACQUELINE BOUCHER* and YVES SMEERS**
TOWARDS A COMMON EUROPEAN ELECTRICITY MARKET
Pathsin the Right Direction... Stillfarfrom an Effective Designt
ABSTRACT. This paper analyses the future organization of cross border trade in the
European electricity market. The draft Regulation "on Conditions for Access to the
Network for Cross-Border Exchanges in Electricity" issued in March 2001 by the European
Commission together with related documents produced by the European association of
Transmission System Operators (ETSO) and the Council of European Electricity Regulators
(CEER) until that date constitute the backbone of this analysis. The paper examines
whether the economic principles contained in these documents suffice to design a working
European electricity market and if not, what is missing. It concludes that these principles
need to be completed by harder measures in order to induce the "real integrated
single market" of electricity claimed by the Commission. In short, the principles may be
necessary, but they are unlikely to be sufficient.
KEY WORDS: cross border trade, electricity restructuring, internal electricity market,
transmission access
1. INTRODUCTION
As repeatedly stated by the European Commission (EC), the goal of the
Internal Electricity market (IEM) is "the creation ofa real integrated single
market, as opposed to a situation characterized by fifteen more or less
liberalized but largely national markets" (explanatory memorandum ofEC
(2001a) and similar statements for instance in EC (2001b), FRF (2000a)
or EC (1998)). The Directive 96/92 EC and its transposition into national
law by the Member States constituted the first step to that goal. In order to
further proceed towards the objective, the EC initiated the Florence Regulatory
Forum EC (2001c) in 1998: "The Forum convenes twice a year at
the European University Institute near Florence and consists of national
regulatory authorities, Member States, European Commission, Transmission
System Operators, electricity traders, consumers, network users, and
* Head of Risk, Asset and Liability Management, Electrabel, Brussels, Belgium.
* Tractebel Professor of Energy Economics, Department of Mathematical Engineering
and Center for Operations Research and Econometrics, Universit6 catholique de Louvain,
Louvain-la-Neuve, Belgium.
t The opitions expressed in this paper are not necessarily those of Electrabel or of any
of the companies ofthe Tractebel group.
JournalofNetwork Industries 3: 375-424, 2002.
@2002 Kluwer Academic Publishers. Printedin theNetherlands.
JACQUELINE BOUCHER AND YVES SMEERS
power exchanges. The Forum was set up to discuss issues regarding the
creation of a true internal electricity market that are not addressed in the
Electricity Directive. The most important issues addressed currently at the
Forum concern cross border trade ofelectricity, in particular the tarification
of cross border electricity exchanges and the allocation and management
of scarce interconnection capacity."
Taking stock of the work achieved in Florence, the EC decided in
March 2001 to introduce two new legislative proposals. The intent was
to submit them to the Council to be held in Stockholm that same month.
The legislation consisted of
(i) a draft Directive "amending Directives 96/92/EC and 98/30/EC
concerning common rules for the internal market in electricity
and natural gas" EC (2001d).
(ii) a draft Regulation "on conditions for access to the network for
cross-border exchanges in electricity in the internal electricity
market" EC (2001a).
The Council declined to discuss these proposals. The alleged reason
is the opposition of France, supported by Germany to the proposed 2005
deadline for the completion of the IEM. This setback may not stop the
overall IEM process (Stockholm European Council: Presidency Conclusions
2001), but it will certainly slow it down. This delay is an opportunity
for examining the draft legislation as well as supporting ETSO documents
and CEER views. This analysis is the objective of this paper: it focuses
on the draft Regulation with the view of assessing whether, possibly
completed by ETSO and CEER views, it provides the basis of the "real
integrated single market" claimed by the Commission.
One can indeed expect difficulties. European electricity systems were
restructured pursuant to directive EC96/92 (EC 1996) which leaves a lot
of flexibility to Member States to restructure their electricity market and
does not organize access to the network (see EC (2001e) for a review of
the transposition in the Member States and EC (2001f) for an EC analysis
of the status of the Internal Energy Market; see also Hancher (1998) and
Glachant (2000) for independent analysis of the subject). It is possible
that the transposition of the Directive into national law entailed sufficient
compatibility for the individual electricity and services markets to
assemble into a "real integrated single market". But the complexity of electricity
makes this outcome unlikely. The Commission is more optimistic:
it states in the Explanatory Memorandum of the draft Regulation EC
(2001a), that "It was in the logic of a gradual approach to implementing
the internal electricity market that specific issues remain to be addressed
after the principal strategic implementation choices have been made by
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EUROPEAN ELECTRICITY MARKET
Member States". Whatever one's own opinion on the evolution towards
the IEM, most will admit that it is now urgent to check that the process
converges and if not to take further harmonization steps. Convergence
towards a good market design is not spontaneous: as argued by Hogan,
"the market cannot solve the problem of market design" (Hogan 2000). In
this sense, France's rejection of the 2005 deadline for the completion of the
IEM is a paradoxical opportunity: the available documents do not convey
much evidence that we have the institutional instruments to complete the
Internal Electricity Market.
The objective of this paper is to substantiate this claim. Specifically, we
want to assess whether the draft Regulation introduces a well-tuned mix of
markets and controls compatible with an integrated electricity market. In
order to conduct this analysis, we examine the different articles of the draft
Regulation and comment their potential contribution to a "real integrated
single market". The conclusion of the analysis is most often that the principles
stated in the draft Regulation go in the right direction but need to
be drastically strengthened. There remain a lot of fundamental questions
to sort out and many opportunities to derail the process. Do ETSO and
CEER documents clarify the situation? They do, but they are also much
too soft. More specifically, most of the proposals of the draft Regulation
are sound. But they can only be effective if there are implemented through
a sufficient rich set of locational and real time prices. This set of prices
is what one does not see in the available documents. How do we arrive
at this conclusion? By formally seeking for certain flaws namely market
incompleteness. What are exactly these flaws? This is taken up in the next
section.
This paper does not discuss market power or asymmetry of information,
even though these phenomena are overwhelming in power systems. Market
power justified and asymmetry of information complicated the regulation
of the former electricity monopolies; they still pervade all restructuring
experiences. Taking them into account complicates the analysis. Specifically,
market power and asymmetry of information can only further
degrade the functioning of badly designed markets. Any shortcoming
identified before taking market power and asymmetry of information into
account will persist and be aggravated if these phenomena are taken on
board. We therefore focus on the shortcomings of the current design
proposals that already appear when market power and asymmetry of information
are neglected. In short, overlooking these phenomena does not
invalidate our diagnosis; it only makes it more benign.
The paper is organized as follows. A brief introduction to market
incompleteness and to its potential dangers is given in Section 2. Section
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JACQUELINE BOUCHER AND YVES SMEERS
3 sketches the methodology adopted in the paper: in brief, we assume
a bilateral organization of the market and reason on stylized networks.
The section also recalls some basic principles of electricity transmission.
Section 4 discusses articles 2, 3 and 4 of the draft Regulation while Section
5 goes in some depth in articles 5 and 6. A few words on the other articles
are given in Section 6 before the conclusions. The analysis relies on EC,
ETSO and CEER documents. These are globally mentioned in the paper
as the Florence documents. EC and ETSO documents can be downloaded
from the web. They are explicitly referenced in the text. In contrast, CEER
documents, although widely distributed, are not published. In order not to
attribute to CEER views that cannot formally be proven to be theirs, we do
not explicitly refer to CEER papers but simply give our views on various
questions that are taken up in these papers.
A revised version of the proposal has been submitted by the Commission
in June 2002. Other documents have also been issued by ETSO and
the Forum met a few more times. A follow up paper will analyze these
events. But its conclusion, at this time (Fall of 2002) can already be
announced: "... closer! But still far from an effective design".
2. ON MARKET DESIGN
Creating an integrated electricity market across different control areas is a
demanding task. It requires, not only opening access to cross border transmission
facilities, but also to create markets to facilitate the use of these
capacities. These markets involve the commodity (energy) and a range
of associated transmission and ancillary services. Therefore, an integrated
electricity market may also require an integrated market of other services.
Which services and how to organize their market is the question debated
in the Florence Regulatory Forum.
In order to get a first insight into these needs, consider what an integrated
electricity system would have required in the regulatory days. For
reference purposes, call the System Operator in charge of this integrated
system a Perfect System Operator (PSO) and assume that this PSO is
not limited by numerical, computational or communication constraints: its
technical capabilities encompass the whole European electrical system and
it can do whatever it finds suitable to manage this system. This conceptual
PSO controls all generators and demand side resources subject to the physical
restrictions imposed by the electric system. Its obligations include,
among others, to meet demand and reserve requirements as well as to
satisfy network constraints.
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EUROPEAN ELECTRICITY MARKET
Meeting all these obligations required a lot of controls. Restructuring
the electricity system does not eliminate physical constraints; it only modifies
the way they are tackled. This may suggest that substituting controls by
markets requires a market for each physical resource formerly controlled
by the PSO. This means a plethora of markets. Surely, this goes too far. One
should not rely on markets to do things that current technology prevents
them to do. The exact role of markets and controls should be carefully
delineated. The question has been elaborated by Wilson (1999). He reasons
that current technology does not permit to operate real time electricity
markets. Physical realities therefore restrict the replacement of controls by
markets. Electricity markets need to close before real time and relinquish
real time operations to the System Operator. As a result, electricity markets
are forward markets. "Real time" prices are computed ex post and depend
on a mix of market actions (market participants' offer of ancillary services)
and SO's controls (call upon these ancillary services). No restructuring
experiment has so far been able to exclude SO's controls from intruding
the market at some stage. California went as far as it could in untangling
both. But all analyses of the recent crisis (see for instance Besant-Jones,
J.E. and B.W. Tenenbaum (2001), Chandley, J.D., Harvey S.M. and W.W.
Hogan (2000), Harvey, S.M. and W.W. Hogan (2001), Hogan (2001),
Joskow (2001)) suggest that this may have been part of the causes of
the meltdown. In short, markets never completely manage the electricity
system. In economic parlance, the electricity market is always incomplete.
This incompleteness is also present in cross border trade. Identifying the
potential market incompleteness imbedded in the proposals of the Florence
documents is the main objective of this paper.
Trade-offs between controls and markets pervade electricity restructuring
whether in the commodity (energy) or the associated services
(here cross border transmission). But there are limits to what trade-offs
are allowed. Specifically, restructuring is flawed when physical control
is removed without markets taking over or when physical control and
prices of tight constraints overlap. Possibly less obvious, but certainly
as important in the European context, restructuring will be flawed if the
national commodity markets are incompatible with the organization of a
market for cross border transmission services. As argued in the introduction,
it is possible but unlikely that national designs are compatible with
one another. Managing the seams between national markets may thus place
a considerable burden on cross border transmission.
As for all components of the electricity system, controls or markets
can rule cross border transmission. Call explicit a market of transmission
services where such services are explicitly created, traded and priced. This
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JACQUELINE BOUCHER AND YVES SMEERS
is the case for example when rights/obligations to use part of a transfer
capacity are created and a dedicated auction organized to trade these
rights/obligations. This market is incomplete when the rights/obligations
inadequately reflect the physical use of the network resources. This is the
case when a fixed transmission capacity is traded while the transmission
capacity available in real time is inherently variable and random. Incompleteness
comes from the fact that one is trading a single non-contingent
service while the network can only deliver contingent services. Introducing
here a comparison that will be used repeatedly, it is like producing a range
of truck models but trading only one abstract average truck. Incompleteness
can be deeper. The market of transmission services may be missing.
This happens for example when transfer capacities are not traded but
allocated on the basis of some priority rule (e.g. first come, first served)
and there exists no secondary market for these services. Both cases lead
to an incomplete IEM, namely one where physical transmission resources
are not fully or even not at all traded. But an IEM where transfer capacities
are allocated on the basis of priority rules (that is not traded) is in a sense
more incomplete than one where non-contingent transmission capacities
are traded through an auction.
Implicit transmission markets arise when transmission services are
bundled in the price of the commodity. The commodity is then traded
locally in a way that reflects the price of the implicit transmission service.
Implicit auctions, market splitting and nodal prices are implicit transmission
markets. Implicit auctions require a pool, an organization that is not
standard in Member States. The Florence documents refer to market splitting
to claim either that it is too advanced for Europe (section II, 4 in
the explanatory memorandum of EC (2001a)) or that the highly meshed
network of continental Europe makes its implementation questionable
ETSO (2001d). They do not refer to nodal pricing which is a more elaborate
version of market splitting, even though it is ideally suited for highly
meshed networks. Because of these different reasons and in order not to
unduly extend the length of this paper, we do not elaborate on implicit
transmission markets.
We shall argue that the proposals contained in the Florence documents
introduce an incomplete explicit transmission market in the IEM
and hence put this latter at risk. In some sense, this claim is compatible
with statements of the draft Regulation that announce further steps, "...
the draft Regulation provides for the subsequent adoption of guidelines
detailing further relevant principles and methodologies" (section II in the
explanatory memorandum of EC (2001a)). Something beyond the draft
Regulation is needed. But it might be needed urgently.
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EUROPEAN ELECTRICITYMARKET
Missing or incomplete markets do not necessarily have dramatic
consequences, but they may. It all depends on the relative importance of the
services that are incompletely traded. For instance, a sophisticated transmission
market is not important if cross border trade does not develop.
Similarly, not trading the real transmission resources does not matter if
they are plenty ofthem compared to the cross border activity. But the risks
created by an incomplete transmission market may sometimes materialize
and seriously endanger not only the energy market but also the physical
system itself. This will be the case if cross border trade develops and the
transmission resources are tight compared to the demand for their use.
More specifically and in direct relation with the discussion of this paper,
consider the trading of non-contingent transmission capacities affected
by random failures. There will be bottlenecks at some time and idle but
valuable transmission possibilities at others. Unused valuable transmission
resources are a true economic waste but it may be unnoticed. In contrast,
bottlenecks are felt. They are acceptable if removed at a small cost or
through exceptional and limited curtailments. But there are more critical
situations. Removing a bottleneck may be quite costly when transmission
constraints are severe. Curtailments may become recurrent when resources
for removing bottlenecks are structurally missing or need to be procured by
intrusive administrative measures. These situations develop from lack of
capacity and/or perverse economic incentives that result from bad market
design. They indicate that the restructuring process has failed.
Former experience in PECO (Hogan 1999) and the Californian meltdown
show that the danger is real. True, the European Commission
promises "a truly integrated market, which means, for instance, that
Europe will avoid the type of problems currently faced by California,
which have resulted from inadequate legal framework and inadequate
production capacity" EC (2001b). But former Governor Wilson also
announced at the time a "vibrant" electricity industry in California. Surely,
the current draft legislation is not the final word and discussions at the
Council ofMinisters and the European Parliament leave room for improvements.
But this is no guarantee that the legislation will work: recall that
both houses of the California legislature unanimously passed Assembly
Bill 1890 in 1996. Political statements are useless in complex technical
matters. And quick political fixes only make the situation worse. Nothing
can replace an a priori careful identification of features of the market
design that economic reasoning tells us are flawed. They may jam the
Internal Electricity Market, and this notwithstanding the stew of free
market and public service rhetoric that comes with the legislation.
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JACQUELINE BOUCHER AND YVES SMEERS
3. THE METHOD OF ANALYSIS
3.1. A Market Organization
Pools and bilateral trade constitute the two main organizations of restructured
electricity markets. The current status of the IEM (see EC 2001e)
indicates that the bilateral organization dominates, at least initially in the
EU. For the sake of simplicity we limit ourselves to this latter model. In
this organization, marketers trade electricity through bilateral transactions.
They also request transmission services, among them cross border transmission
to complete their deals. The problem is thus one of allocating
cross border transmission resources to bilateral transactions. Keeping in
line with the draft Regulation, we assume that this allocation should be
done by market mechanisms.
Cross border transmission lines link the different control areas of
the European electricity system. Each control area is run by a separate
TSO. Except for Germany, domestic transmission services in continental
Europe are regulated and priced according to a postage stamp mechanism.
There is thus no mention of working markets of domestic transmission
services. This contrasts with the recommendation to organize cross border
transmission on a market basis. This difference of approach may be justified
on the ground that domestic network capacities are deemed globally
sufficient and that domestic re-dispatching or counter trading can easily
accommodate occasional bottlenecks. We take stock of this assumption
and suppose away bottlenecks in the domestic grids. This simplifying
assumption is implicit in most Florence documents. It can and should
be revisited at some point. It is briefly questioned in this paper when
discussing Articles 2 and 8 of the draft Regulation. There is a general
consensus that TSOs should coordinate their actions when it comes to cross
border trade. The exact nature of this coordination is not fully specified yet
but the Florence documents sketch what is aimed at. A useful proposal
by ETSO to coordinate auctions of transfer capacities (ETSO 2001b)
is mentioned later. This document published one month after the draft
Regulation constitutes the starting point of our forthcoming follow up
analysis.
Exchanges exist in various European places and new ones are planned.
Transmission constraints have an impact on the price in these power
exchanges. But we posit that the current state of development of the
IEM does not permit to price cross-border transmission constraints on the
basis of differences of energy prices in the exchanges. We instead adopt
the view that a good market of transmission services is a prerequisite to
achieve meaningful electricity prices in the exchanges, but not the other
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EUROPEAN ELECTRICITY MARKET
OI(North)
Q II (South)
Figure1. The North-South example.
way around. This attitude complies with ETSO's conclusions that market
splitting of the type operated in Scandinavia cannot be used for assessing
transmission prices in the highly meshed continental network (ETSO
2001d). The relative illiquidity of the European exchanges compared to
Nordpool also supports that position. On more fundamental grounds, some
Nordic voices (Bjorndal and Jornsten 2001) now also question the zonal
pricing implied by Nordpool market splitting.
3.2. Two Stylized Networks
Flaws appearing in stylized examples do not vanish in the real world.
We therefore conduct the analysis on two very schematic networks. In
order to simplify the discussion, we neglect losses and work with the
standard DC load flow approximation of the load flow equations. The first
network, commonly called the North-South model, is depicted on Figure
1. It consists of two nodes or control areas separated by a transmission
capacity. This example has been used in various texts of the literature
(Wu et al. 1996; Oren 1997; Joskow and Tirole 2000). It is also used
occasionally in ETSO papers (e.g. ETSO 2001a). The second example,
depicted on Figure 2, was introduced in Chao and Peck (1998). Except
when stated otherwise, we follow these authors and assign generation at
nodes 1, 2 and 4 and demand at nodes 3, 5 and 6. We suppose rounded
marginal generation costs of 10, 20 and 30 euro/Mwh at node 1, 2 and 4
respectively.
Different groupings of the six nodes into control areas illustrate various
zonal patterns in the overall market. A two control area example is obtained
by grouping nodes 1, 2, 3 and 4, 5, 6 in zones I and II respectively (Figure
3).Alternatively, we obtain a four-control area system if nodes 3 and 4
respectively constitute zones I and II while zones III and IV respectively
consist of nodes 1, 6 and 2, 5 (Figure 4).
Kirchoff's laws direct electric flows. Power Distribution Factors (PDF)
offer a particularly simple representation of these physical laws. In order
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JACQUELINE BOUCHER AND YVES SMEERS
Figure2. The six node example.
II
Figure3. The six node/two zone example.
to illustrate the use of PDFs, suppose as Chao and Peck (1998) that the
impedance of all lines but (1-6) and (2-5) is I while lines (1-6) and (2-5)
have an impedance equal to 2. The PDFs derived from the DC load flow
approximation are given in Table I.
They can be interpreted as follows:
(i) A unitary (1 Mw) injection in node i with off-take at some fixed
but arbitrary reference "hub" node (here taken as node 6) entails
a flow equal to PDF(mn)i in line (mn). The flows in the different
lines resulting from a unitary transaction from node i to 6 are
accordingly given by the PDFs of column i in Table I.
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EUROPEAN ELECTRICITY MARKET
I
III IV
II
Figure4. The six node/four zone example.
TABLE I
PDF coefficients.
Node 1 Node 2 Node 3 Node 4 Node 5
PDF(23) -0.1250 0.1667 -0.4792 0.0208 0.0417
PDF(31) -0.1250 0.1667 0.5208 0.0208 0.0417
PDF( 12) 0.2500 -0.3333 -0.0417 -0.0417 -0.0833
PDF(56) 0.2500 0.3333 0.2917 0.2917 0.5833
PDF(64) -0.1250 -0.1667 -0.1458 -0.6548 -0.2917
PDF(45 ) -0.1250 -0.1667 -0.1458 0.3542 -0.2917
PDF(25 ) 0.3750 0.5000 0.4375 -0.0625 -0.1250
PDF( 16 ) 0.6250 0.5000 0.5625 0.0625 0.1250
(ii) A unitary transaction from node i to node j entails a flow in line
(mn) equal to the difference PDF(mn)i - PDF(mn)j. As an example
the flow in line (1-6) due to a unitary transaction from node 1to
2 is equal to 0.125 = PDF(1-6)1 - PDF(1-6)2.
3.3. Some Questions
The paper considers three types of questions. The first one is the very
theme announced in the introduction: does the draft Regulation, possibly
completed by ETSO and CEER papers, suffice to induce a "real integrated
385
JACQUELINE BOUCHER AND YVES SMEERS
single market"? We conclude that the documents provide good principles
but remain far from offering an effective design of the electricity market.
More is needed to reach the objective. In other words, even though the
principles may be necessary, "The rules contained in the Regulation are as
simple as possible and are limited to what is necessary to regulate in EC
legislation, in compliance with the principle of subsidiarity" (section I in
the explanatory memorandum of EC (2001a)) they may remain far from
sufficient.
The practical applicability of the various proposals is a second issue of
interest. Good principles are useless when too difficult, if not impossible,
to implement. We thus also try to pinpoint recommendations that are likely
to result in a deadlock because they cannot be applied in practice. Referring
to the same statement of the explanatory memorandum of the draft
Regulation, the proposed rules are not "as simple as possible".
Jurisprudence develops by logically deducting new principles from old
ones. The US experience shows that this can be a particularly rich process
in electricity restructuring. A third objective of the paper is thus to try to
pinpoint articles of the draft Regulation that have a strong imbedded but
still hidden power. And indeed, there seems to be a lot of potential in the
draft Directive. But developing this potential may require quite involved
reasoning.
4. ARTICLES 1 TO 4
Articles 1 to 4 of the draft Regulation offer straightforward but fundamental
economic principles.
4.1. Article 2: Loop Flowsand CrossBorderTrade
4.1.1. Loopflow arepartof transitandthere may be congestion on the
grid
By stating that loop flows are part of electricity transit, paragraph 2(a) of
Article 2 strengthens the definition adopted in earlier and more general
legislation or international agreements. It also makes it applicable to
electricity.
'Transit' of electricity means a physical flow of electricity hosted on the transmission
system of a Member State, which was neither produced nor is destined for consumption in
that Member State; this definition includes transit flows which are commonly denominated
as 'loop-flows' or 'parallel flows'.
Loop flows are important features of cross border electricity trade. We
briefly recall their physical nature on the six-node/four-zone example
386
EUROPEAN ELECTRICITY MARKET
(Figure 4). Consider a unitary transaction (1 Mw) between control areas
I and II (e.g.from generation node 4 to demand node 3). This transaction
entails flows of 0.5 Mw through both control areas III and IV. Kirchoff's
laws make it difficult for the TSOs and impossible for the marketers to
modify these flows. Specifically, the System Operators can redirect the
transit flows into the two control areas by changing the topology of the
network or by modifying the characteristics of the lines through phase
shifters. These actions are beyond the control of the marketers who can
only select the origin and destination of their transactions but not the transit
path.
Here is a more extreme situation. Consider a unitary transaction
between the two neighboring areas I and III (e.g. from node 1 to node
3). Kirchoff's laws imply that 0.0625 Mw of this transaction (PDF(2-5)3 PDF(2
-5)1) flows through line (5-2) of zone IV. In other words, atransaction
between two adjacent areas partially flows through other areas. It spreads
through the whole grid. Directive 96/92/EC does not elaborate on this
pervasive effect. But the definition of Paragraph 2(a) of Article 2 does so in
a way that reconciles physical and commercial realities. The recognition
that loop flows are part of transit is fundamental. Most of this paper is
about the implication of this physical reality. Paragraph 2(b) of Article 2
introduces a first consequence namely congestion:
'Congestion' means a situation in which an interconnection linking national transmission
networks cannot accommodate all transactions resulting from international trade by market
operators, due to a lack of capacity.
Congestion is a key issue in electricity markets; we further discuss its
physical nature before elaborating on the definition adopted in the draft
Regulation.
4.1.2. The physical notionof congestion
Physically, congestion arises when a transmission resource is saturated.
This can happen in different ways. Congestion in the North South network
(Figure 1)occurs when the flow between the two zones saturates the single
line linking them. This is akin to congestion of a single road linking two
areas except for one major difference: queues are not possible in electricity
with the consequence that the network collapses whenever there is a traffic
jam.
Consider the more complex case of the six-node/two-zone meshed
network (Figure 3) and assume that lines 1-6 and 2-5 respectively have
180 and 200 Mw thermal limits, all other lines having an infinite capacity.
Congestion arises when it is impossible to further transfer electricity from
zone I to II. Because of Kirchoff's laws, this may happen when one of
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JACQUELINE BOUCHER AND YVES SMEERS
all lines are up line (2-5) is down line (1-6) is down
Figure 5. n-I criterion.
the lines (say 2-5) is saturated even though the other (say 1-6) still has
idle capacity. Take the case where one wishes to transfer power from node
2 in zone I to node 5 in zone II. The transaction is limited to 320 Mw
(200/(PDF(2-5)2 - PDF(2-5)5) with line 2-5 saturated and 60 Mw of unused
capacity remaining in line 1-6 (the flow on this line is 120 Mw equal
to 320*(PDF(1-6)2 - PDF(1- 6)5)). Even though one of the lines has spare
capacity, physical laws prevent the Systems Operators from using it. In
short, the transmission capacity between the two zones is not the sum of
the capacities of the two lines.
Reliability adds a further complication. For reliability reasons, electricity
networks are commonly operated according to the n- 1criterion. This
principle provides that a dispatch is only deemed feasible for the network
if the flows that it entails are feasible in each contingency where a line
defaults (Figure 5).
Apply this notion to the interconnection between zones I and II. There
is congestion whenever the flow between zones I to II in any of the two
default states saturates the remaining operating tie lines. Consider again
the above example of a transfer from node 2 in zone I to node 5 in zone
II. The transaction will be limited to 180 Mw even though only 67.5 and
112.5 Mw flow in lines 1-6 and 2-5 in the normal state. The physical limits
of the lines in the default states are reached even though none of the lines
of the interconnection is at capacity in the normal state. As will be seen
later, more exotic circumstances may add to the strangeness of congestion.
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EUROPEAN ELECTRICITYMARKET
4.1.3. An ambiguousdefinitionofcongestion
Paragraph 2 recognizes congestion where an interconnection cannot
accommodate "transactions resulting from international trade by market
operators due to a lack of capacity". Paragraph 2 defines neither international
trade nor interconnection. We interpret "international" as "crossborder".
Directive 96/92/EC (EC 1996), which applies to the draft Regulation
defines "interconnectors" as "equipment used to link electricity
systems"; this is almost the language of paragraph 2b. We use "interconnection"
in the sense of a set of interconnectors linking two electricity
systems and broadly identify the saturation of the "interconnection" with
a saturation of at least one of its constituting "interconnectors". Are these
definitions adequate?
Consider the North South example first. The physical congestion is
well captured by the definition: the line between North and South is
saturated if and only if the interconnection linking North and South
"cannot accommodate all transactions resulting from international trade
by market operators, due to a lack of capacity".
Consider now the example of a meshed grid constructed on the sixnode/two-zone
example. Assume two domestic and one international
transactions. Domestic transactions in zones I and II respectively trade
1000 Mw from node 1 to node 3 and 1000 Mw from 4 to 6. The international
transaction I-I trades 100 Mw from node 1to 6. Altogether the flow
in line (1-6) amounts to 187.5 Mw (62.5 Mw from domestic transaction I,
62.5 Mw from domestic transaction II and 62.5 Mw from the international
transaction). The thermal limit of line (1-6) is 180 Mw, which implies that
it is saturated (an excess flow of 7.5 Mw in one of the interconnectors).
This congestion is recognized by the definition of paragraph 2 to the extent
that "all transactions resulting from international trade cannot be accommodated".
But one may as well argue that it is impossible to accommodate
the national transactions! Each transaction indeed entails a flow of 62.5
Mw in line (1-6) and it is the sum of them that saturates it.
Suppose now that domestic transactions increase by 50% while international
trade disappears. The flow in line 1-6 is still 187.5 and there
is still congestion in the physical sense. But the interconnection trivially
accommodates all international trades since there is none. Is this a
congestion in the sense of paragraph 2? No apparently but the paradox
disappears and the physical congestion is indeed recognized if "international
trade" is replaced by "trade". One can also find bizarre that the
internal market singles out certain transactions on the sole ground that they
are international.
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As a last example, suppose that line 1-2 in zone I has a thermal capacity
of 250 Mw (this is one of the few cases in this paper where we consider
saturation of a domestic line) and consider the previous domestic transaction
of 1000 Mw in zone I. These 1000 Mw going from node 1to node 3
entail a flow of 291.7 Mw on line (1-2), which exceeds its thermal limit.
This domestic transaction prevents any international trade from node 1 to
zone II.There is a lack of capacity in the network, but not on the "interconnectors"
linking the two control areas. This lack of capacity occurs without
any international transaction. Is this a congestion in the sense of the draft
Regulation? One can always argue that it all depends on the exact definition
of interconnection and hence on the computation of transfer capacity.
Alternatively, one can argue that this excess flow on a domestic line should
first be removed by domestic measures and that congestion in the sense of
paragraph 2 only occurs when there is an international transmission. But,
all this is not defined in the draft Regulation. Moreover, as will be argued
later, the notion of transfer capacity is itself inherently ambiguous and the
differentiation between domestic and international transactions unnatural
in a "real integrated single market".
Do cases like this occur in practice? They surely do. In periods of
low demand, Svenska Kraftnat occasionally reduced the capacity on the
interconnectors between Denmark and Germany because of congestion on
its domestic grid. This is particularly noteworthy as Sweden is generally
recognized as having a strong system with little congestion and ample
counter trading resources. As another example, TenneT attributed some
limitations on the interconnection between Belgium and the Netherlands
in the winter of 2000 to the damages caused by a storm to the domestic
French grid.
4.2. Article 3: Network ExternalitiesShould be Internalized
Loop flows are almost textbook examples of economic externalities. They
result from an agent's action and influence (limit or enhance) the possibilities
of other agents to act. Standard economics recommends internalizing
externalities. This is also what Article 3 of the draft Regulation does, at
least to some extent. Specifically, paragraph 1 states that
Transmission system operators shall receive compensation for costs incurred as a result of
hosting transit flows of electricity on their network.
Paragraph 2 further requires that
'The compensation referred to in paragraph I shall be paid by the operators of national
transmission systems from which transit flows originate and/or the systems where those
flows end.
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The first principle is sound but the second is controversial.
4.2.1. Who shouldpayfor transitcosts?
Consider the six-node/four-zone example (Figure 4) and a transaction from
zone II (generation at node 4) to zone I (demand at node 3). Zones III and
IV may incur costs because of this trade. The draft Regulation requires
that these costs be compensated. This is in line with economic reasoning.
Who should pay the compensations? The draft Regulation states that the
operators of those systems from which transit flows originate and/or those
systems where these flows end should pay these costs. ETSO disagree
(ETSO 2001f). Economic reasoning supports ETSO's position: those who
are responsible for the costs should pay. TSOs landII did not cause transit
costs and hence should not be liable for them. TSOs will thus charge these
costs to domestic users in their control area. But they can do so in different
ways. One approach is that I and II recover these costs from the marketers
who caused them. This does not create distortion of competition. But TSOs
I and II could also socialize these costs. This distorts competition and
hence the incentives to trade.
The European Commission apparently recognized the danger at the
November 2000 meeting of the Florence Regulatory Forum when it
argued, "it is not possible to accept 'that the potentially different
approaches at Member State level do not result in distortion of the IEM'"
(FRF 2000b). The Draft Regulation does not go that far: it states in Section
m. 1of the explanatory memorandum "apart from exceptional cases, it is
technically not-yet-possible to identify whether and to what extent an individual
exporter/importer causes transits. Therefore, the draft Regulation
does not foresee a mechanism whereby individual exporters or importers
are directly held responsible for transit flows". This says that it is not-yetpossible
to charge transit costs to those who caused them. Needless to say
large transit costs would be a stumbling bloc to the IEM if they cannot be
properly internalized. A nodal system would remove this stumbling block.
But the Florence documents do not consider nodal prices.
4.2.2. Incrementalcosts oftransitor transmission
Suppose we neglect this difficulty, would paragraphs 1 and 2 suffice to
define a good organization of cross border trade? Not really: one still
needs to compute the "cost incurred as a result of hosting transit flows
of electricity on their networks". This is handled in Paragraph 6:
The costs incurred as a result of hosting transit flows shall be established on the basis of
the forward looking long-run average incremental costs (reflecting costs and benefits that a
network bears from hosting transit flows compared to the costs it would bear in the absence
of such flows).
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The introduction of average long run incremental costs (ALRIC) confirms
a jurisprudence initiated in telecommunication. The principle also looks
reasonable: those suffering incremental costs because of transit should
recover them. But ETSO (ETSO 2001f) asks for clarifications on this
statement. How should ALRIC be determined? The draft Regulation only
provides a definition; is this really operational? Take the (uncontroversial)
definition of incremental costs given in Hunt and Shuttleworth (1996):
"Incremental cost is sometimes used instead of marginal cost, when referring
to the cost of an increment of use sustained over a long period.
It is the difference between total system costs with and without the
increment in use". Computing the incremental cost of some transmission
activity therefore requires comparing the cost of transmission systems for
some increment of transmission activity sustained over a long period. But
Paragraph 6 requires selecting a sensible increment of transitflows not
of transmission flows. It accordingly demands to choose an incremental
transit activity sustained over a long period.
We illustrate the situation on the six-node/four-zone model and focus
on the network of control area IV (nodes 2 and 5 and line (2-5)). For the
sake of this illustration, we temporarily locate a generator at node 3in zone
I and a demand in node 4 of zone II. We assume that zone II imports from
zones I and III, while zone IV does not import (consumption in node 5 is
equal to generation at node 2). All transactions that use the grid of zone IV
demand the same network service namely an injection at node 2 and an offtake
at node 5. Zone IV incurs transit costs because of the transactions III-II
and I-II. According to paragraph 2, these need to be compensated by the
TSOs of zones I, II and III.The compensation mechanism first requires the
TSO of zone IV (or another agent) to select an "increment of (transit) use
sustained over a long period" for both transactions III-I and I-LI. Doing
this in a sensible way is certainly a challenge given the current stage of
development of the TEM; but suppose it can be done.
By definition, the end result of the computation of the average long run
incremental cost depends on the size of the "increment of use sustained
over a long period". There is no reason why this should be the same for
the transits from III to II and from I to II, neither for control area IV own
use of its network. There is thus no reason for the ALRIC of both transits
to be the same or to be equal to the ALRIC of zone IV. Does the draft
Regulation then imply that TSO IV can charge two different ALRICs to
TSOs II-III and I-II for the same use of the network (injection in node 2
and off-take in node 5)? Does it also mean that TSO IV is allowed not
to charge anything for its own use of the network in case the ALRIC
of its own transactions were zero? This looks like plain discrimination.
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At least, it is not an equality of treatment. The obligation to separately
compensate for flows due to transit and domestic transactions on the basis
of their individual ALRIC adds to the drawbacks of charging TSOs, and
not marketers, for transit costs.
Note that both paradoxes immediately disappear if the ALRIC is
computed once for the global transmissionactivity irrespective of whether
it is transit or domestic transmission. In other words, the difficulty
disappears if domestic and international transactions are put on an equal
foot, something that appears quite reasonable in a "real integrated single
market". Any distinction between domestic and transit flows is bound to
introduce, via the ALRIC, an inequality of treatment between domestic
and other uses of the network. Any further distinction between different
transit sources is bound to introduce, for the same reason, an additional
differentiation of treatment between transits. This is not surprising: ALRIC
is an ad-hoc substitute of long run marginal cost. But it does not inherit all
its good properties, especially when it comes to send non-discriminatory
signals. Marginal costs are by definition non-discriminatory, but average
long run incremental costs are not.
4.2.3. What should incrementalcosts include?
The difficulty of computing "forward looking long run average incremental
costs" is further exacerbated by disagreements among participants to the
Florence Regulatory Forum as to what to include in these costs: losses,
congestion and/or investments? First principles provide an answer. Long
run average incremental costs are substitutes of long run marginal costs.
The determination of the former should therefore follow the logic of the
latter. Standard reasoning reckons that marginal investment cost should,
under usual economic assumptions, be equal to the sum of marginal
congestion and losses costs. Transpose this principle to incremental costs:
incremental investment costs must be approximately equal (strict equality
cannot be guaranteed with incremental costs) to the sum of incremental
congestion and losses costs. Either one, that is investment or the sum of
congestion and losses costs can thus equivalently be used as the relevant
incremental cost. Maybe indivisibilities and economies of scale of the
lines justify preferring investment costs. This can be debated on rational
grounds. But any other mix, such as the sum of investment and losses costs,
as is sometimes proposed, cannot be economically justified.
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4.2.4. Can one really compute incrementalcosts in an interconnected
system?
It remains to compute the relevant incremental investment (or sum of
congestion and losses) costs. Is this easy? Participants to the Florence
Regulatory Forum have expressed the wish to have unambiguous rules to
identify investments due to loop flows and transits. Such rules would allow
one to charge the costs of these investments to the market participants that
benefit from them. But these ideal objectives are probably impossible to
reach. It is indeed difficult, if not impossible, to effectively identify who
benefits from a reinforcement in a strongly meshed network. One can
certainly devise rules and procedures, but the difficulty is to make them
economically meaningful. A preliminary question is whether TSOs should
compute incremental cost individually, that is neglecting network externalities
or cooperatively, that is taking them into account. The resulting cost
is likely to be too high, if not completely arbitrary, in the first case. It
will require a supra national organization (e.g. ETSO) in the second case.
In both cases, a difficult allocation problem (a cooperative cost allocation
game problem) will have to be solved to share the cost among the benefiting
parties. Are we sure we can do this in a sensible way? The bets are
that the measurement and use ofthe average long-run incremental cost will
be plagued by considerable arbitrariness and hence be prone to litigation.
4.2.5. CanETSO compute incrementalcosts?
ETSO asked clarifications about the use of long run incremental costs.
This is not a surprise. ETSO did not really think in terms of incremental
costs so far. This is best illustrated in the provisional tariff now discussed
since the fifth Florence Regulatory Forum (see FRF 2000a, 2000b, 2001).
ETSO (see ETSO 2000b, 2000c) derived the export charge by allocating
existing costs, not by computing forward-looking incremental costs. The
whole notion of horizontal network, which underlies this export charge, is
a rephrasing of cost allocation into cost causality. The language may have
a flavor of incremental cost but the bottom line is cost allocation. These
computations suggest that ETSO is still far from a sensible implementation
of average long-run incremental cost of transmission, let alone of transit.
And not surprisingly so because the difficulties are real.
4.2.6. To sum up on ALRIC
There exists an extensive experience with Average Long Run Incremental
Cost in the UK. It shows that the notion must be validated in each particular
case. Its applicability to the more complicated context envisaged by
the draft Regulation remains untested at this stage. Various authors have
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already pointed out that the ALRIC is not a clear-cut notion (Laffont
and Tirole (2000) discuss the approach in the case of telecommunication
and argue that its application is subject to considerable discretion
(see pp. 148 and the subsection "4.4.1 Discretion in the Measurement
of the ALRIC")). Specifically in the context of the draft Regulation, the
application of ALRIC to transmission requires to define an "increment
of use sustained over a long period". This is a challenging task in the
current unstructured IEM. Selecting this increment of use for transit (and
possibly even individual transits), not for transmission further adds to the
complication. Not only is the approach questionable in theory, it may turn
out counter productive in practice. But even when assuming that this can
indeed be done, it remains to compute the incremental costs of each grid
for the different increment of transit transactions. The pervasive externalities
of the power grid make this a daunting task. In short, those proposing
the approach should provide evidence that it can indeed be implemented.
If our reading of the draft Regulation is correct, this rule is not "as simple
as possible".
4.3. Article 4: There are ChargesforAccessing the Network
Article 4 elaborates on the structure of the access charges to the network.
Access charges have been extensively debated in the industrial economics
literature. But, except for congestion pricing this literature does not
offer anything special to electricity. Not surprisingly, the draft Regulation
therefore limits itself to general remarks.
4.3.1. Sound but too generalprinciples
Paragraph 1of Article 4 states that
Charges applied by national grid-operators for access to national networks shall reflect
actual costs incurred, and shall be transparent, approximated to those of an efficient
network operator and applied in a non-discriminatory manner. They shall not be distance
related.
Except possibly for the restriction imposed by the last sentence, these
are very sound albeit quite general objectives. But ETSO (2001f)
sees inconsistencies and seeks clarifications about the efficient network
operators. The reference to distance related tariffs might not help either.
Paragraph 1 bans distance-based tariffs. But it is an established policy in
the UK to use models that minimize Mw.Km (a measure that includes
a distance criterion) in order to derive long term incremental cost based
locational signals. One should also note that the minimization of Mw.Km
was extensively used in the past to get a first cut into network investments.
Efficient network operators, like EdF resorted to these models. Distance
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has thus a real, albeit involved, relation with incremental network costs.
The prohibition of distance related access charges should therefore not
be total. Banning distance based cost allocation is certainly economically
justified. But one should not prohibit the computation of incremental cost
on the basis of distance.
Paragraph 2 of Article 4 deals with the problem of the allocation of
access charges between generators and consumers. It states that
Generators and consumers (load) may be charged for access to national networks. The
proportion of the total amount of the network charges borne by generators shall be lower
than the proportion borne by consumers. Where appropriate, the level ofthe tariffs applied
to generators and/or consumers shall provide locational signals, and take into account the
amount of network losses and congestion caused.
These principles open many options. Specifically, access to the network
can take the form of linear or non-linear tariffs or of sophisticated menus
or sums of such tariffs. Sum of linear tariffs are common in practice:
they include prices for energy (the commodity) and maximal demand (the
demand charge). Non-linear tariffs also include a fixed component. Their
efficiency properties are extensively discussed in the regulatory economics
literature. Both the fixed and variable components of the linear or nonlinear
tariffs can include the locational signals mentioned in Paragraph 2.
These locational signals can depend on congestion and losses.
Some of these options have been discussed in the Florence Regulatory
Forum, others not. Specifically, the choice between linear and non-linear
access charges did not retain much attention. In contrast, the respective
charges paid by consumers and generators have been extensively debated.
Some insist that generators pay an access charge; others argue that only
consumers should pay. This obviously creates a distortion of competition
that is hard to accept in the IEM. Generators that need to pay
access charges in their home system suffer a competitive disadvantage
compared to those that operate in a system where the consumer pays
the entirety of these charges. This harmonization problem is well recognized
in the explanatory memorandum of the draft Directive that devotes
a whole section to the problem ofthe "Harmonization of national network
charges". It is commonly admitted that generation is more price responsive
than load. This justifies the suggestion that it is most efficient to recover
network costs on load. This position seems to be gaining ground but is not
fully embedded in the draft Directive that simply requires that
The proportion of the total amount of the network charges borne by generators shall be
lower than the proportion borne by consumers.
Full harmonization is thus unlikely to be achieved, with inevitable
consequences on competition.
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4.3.2. What aboutlocationalcomponent?
The introduction of a locational component in the access charge is another
issue of debate. In principle, locational components should be based on
incremental costs that include losses, congestion (which are opportunity
costs) or investment costs. They should not include existing network costs.
But some participants to the Florence Regulatory Forum do not seem to
accept these basic principles. Only after an agreement is reached on this
fundamental issue, can one envisage to tackle the economic and computational
problem raised by the inclusion of a locational component in the
access charge.
4.3.3. The otheraspects
The other paragraphs of Article 4 discuss technically less difficult, but still
sometimes institutionally controversial issues. Paragraph 3 states that
Payment and receipts resulting from the inter-transmission system operator compensation
mechanism set out in Article 3 shall be taken into account when setting the tariffs
for network access. Actual payments made and received as well as payments expected
for future periods of time, estimated on the basis of past periods shall be taken into
account.
This suggests that TSOs will not be a for profit organization, or at least that
their profit will be regulated. This raises the usual question of providing
the right incentives to TSOs (e.g. the incentive to offer maximal transfer
capacities (see below)).
Paragraph 4 states that
Exporters and importers shall not be charged any specific tariff in additional to the general
tariffs for access to national networks.
This should exclude in the long run the ill designed export charge that is
part of the provisional tariff (FRF 2000a, 2000b, 2001).
Finally, paragraph 5 states that
There shall be no specific network charge on individual transactions for transits of electricity
covered by the inter-transmission system operator compensation mechanism set out
in Article 3.
This is similar in spirit to paragraph 4: specific tariff to export and import,
or tariffs that depend on the nature of the individual transaction are not
justified in a "real integrated single market".
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5. ARTICLES 5 AND 6
5.1. Article 5: The System is Based on Transfer Capacity
Articles 5 and 6 deal with congestion, that is with the physical, but hopefully
occasional, segmentation of the "real integrated single market". A
good treatment of congestion is of central importance in a market that one
ideally wishes not to be segmented. Article 5 introduces the main tools
foreseen for this purpose.
Paragraph 1of Article 5 assigns the responsibility of the transmission
systems to the TSOs:
Coordination and information exchange mechanisms shall be put in place by transmission
system operators to ensure the security of the networks in the context of congestion
management.
Furthermore, as stated in paragraph 2,
The safety, operational and planning standards used by transmission system operators shall
be made public. This publication shall include a general scheme for the calculation of the
total transfer capacity and the transmission reliability margin based upon the electrical
and physical realities of the network. Such scheme shall be subject to the approval of the
national regulatory authority.
In stating these obligations, paragraph 2 also introduces the notion of
"transfer capacity" which appears again in Paragraph 3:
Transmission system operators shall publish estimates of available transfer capacity for
each day, indicating any available capacity already reserved. These publications shall be
made at specified time intervals before the day of transport and shall include in any case
week-ahead and month-ahead estimates. The data published shall include a quantitative
indication of the expected reliability of the available capacity.
Loop flows, congestion and transfer capacities are cornerstones of the
draft Regulation. But they are of quite different nature. Loop flows and
congestion are physical realities irrespectively of their definition. Transfer
capacity is just the opposite. It is a construct that may only be loosely
related to physical and economic realities irrespectively of the effort made
to define it. Transfer capacity only exists insofar as it is defined to exist. But
the definition may be useless and even misleading. The draft Regulation
makes an important contribution to the achievement of a "real integrated
market" by introducing loop flows and recognizing their impact in congestion.
But it stops short of drawing the full conclusion of this first step.
Transfer capacity like incremental cost is a convenient but fundamentally
ambiguous concept.
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5.1.1. TSOs must publish information on transfercapacities
The grid creates externalities between market participants. These take the
form of loop flows. Article 2 of the draft Regulation recognizes these
externalities. A minimal requirement to tackle externalities is to provide
information about them. What information? Pollution, which is the most
widely discussed externality, can serve as a point of comparison. Environmentalists
provide key information on pollution by constructing climatic,
atmospheric pollution and river quality models. The aim of these models
is to assess how much antropogenic gas, S02 and Nox emissions or waste
water the ecological system can assimilate.
Paragraphs 1 and 2 of Article 5 require something similar from TSOs
namely to ascertain the injections and off-takes sustainable by the grid
and to indicate how one arrives at these figures. The capabilities of the
grid depend on "safety, operational and planning standards" as well as
on "transmission reliability margin". TSOs need therefore also document
these aspects. But paragraphs 2 and 3 say more: they demand that the
capability of the grid to accommodate injections and off-takes in different
zones be expressed in terms of transfer capacities (TCs).
Take the six-node/two-zone example to illustrate what is at stake. The
transfer capacity from zone I to II is meant to measure the maximal flow
of electricity that can go from the former to the latter. As shown on Figure
6, this obligates TSOs to implicitly construct a North-South representation
of the six-node network and to compute the maximal quantity of energy
that can reliably flow from North to South.
Consider now the more complex example of the six-node/four-zone
network. A representation of the network in terms of transfer capacity
demands that the TSOs construct an equivalent four node network such
as depicted on Figure 7 and assign figures of transfer capacities to the
pairs (I-III), (I-II), (III-IV), (III-II) and (II-IV) in both directions. Paragraph
2 subjects this computation to the review by national regulatory authorities.
Last, it obligates TSOs to publish transfer capacities each day and
estimates of these transfer capacities well in advance. It also requires "a
quantitative indication of the expected reliability of the available data".
Can all this be done with a reasonable degree of confidence? This raises
two questions. Can this be done at all? If yes, do TSOs have the incentive
to do it properly? We first turn to this latter point.
5.1.2. On TSOs incentives
First note that TSOs need information from one another in order to
compute transfer capacities. But data on each other's grid and operational
practice is a domain where the past may have left some asymmetry of
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Transfer capacity
On
5
A TC representati)n of the
4 ii six node/two zone example
Figure6. Transfer capacity for the six node/four zone example.
I I3
II III1 2
I IV
a TC representation of the
six node/four zone example
IV
Figure 7. Transfer capacity for the six node/four zone example.
information. TSOs may also be of various levels of sophistication. Last, the
current legislation permits the coexistence of different relations between
TSOs and the incumbent generators. All this would be irrelevant if TSOs
only worked for the common good. This is what ETSO assumes from
its members (ETSO 1999, pp. 4-5). But it is not a common economic
hypothesis.
We may alternatively consider the possibility that TSOs behave like
other economic agents, that is, that they pursue their own goals given the
incentives that they are subject to. There is little evidence that significant
attention was given to the design of proper TSOs' incentives. In any
case, the subject is poorly understood in the literature. Participants to the
Florence Regulatory Forum have recognized at least part of the danger
(and maybe much more) when they advised to construct a European load
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flow model. This construction may require the inception of a European
TSO, possibly only endowed with the limited but crucial responsibility to
assemble relevant network information. This European load flow model
would also allow one to check that the figures produced by the national
TSOs are consistent.
5.1.3. On transfercapacity
Does the draft Regulation set the right objective when it requires TSOs to
compute and publish transfer capacities? ETSO says both yes and no with
equal vigor. It first proposed to use transfer capacity in November 1999
(ETSO 1999). The organization advised at the time, "no better notion could
be worked out by TSOs, simple enough to be used by non-specialists".
But it also accompanied this statement with some caveat: "in many cases
they (Net transfer capacity or NTCs) may be a somewhat ambiguous
information ... to help market agents in managing the risk of transaction
curtailment, NTC publication could include indications on upper or
lower bounds, statistical uncertainty of published values and dependencies
on numerous factors such as other cross-border exchanges in other directions".
To be certain that users are sufficiently cautioned on the danger of
using transfer capacities (ETSO 2000a) gives a detailed explanation of the
difficulties of computing transfer capacities. Probably most astounding for
"non specialists" is the property that 100 Mw from zone I to zone II is not
necessarily equal to 100 Mw from zone I to zone II!! It may depend on
which TSO computed the 100 Mw (page 11 in ETSO 2000a).
The core of the difficulty raised by transfer capacities lies in the fact that
they do not obey usual arithmetic: "it makes no sense to add or subtract
the NTC values given in the NTC table, as each value corresponds to a
specific set of assumptions regarding power inputs and outputs" (p. 7 in
ETSO 2000a). Specifically, this means that 100 Mw from zone I to zone
II plus 100 Mw from zone I to zone II is not necessarily equal to 200
Mw from zone I to zone II. In the same way, 100 Mw from zone I to II
is not necessarily compensated by 100 Mw from zone II to I. The reason
of this strange behavior can be traced very easily. The use of the transfer
capacity depends on the precise origin and destination of the transactions.
ETSO (2000a, p. 5) states that "the resulting T(otal)TC- value ... is to
be interpreted as the expected maximum volume of generation that can be
wheeled through the interface between the two systems, which does not
lead to network constraints in either systems, if future network conditions
and especially generation scenarios were perfectly known in advance". Put
it in other ways, in order to compute the maximal use of the network, one
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needs to make assumptions on the use of the network!! This definition is
restated and elaborated in ETSO (2001a, p. 6).
Note with reference to the above discussion over congestion that ETSO,
in contrast with the draft Regulation, does not limit itself to constraints
on the interconnection; it also considers "network constraints in either
system". As the draft Regulation though, it computes TTC by seeking
limitations in transfers from zone to zone and hence also places a priority
of international transactions with respect to domestic ones. As argued
above, this thinking does not really look compatible with a "real integrated
single market" (the use of "wheeling" is a clear indication of the
underlying reasoning).
Notwithstanding the strange properties of transfer capacities, the draft
Regulation obligates TSOs to announce values of transfer capacities. It is
no surprise, but it should be illuminating, that ETSO wishes to refrain from
making any commercial commitment on services subject to such unusual
arithmetic. Why should then marketers trust a transmission concept that
TSOs do not trust themselves?
5.1.4. Transfercapacitiesmake sense in radialnetworks
Consider first the simple case of the North South example with perfectly
reliable lines. Marketers willing to inject in North and withdraw in South
need a certain amount of line capacity services from North to South.
Because lines are supposed perfectly reliable, the service can be firm. It is
also perfectly homogenous: 100 Mw of line capacity from North to South
for marketer A is the same as 100 Mw of line capacity from North to South
for marketer B and the sum of these services is 200 Mw. Transfer Capacity
is perfectly defined and obeys usual arithmetic. Referring to the words of
ETSO, it is not an "ambiguous information" and there is no need to caution
marketers about the dangers of using this information. TSOs are thus able
to define the total capacity every day and to perfectly predict their future
values. Trading these line capacities completes the market.
Reliability complicates things but keeps them manageable. Consider
the same North-South example and assume now that two lines of identical
capacities but subject to forced outages link the two zones. The TC
between the two zones remains well defined but is now contingent on line
failures. A marketer willing to trade 100 Mw from North to South can
no longer secure a firm 100 Mw capacity. But it may obtain alternatives.
The marketer can procure 100 Mw of capacity contingent on the state of
the network (this would be an unusual contract). Or it can purchase 100
Mw of transmission service North-South with different levels of priority
and pay accordingly. Another possibility is to get an insurance contract
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that pays some compensation in case the network or part of it is down.
This insurance contract can be replaced by a financial contract with payoff
depending on the electricity prices in North and South. Last, the marketer
can secure back-up incremental and decremental generation in both areas.
In short, 100 Mw of transfer capacity is no longer a well-defined service
but it can be completed by more complex services (such as 100 Mw from
North to South with first priority) that are well defined.
Contracts for contingent services associated with additional insurance
or financial contracts allow marketers to trade risk, something which is of
the essence in an uncertain environment. These contingent contracts also
obey standard arithmetic: a contract of high priority does not add up to a
contract of low priority, but two contracts of the same priority add up. As
a result, marketers are not given "indications on upper or lower bounds,
statistical uncertainty of published values and dependencies on numerous
factors such as other cross-border exchanges in other directions". They
are offered a set of contingent contracts that, if in sufficient number and
diversity, allow them to trade risk. Trading these contracts completes the
market.
Contingent services are common place and the trend is to tailor them
more and more to customers' needs. This may make life more difficult
for non-specialists but TSOs can train them (see for instance PJM training
material on http://www.pjm.com/). Every business requires some learning
and there is no reason why the complex electric commodity would be
an exception. This more intricate environment can be illustrated on a
truck example. Suppose that two marketers A and B want similar trucks
delivered at the same time. Assume that the manufacturing line is subject
to breakdown. Because of these failures, the manufacturer cannot commit
to deliver the trucks on a given date. But it can offer a contract that specifies
that it will temporarily supply a replacement vehicle in case the truck is
not delivered at the agreed date. Alternatively, truck rental companies may
provide that type of contract. These contracts allow one to trade risks and
complete the market.
In short, reliability complicates the task of the TSOs and of the
marketers but does no make it impossible. Transfer capacities are still
amenable to market operations. TSOs can no longer announce firm daily
transmission capacities and both TSOs and marketers have to deal with
risks. But there is nothing very special in this. There are plenty of services
that are not guaranteed and for which one creates insurance or hedging
instruments.
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TABLE II
TC as a function of the origin and destination ofthe cross border transaction.
1-6 1-4 1-5 2-6 2-4 2-5 3-6 3-4 3-5
288 320 360 360 355 320 320 355 355
5.1.5. Transfercapacitiesare ill defined in meshed networks
In contrast, loop flows make TCs truly ambiguous. In order to see this,
consider the six-node/two-zone problem. The TC between zones I and II
is no longer well defined as it depends on the pattern of loop flows. As
Table II illustrates, TC changes with the trades that it is meant to allow. In
ETSO's wording "The Total Transfer Capacity TTC, (that) is the maximum
exchange programme between two areas compatible with operational
security standards applicable at each system if future network conditions,
generations and load patterns were perfectly known in Advance" (ETSO
2001 a, p. 6).
This dependence ofTC on flows has important consequences. First note
that, in contrast with the two-node example, a marketer no longer uses a
transfer capacity from zone I to zone II. Marketer A who wants to trade
100 Mw from 1to 6 will have no use of 100 Mw from 2 to 5. Transmission
service from I to II is not what TSOs produce either. 100 Mw from 1to 6
and 100 Mw from 2 to 5 require different uses of the transmission network.
A TSO is not indifferent between both. Therefore, "1Mw transmission
capacity" from Ito II is not a physical transmission service whether for the
grid operator (the TSOs) or for the users (the marketers). If 100 Mw from
I to II is not the service produced and consumed, what is that service and
how will the market find its price and quantity?
There has been considerable controversy in the US on the subject
of congestion management (see the flow gate debate on http://www.
ksg.harvard.edulhepg/index.html and http://www.stoft.com/x/flowgate/).
But the recourse to transfer capacity is not a contender in those discussions
because it is a priori clear that it cannot solve the problem. The difficulty
introduced by TCs can be stated very simply: a TC market does not trade
the physical services that marketers use and TSOs produce. It trades something
else, namely a synthetic (derivative) transmission service (the TC)
without trading the underlying physical services (line uses or point to point
transmission services). It is like trading a stock index with varying weights
without trading the securities and not knowing the weights. The market is
incomplete. The truck example may again illustrate the situation.
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Suppose that two wheat marketers require trucks equipped with special
features. Marketer A wants a truck with features A while marketer B uses
a truck with features B. Would the truck producer promise delivery with
an ETSO like statement that in order "to help them in managing the risk of
not being delivered the truck they want, they will be given indications on
upper or lower bounds on the number of trucks with different features that
can be produced, statistical uncertainty of published values and dependencies
on numerous factors such as the amount of trucks of a certain
type that the company has to manufacture that year"? Would the production
plan simply record a demand for two trucks, ignoring the additional
features? If manufacturing and assembling features A and B only place
minor strains on the production facilities, the manufacturer may indeed
plan its production without bothering about features until the last moment.
It will carefully distinguish between features A and B otherwise. But in
any case, it will deliver a truck with features A to client A and features B
to client B.
How does this apply to transmission services? The principle is simple:
one need not worry about differentiating transmission services from 1
to 6 and from 2 to 5 if the transmission system is over-sized. Trading
transmission capacity will suffice. The market is incomplete but this
is not important. In contrast, the difference between the two transmission
services is crucial if the grid is tight. Neglecting this difference
and aggregating the two services into one makes market incompleteness
consequential. Unfortunately, cross border transmission capacities are
tight.
To sum up, paragraph 3 of Article 5 raises many important questions.
TSOs may indeed announce transfer capacities the day ahead, but this may
be of little relevance for the "real integrated single market". Most energy
transactions are planned well before the day ahead in a pure bilateral
system. And because TSOs may only have to give indicative values of TCs
before that time, one can expect that these transactions will suffer from the
uncertainty associated to the transmission capacities.
Is it possible to hedge these uncertainties? This would be too long to
argue here. But note that the uncertainties affecting TC values because
of loop flows are of a completely different type than those normally
encountered in financial or insurance markets. Specifically they are not the
consequences of equipment failure or weather variations. These uncertainties
arise because Kirchoff's laws prevent transmission capacities to be
exactly computed until the very moment the transactions that use them
take place.
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5.1.6. Transparencydoes not solve the problem, but itmay help uncover
it
TC is thus a central piece ofthe design ofthe real integrated market desired
by the EC, but it may also be its Achille's heel. The draft Regulation tries
to render the notion as acceptable as possible. Surely, it is necessary to
indicate how TC is computed. And it is also essential to revise the computation
often. This may be a burden but it is necessary. The problem is
that it might be far from sufficient. Transfer capacities is an economically
flawed notion when the grid is tight. The best one can hope for is that
the transparency recommended by the draft Regulation helps uncover this
logical flaw.
5.2. Article 6: Address Congestionwith Market BasedSolutions
Paragraphs 1and 2 are the core of Article 6. They state that
network congestion problems shall be addressed with non-discriminatory market based
solutions which give efficient economic signals to the market parties and transmission
system operators involved. Transaction curtailment procedures shall only be used in emergency
situations where the transmission system operator must act in an expeditious manner
and re-dispatching or counter-trading is not possible. Market actors which have been
allocated firm capacity shall be compensated for any curtailment of this firm capacity.
These paragraphs contain three key statements. We successively examine
each of them.
5.2.1. On the needfor market solutions
Market based congestion relief seems natural today. But this has not always
been the case. The first ETSO document on congestion management
(ETSO 1999) indeed considered a proposal that ruled access to transfer
capacities through priorities. The proposal was formally rejected and no
longer appears in the draft Regulation or in recent ETSO's documents. But
its underlying rationale is still present in the background. It may thus be
interesting to revisit this priority based congestion management proposal.
Our aim is not comprehensiveness or historical interest; but we believe that
the discussion may illustrate the nature of the non-market based reasoning
that still pervades, admittedly in much weaker form, current transmission
proposals. We exclude economic bid based rules from this discussion,
as these are true market solutions. We instead focus on rules like first
come first serve or proportional allocation, which are pure quantitative
instruments and do not contain any economic signal.
As argued above, the notion of transfer capacity embeds an incomplete
transmission market. We here claim that an allocation of transmission
capacity on the basis of priority rules is the most extreme case of this
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T1=30 T2 =20 T3 =30
T2=20 T3=10 T1 =20
200 200 200
Figure8. Allocation of TC through priority rules.
incompleteness: it creates an energy market with no market for transmission
services. To see this, consider the two-node example with perfectly
reliable lines. As argued before, transmission capacity is here a welldefined
economic resource. Marketers demand and TSOs supply reservations
of line capacity. Trading these line capacity reservations completes
the market. What if line capacity reservations are not traded but allocated
through priority rules? The market becomes incomplete. To get a
first insight into this situation, consider a sample of trade patterns on the
North-South example. Transactions TI, T2 and T3 (100 Mw each) respectively
have gross margins (before paying for transmission) of 30, 20 and
10 euros/Mwh. Figure 8 shows the transactions that obtain line capacity
reservation in each possible allocation of transmission capacities based on
priority rules.
All patterns are compatible with quantitative priority rules. But only
the one that gives the capacity of the line to the higher margin transactions
is the outcomeof an efficient operation of the power system. What
is the problem? Again, it is both simple and deep: marketer T3 wishes
to trade any transmission right that he/she would obtain from a priority
based rule with a marketer who does not have any capacity reservation
but makes a higher margin on his/her transaction. But the priority-based
system does not permit this trading and hence this arbitrage. Therefore,
the absence of arbitrage on the transmission market distorts competition
in the commodity market. In the parlance of the introduction, the market
is incomplete because the market for transmission services is missing.
As can be seen from these trade patterns, priority rules also introduce a
fundamental indeterminacy in the market. There is no way to tell who will
gain access. All outcomes are equally plausible. Only one is economically
efficient and compatible with the desired operation of a "real integrated
single market" but there is no way to insure that it will emerge from the
process. Note that power dispatchers would never have run their system
on the basis of priority rules in the days of regulation. But interestingly
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enough, the Californian restructuring force the ISO to use quantity-based
procedures to deal with congestion!
5.2.2. Auctions are a step in the good direction.Butjust one step
Priority based congestion management restricts spatial arbitrage. Alternative,
market based solutions are thus necessary. This is what paragraph I
of Article 6 acknowledges. Different methods initially introduced in ETSO
(1999) and later elaborated in various documents are summarized in the
appendix of the draft Regulation. The explicit auction of TCs is the first
market-based proposal in ETSO (1999). ETSO describes it in these terms
"Marketers bid for parts of the NTCs (recall that ETSO was referring to
Net Transmission Capacities)" "The bids are stacked, highest bid first, until
NTC is completely used". "A transmission market clearing price is calculated
and each participant pays this". "Once the TC is completely used,
either the process is stopped, or there is some re-dispatching, according to
the level of the clearing price and the process may go on with the extra
trade possibilities". TC auctions exist in various places at the time of this
writing (see ETSO 2001e, p. 14). We discuss the underlying principle on
our stylized networks.
Consider first auctioning the capacity of aperfectly reliable line joining
the two nodes of the North-South example. As argued in the introduction,
current technology does not allow for real time auctions of TCs.
By necessity, the auction is a forward market where marketers express
their valuation of the line capacity. Under ideal economic assumptions, the
outcome of this market is almost akin to a dispatch that operates generators
in economic order, subject to tie-line capacity constraints. But there is
one difference: the TC auction is a forward market while the dispatcher
operates in real time. Does a forward market perfectly substitute a real
time dispatch? No! As is well known demand and supply of electricity
is continuously and randomly changing over time. Deviations between
forward and real time transactions are almost inevitable. They need to
be handled in one way or another. Well articulated (complete) forward
contracts that specify recourse actions in response to deviations can play
that role. The design of such contracts has not been explored so far in
electricity. In any case, this seems too much beyond the current state of
discussion to be considered here. The inception of a balancing mechanism
that operates in real time is the only remaining solution. This mechanism
can be administratively managed (with penalties) or take the form of a spot
market. Neither the draft Regulation, nor the draft Directive foresees this
spot market. ETSO and CEER documents do not mention it either. Most
likely it is left to national discretion.
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Member States have different attitudes with respect to the creation
of a spot market. A sound interpretation of the principle of subsidiarity
would have required that the design of this real time market be decided at
European level (in this case ETSO level) and not be left to Member States.
This is not what happened. One may thus conjecture that administratively
determined penalties will rule deviations between forward and real time
transactions in many continental markets. But it is a spot energy and transmission
market that would best permit marketers to arbitrage between
the forward market and real time operations. An administrative balancing
system distorts the prices in the forward market because it construes
price expectations on administratively defined penalties. A forward TC
market without a real time balancing market, (or a set of well articulated
contracts on deviations) is thus an incomplete market, even in the twonode
example. Only when deviations in supply and demand between the
auction and real time do not exist, will the market be complete. What is
the problem? It is very similar to the one mentioned about priority based
allocation of transmission services: administratively regulated penalties in
real time, that is economically meaningless real time prices, limit or distort
marketer's arbitrage possibilities. But arbitrage is the driving force of the
"real integrated single market" in a bilateral system. It is that very essential
activity which is affected.
As argued above, line outages make transfer capacities more complex
but not impossible to manage through the market. Contingent transmission
services need to be defined to accommodate line failures. Additional
insurance or hedging contracts are also needed to complete the market.
This is doable but is foreseen neither in the draft Regulation nor in ETSO
proposals that only recommend that the definition of TCs "take reliability
into account". What is the underlying physical phenomenon? Contingencies
may change network resources in real time. This adds to the deviations
that develop between the closure of the forward market and real time
operations. This is not a new phenomenon but an enhancement of the
one that already results from demand randomness, as we just discussed.
It increases the recourse to adjustments and hence adds to the distorting
effect of an administratively organized balancing mechanism.
5.2.3. Can TC auctionswork in tight grids
Consider now a meshed network such as the six-node/two-zone example.
As argued before, TC is now an ambiguous notion. TCs cannot be defined
independently of the transactions that demand them. And because one
auctions TCs and not transaction dependent TCs there is no guarantee that
network resources will be granted to the transactions that value them most.
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In other words, the TC market might be in equilibrium without supply and
demand of network resources balancing.
To illustrate this point, suppose that the TSOs agreed on an overall TC
of 300 Mw from zone I to zone II (a value chosen between the max and
the min TCs found in Table H that reflects assumptions on "future network
conditions, generations and load pattern"). Assume two transactions A and
B respectively from 1 to 6 and from 2 to 5, both of 300 Mw, contending
for the transfer capacity. Transactions A and B are respectively valued at
30 euros/Mwh and 10 euros/Mwh. The equilibrium on the TC market is
to allocate 300 Mw to transaction A at a TC price of 30 euros/Mwh.
But this does not fit with the 288 Mw available for a transaction from
1 to 6. The equilibrium on the TC market is not an equilibrium for the
network resources because the demand and supply of these resources do
not balance. Revert now the assumption on the valuation of the transaction,
that is, assume A and B are respectively valued at 10 euros/Mwh and 30
euros/Mwh. The equilibrium of the TC market is to allocate 300 Mw to B
at aprice of 30 euros/Mwh. But this does not saturate the 320 Mw available
for transactions from 2 to 5. The price of transmission should thus be zero
and not 30 euros/Mwh. Again, the equilibrium on the TC market is not
an equilibrium of network resources because the price ofunused resources
is positive. In short, in no case is the equilibrium on the TC market an
equilibrium of the real network resources: either the quantities or the price
do not fit.
This mismatch can be interpreted in terms of the truck example.
Trading TCs is like trading trucks without special features even though
customers and production planning demand these features. There will be
a mismatch in the supply and demand of special features. How important
is the mismatch? It all depends on the capacity of the network. It is not
very serious if the network is over-sized. It may be overwhelming when
cross border trade possibilities are limited. ETSO is well aware of this
possible mismatch when it mentions in the reference to the conclusion of
the auction: "either the process is stopped or there is some re-dispatching
.. .". ETSO therefore recognizes the disequilibrium and suggests removing
it by re-dispatching. A similar concern appears in ETSO's discussion of
transactions involved in several congestions "as an example, transactions
could be handled through an optimal power flow ... This needs a strong
co-ordination between the TSOs involved." What does strong coordination
mean? We shall come back to that issue when discussing proposals 4 and
5 of ETSO (1999).
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5.2.4. In short: There are two flaws
A straight TC auction introduces two flaws (in the sense of missing or
incomplete markets) in the market design. One already appears in the
forward TC market. Except when the network is over-sized, the auction
does not guarantee that demand and supply of physical transmission
resources match. The demand and supply of TCs may balance but transfer
capacities are not physical network resources. Also, the price of TCs is
not the opportunity cost (and hence the economically meaningful price) of
the used network resources. Locational arbitrage is thus distorted. TCs are
claimed to simplify the work of marketers. The reality is that they prevent
them from properly arbitraging the commodity between different sources
and destinations. Worse, this limitation already appears in the forward
market where time is not a constraint for achieving full arbitrage. This
drawback is to be appreciated considering that marketers are key agents
in a bilateral organization of the market and the driving forces of the "real
integrated single market".
The second flaw derives from the absence of a balancing market that
relates energy and transmission in real time. Current restructuring indicates
that one will often have at best an administratively organized balancing
system. The consequences are twofold. First, there is no relation between
energy and transmission prices in real time because deviations are administratively
priced. This implies that real time energy prices in different
locations can be inconsistent in the sense that they allow for un-exploited
arbitrages. Second, these non-market based real time prices create inadequate
expectations in the forward market and hence further perturb its
operations. Again, this flaw distorts or limits the arbitraging activity of the
marketers.
To sum up, one is bound to find a discrepancy between the TCs
allocated by the auction and the real use of network resources (loop flows
effect). This discrepancy may be exacerbated by outages and deviations
between the forward market and real time operations (randomness effect).
Further discrepancies arise if different types of auctions are run in different
places at different times. This latter issue is recognized in ETSO (2001b).
These problems have been extensively discussed and elaborated in the
nodal vs. flow gate debate in the US. One cannot escape them and any
attempt to do so will backfire.
The claim that transfer capacities simplify the work of marketers is
misleading. True, marketers may find it difficult to simultaneously discover
prices on the transmission and energy markets because of their complex
interrelation. But doing away with physical realities is no simplification.
It is possible to bundle the energy and transmission markets and hence
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keep transmission prices integrated in the price of the commodity. This
is an implicit transmission market. It requires a nodal system, a solution
that is not envisaged in the Florence documents even though it exists both
in theory and in practice. Surely, leaving part of the price discovery to
a computer program restricts the role of the marketers. But this is more
benign than distorting price discovery by forcing an inadequate mechanism
on marketers on the ground that "it can be used by non specialists".
Alternatively, one may remove the need for the transmission market by
(possibly uneconomically) expanding the transmission capacities. To sum
up, a TC auction is a step in the good direction in the sense that it introduces
a transmission market. But it is just one step: because TCs are not
physical network resources, the transmission market fails to trade the real
resources offered by the grid.
5.2.5. Re-dispatch offers a remedy
The forward TC auction may thus lead to unbalances between supply and
demand of physical network resources. The resolution of the mismatch
may be left to the real time balancing mechanism. Alternatively, one
may try to already resolve part of it forward, using other instruments.
This alleviates the burden placed on the balancing mechanism and hence
improves the final outcome of the process: the less one resorts to an
administratively organized balancing system, the smaller real time operations
distort marketers' expectations. Is this possible?
ETSO suggests it is when it states, "either the process is stopped or
there is some re-dispatching . . .".The TSOs organization even goes further
when it states, "as an example, transactions could be handled through
an optimal power flow ... This needs a strong coordination between the
TSOs involved." This suggestion directly moves us into proposals 4 and
5 of ETSO (1999). We can indeed quickly dispose of market splitting,
which is proposition 3 in ETSO (1999) as it isjudged either too difficult to
implement in the near future (EC 2001a) or inadequate for strongly meshed
networks (ETSO 2001d). Proposals 4 and 5 have a dual role; they can be
seen as stand-alone congestion management methods or as complements
of the TC auction. In the language of the introduction, they complete the
forward market by reducing the unbalance between the supply and demand
of physical network resources that results from the sole auction of TCs.
Single zone re-dispatching
Single zone re-dispatching is the fourth congestion management method
proposed in ETSO (1999). The principle is to find resources (incremental
and decremental injections) in the "constrained TSO's own control area"
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necessary to relieve (part of the) congestion due to Cross Border Trade.
The concept is easily illustrated on the two stylized networks.
Take the North-South example first. Counter-trading requires TSOs to
change their dispatch in North and South respectively while keeping export
and import from these nodes unchanged. This is clearly impossible. The
method is thus inoperative in this example. But it can work in a meshed
network. Consider the six node/two zone example and assume the same
transactions as in section 4.1.3), namely 1000 Mw from nodes 1 to 3 in
zone I, 1000 Mw from nodes 4 to 6 in zone II and 100 Mw from node 1
in zone I to node 6 in zone II. Suppose that TSOs assert again a Transfer
Capacity of 300 Mw from zone I to zone II. The above transactions are
compatible with the transfer capacity. Indeed, by definition none of the
domestic transactions require TCs from I to II and the international transaction
only demands 100 Mw, well below the 300 Mw announced in the
auction. But loop flows entail a load of 187.5 Mw on line (1-6) therefore
creating a congestion on that line. Counter-trading allows TSO to remove
this congestion by re-dispatching 60 Mw (7.5/(PDF(1-6)1 - PDF (1-6)2))
between nodes 1 and 2 (recall that, except when stated otherwise, generation
is located at nodes 1, 2 and 4). The resulting shift of 7.5 Mw from
line (1-6) to line (2-5) removes the congestion. The re-dispatch does not
change the total energy transferred from zone I to zone H but it makes it
compatible with the thermal constraints of the lines.
Counter-trading induces a re-dispatching cost of 600 euros (obtained as
60*(20 - 10); recall from Section 3.2 that marginal generation costs are
assumed to be 10, 20 and 30 euros/Mwh at nodes 1, 2 and 4 respectively).
Re-dispatching costs are well recognized by ETSO. The organization
suggests allocating these costs to those agents responsible for them namely
"i.e. market players involved in extra cross-border transaction". This is in
line with the definition of congestion in the draft Regulation that attributes
congestion on the interconnection to international transactions. In the
example, the reasoning leads to allocate the whole re-dispatching cost
to the sole international transaction even though the three transactions
contribute to exactly the same flow (62.5 Mw) on the congested line.
Attributing the cost of re-dispatching to international trade gives domestic
transactions all property rights on inter-ties, an assumption that is hardly
compatible with the "real integrated single market".
As argued above, one can also and equally arbitrarily contend that
the loop flows induced by the domestic transactions are at the origin of
the congestion. Socializing re-dispatching costs over all marketers is an
alternative to assigning them to some transactions arbitrarily defined as
responsible for the congestion. ETSO rightfully recognizes that socializing
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re-dispatching costs eliminates any price signal (it gives the right price
signal in the example but this is fortuitous). There is unfortunately no alternative
to the dilemma as long as one does not consider nodal pricing. One
shall either arbitrarily assign responsibility of congestion costs to certain
transactions or socialize them over all transactions. The price signal is
meaningless if not misleading in the first case; it is absent in the second
one. This is hardly a market solution!
But something can hopefully be made of single zone re-dispatching
if and when combined with TC auctions. As argued above, TCs do not
correctly describe physical network resources. But they should at least
provide some information about them. If so, a TC auction would not necessarily
eliminate bottlenecks but it may reduce them. One can thus hope
to arrive at smaller re-dispatching costs after the auction is completed.
Combining both tools may thus be a reasonable idea. Will it work? We
do not know. It does not work in this example where the auction does not
ration the use of network resources: one offers 300 Mw of TCs and the
demand for them is only 100 Mw. A mix of market splitting and countertrading
works in the mildly meshed grid of the Nordic system (see ETSO
2001d). The sole re-dispatching did not work in PECO (Hogan 1999) and
certainly not in the predefined zones of California. There is thus some hope
but no certainty. In any case, the simple two-node North-South example
illustrates one potential cause of failure ofpure re-dispatching: the method
can become awfully costly, if not totally inoperative, when re-dispatching
resources are scarce.
Crossbordercountertradingor coordinatedre-dispatching(CCR)
Cross border counter-trading is the fifth proposition of ETSO (1999). It
extends the previous approach to re-dispatching across border constraints.
The name counter-trading comes from the possibility offered to TSOs
to buy congestion relief from one another. Coordinated re-dispatching
aims at the same result, without resorting to markets, but relying instead
on coordinated actions of the TSOs. The rationale for extending redispatching
to cross-border counter-trading or re-dispatching is immediate:
it facilitates the removal of congestion.
Take the North-South example: it is impossible to relieve congestion by
having each TSO re-dispatch in its own control area. Cross-border countertrading
makes this possible. It has also implications in meshed networks.
Consider again the six-node/two-zone example and the transactions of
section 4.1.3 (1000 Mw from nodes I to 3 in zone I, 1000 Mw from nodes
4 to 6 in zone II and 100 Mw from node I in zone I to node 6 in zone II).
As indicated in that section, this trade pattern leads to an excess flow of 7.5
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Mw in line (1-6). Re-dispatching 60 Mw from node 1to 2 in the same zone
can remove this congestion at a cost of 600 euros. Cross-border countertrading
achieves the same result by trading 13.3 Mw (7.5/(PDF(1- 6)1 PDF(1-6)4))
between generators 1and 4 at a cost of 266.6 euros (obtained
as 13.3*(30 - 10)).
Cross-border counter-trading may also drastically increase TCs. But
there remain two difficulties. One is directly carried over from single-zone
re-dispatching: what should one do with the cost? ETSO (1999) proposes,
"the cost of CCR should be allocated to the market participants responsible
for the bottleneck". This is the same, in principle sound but in practice
inapplicable, recommendation as in single zone re-dispatching. All transactions
that induce a flow on some line are responsible for the bottleneck
and any attempt to assign this responsibility to one or another agent is
arbitrary. If cross-border counter-trading sufficiently increases TCs at a
small cost, then "allocating" these costs to all participants is fine. But
cross-border counter-trading, very much like single zone counter-trading,
may induce perverse incentives to create congestion in order to be called
upon to relieve it (Hogan 1999). Gaming or genuine transmission limitations
may render the method devastating if the cost of counter-trading
is high and socialized over all participants. The second difficulty is to
organize trade between TSOs (see Cadwalader et al. 1999). This may
require considerable organizational work. The issue is not alluded to in
the Florence documents.
Re-dispatching and counter-trading, whether operated on their own
or in combination with a TC auction, have an interesting property. In
contrast with TCs that need to be defined before real time, counter-trading
can be operated both forward and in real time. Securing re-dispatching
resources is like procuring an option traded in the forward market and exercised
in real time. Because of this character of option, re-dispatching and
counter-trading, in contrast with TCs may have the potential of organizing
a complete market. Needless to say, this is only possible with a real
time market, that is a balancing market. None of the Florence documents
provides any clue as to whether this interesting property will be explored
or taken advantage of.
This persisting invocation of a missing balancing market suggests the
following remark. The allocation of costs to those responsible for them
is a recurrent theme in the Florence documents but no viable proposal is
offered to perform this allocation. It is suggested that the creation of a
spot market and the settlement of congestion costs on the basis of these
spot prices is the only way to allocate costs without being discriminatory.
Any other solution is arbitrary, inefficient and possibly prone to gaming
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especially if re-dispatching resources are scarce. Also, do not count on
administrative intrusion for increasing re-dispatching resources. It can only
create regulatory uncertainty and reduce agents' incentive to enter and play
the market in an economic sound way.
5.2.6. Curtailmentremainspossible
Paragraph 2 of Article 6 addresses curtailments
Transaction curtailment procedures shall only be used in emergency situations where the
transmission system operator must act in an expeditious manner and re-dispatching is not
possible.
Emergency situations are a fact of life. But the power system should
not live in a continuous state of emergency. Can the "real integrated
single market" suffer from curtailments? Yes! Specifically, curtailment will
happen whenever there is a mismatch between the supply and demand of
transmission resources in the forward market and this mismatch cannot be
resolved by counter-trading whether single-zone or cross-border. Curtailment
also happens whenever deviations between the forward market and
real time transactions are too large to be accommodated by the balancing
mechanism.
Why would these outcomes ever occur? As argued above, the forward
TC market is inherently incomplete because transfer capacities do not
reflect the intricacies of meshed networks. The end result is an unbalance
between the supply and demand of network resources in the forward
market. Were it not for recourse actions this would already imply curtailment.
We also argued that deviations between the closure of the forward
TC market and real time transactions are inevitable. This may further
increase the imbalance between supply and demand of network resources
and hence the risk of curtailment. Load relief resources callable in real time
mitigate but do not eliminate those risks. Curtailment eventually occurs
when there is not enough load relief resources to resolve the sum of these
unbalances. Can this happen? Yes, it suffices that the incentives to provide
the load relief resources are too low. Worse, as extensively argued by
Chandley and Hogan (2000) in the Californian case, there may sometimes
be incentives not to provide load relief resources. Whether this will be so
in the European system is difficult to appraise without knowing the details
of the implementation (see article 7 and the questions that remain to be
solved). But some general principles can be given.
Load relief resources can be procured by intrusive measures or proper
remuneration. Intrusive measures may work in the short run. They create
unbearable regulatory uncertainty and destroy the market in the long run.
What about remuneration? First note that some plants can serve the energy,
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congestion relief and balancing markets. The remuneration obtained in
each of them determines the allocation of their capacity between these
markets. Do we have the adequate mechanisms to do this arbitrage? This
does not look so. Consider first congestion relief. An adequate remuneration
mechanism requires to charge those who are responsible for the
recourse to those services (those who create congestion) and to remunerate
those who provide them. This can be done with a spot market but is difficult
otherwise. Specifically, allocating re-dispatching costs to those responsible
for congestion is hopeless as long as there is no locational spot market.
The best one can hope for is to spread the costs on all agents. But one
may be wary of the result. Agents that cause large congestions in some
location but are only charged an average congestion cost have no incentive
to reduce their troublesome transactions. Similarly, those which provide
valuable congestion relief services while at the same time having to pay
some average congestion costs have little incentive to make these services
available. This creates a mismatch between the supply and demand of
congestion relief services that comes on top of the mismatch between
demand and supply of network services. This is a source of curtailment.
Gaming further adds to the problem but is not discussed in this paper.
Balancing services are no better. Prices charged for deviations are here
the key element. A spot market should give the right signal to more or less
extensively rely on the balancing market but administratively determined
penalties do not. Low deviation penalties entail an excessive demand for
balancing services compared to the supply. This leads to curtailments.
Too high penalties unduly increase the price of unbalances and hence
uneconomically reduce them. At least, this does not induce curtailment.
Whether these outcomes will materialize remains to be seen. It all depends
on the fine details of the system and we know nothing about these fine
details yet. But PECO and California show that these bad outcomes are
not only mental experiments: they happen.
5.2.7. Curtailmentsshallbe compensated
The last sentence of paragraph 2 states that
Market actors which have been allocated firm capacity shall be compensated for any
curtailment of this firm capacity.
Compensating curtailments is in line with economic reasoning. But it
immediately raises the question as to how curtailment will be organized
and the compensation computed. In other words, does one have the means
to curtail firm TCs in an economic sound way and offer a market-based
compensation for curtailment? Or will this be administratively organized?
By definition, re-dispatch will have exploited whatever economic curtail-
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ment possibility is available (decrementable load). One must conclude that
real time unforeseen curtailment will be administratively managed. But
one cannot probably hope for anything better. The key question is then,
how will it be compensated?
It is impossible to compute a market based compensation without real
time prices and hence a balancing market. The compensation will thus
be administratively computed. This is akin to administratively pricing
balancing services. Both introduce inconsistent prices in the real time
market and hence distort expectations in the forward market. This has
an impact. Inadequately compensated curtailments and inadequate balancing
prices (most likely regulated prices) concur to distort the arbitrage
activity of the marketers. TCs and the absence of balancing market may
ease marketers' life if there is no curtailment. But they may make it
miserable if curtailments are frequent and improperly compensated. The
end result is predictable: trade that is curtailed too often and improperly
compensated will decrease. This will solve the congestionproblem
but not in the sense intended by the European Commission: quantitative
non-economically based restrictions combined with administratively
determined compensations are incompatible with a "real integrated single
market".
5.2.8. TSOs will maximize the amount ofTCs on the market
Paragraph 3 states that
The maximum capacity of the inter-connectors shall be made available to market operators,
complying with safety standards of secure network operation.
It is not clear that TSOs have an incentive to maximize the capacity of
the inter-connectors. TSOs are likely to be regulated as not for profit
organizations while being liable in case of failure to deliver the promised
TCs. Declaring inter-connector capacity available implies risks if one
is compelled to compensate for it when it fails to be there. TSOs can
admittedly be held liable for line failures that decrease the available
capacity. But they cannot reasonably be held responsible for modifications
of transactions that change transfer capacity.
In consequence, one can probably induce TSOs to undertake the right
maintenance in order to optimize TCs with respect to line failures. But
one cannot design incentives for maximizing TCs contingent on the loop
flows effects and hence on marketers' transactions. TSOs who are required
to pay compensations in case of curtailment, will reserve part of line
capacities and procure ancillary services to guarantee these TCs. They may
indeed have strong incentives to stay on the safe side, offer little TCs and
possibly use intrusive means to reserve load relief resources. Alternatively,
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EUROPEAN ELECTRICITY MARKET
but more or less equivalently, they can make TCs available at the last
moment, with the result that it is impossible for marketers to conclude
long-term contracts on the energy market. None of this will maximize TCs.
ETSO (2001f, p. 4) is obviously well aware of these questions when it
announces "a compensation of market participants would force TSOs to
keep up higher security margins that consequently would decrease market
liquidity".
5.2.9. Otherparagraphsare less worrisome
The other paragraphs of Article 6 raise fewer questions even though they
would deserve a more extensive discussion than allowed in this paper.
Paragraph 4 imposes that
Any allocated firm capacity that will not be used, shall be reattributed to the market.
This prevents holders of transmission capacity to withhold it from the
market therefore exerting market power. This subject is extensively
discussed in the literature, particularly by Joskow and Tirole (2000).
Paragraph 5 requires that
Transmission system operators shall, as far as possible, net the capacity requirements of
any power flows in opposite direction over the congested interconnection line in order to
use this line to its maximum capacity. In any event, transactions that relieve the congestion
shall never be denied.
This may create difficulties (see ETSO 2001f, p. 4) but it is a direct
consequence of the requirement to maximize the amount of TCs.
The last paragraph 6
Any rents resulting for the allocation of interconnection capacities shall be used for .. .:(a)
guaranteeing the firmness of the allocated capacity, (b) network investments, (c) reduction
of network charges. These rents ... shall not constitute a source of extra profit to the
transmission system operators.
confirms the suggestion that the TSOs are likely to be operated as not
for profit organizations. It eliminates the long run incentive of the TSOs
to restrict transmission capacities in order to increase rents. But it also
eliminates the short run incentive to maximize TCs.
6. THE OTHER ARTICLES
Articles 5 and 6 go in the right direction. But they will not suffice to the
task. An important question is whether one can be satisfied with the principles
as currently stated or whether one should attempt to push them to
their logical conclusion. Just think of the consequences of a Court insisting
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that compensation of curtailment be market based because compensation
is part of the congestion management and that this latter should be
market based. This could have far reaching consequences. It could force
the introduction of a balancing market in order to allow for market-based
compensation. This would in turn open the way to other systems of congestion
management not currently discussed in the Florence documents.
Deduction has considerable power. Also, one can deduct before the facts
and hence take advantage of the delay imposed by the Stockholm meeting
of the Council. One can also deduct after the facts when complaints are
brought to Court and damage is done. In both cases, deduction will move
us beyond the current proposals.
Article 7 gives some mixed encouragement in this respect. It recognizes
that the process is far from finished. It lists open questions that need to be
sorted out such as "details of the determination of the transmission system
operators liable to pay compensation for transit flows .. .", "details of
methodologies to determine the amount of transit hosted and export/import
of electricity made, . . .", "details of the methodology to determine the costs
incurred as a result of hosting transit of electricity, . .. ", "the participation
of national systems which are interconnected through direct current
lines .. .". Some of these questions, if treated rigorously, should entail
significant advances in the reasoning.
With regard to national tariffs, Article 8 also states that
national regulatory authorities shall insure that national tariffs and methodologies of
congestion management are set and applied in accordance with this regulation ...
This may also have potentially far reaching consequences if the management
of congestion of interconnection is truly market-based.
In contrast one may be skeptical about the virtues of the "comitologie"
mentioned in the explanatory memorandum of the draft Regulation.
Committees perform quite differently depending on whether they are
in charge of finding a solution to technical and economic problems or
achieving a political consensus by playing down these difficulties. In any
case ETSO expresses concerns (ETSO 2001f) about not being represented
in the "regulatory Committee": "The potential lack of high level technical
expertise may also lead to inefficient or even dangerous politically driven
decisions for the operations of the European electrical system". More
directly to the point ETSO demands that "appropriate dispute mechanisms
are put in place and that the liabilities of the Commission, Regulators and
transmission systems operators are appropriately defined for each Member
State".
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EUROPEAN ELECTRICITY MARKET
7. CONCLUSION
The EC, supported by the participants to the Florence Regulatory Forum,
is currently proposing principles for organizing cross border transmission.
These are important steps that go in the right direction. But they fall short
of a full market design. The proposed system is far from handling the
constraints of the transmission systems in general and of cross border
capacities in particular. In economic parlance, these markets are too incomplete.
But even so, it is of the essence to move ahead and to start thinking
about the full consequences of these principles.
Specifically, ETSO should start working in terms of incremental cost
and drop allocated costs that cannot send any meaningful price signal.
This is technically (conceptually and computationally) burdensome. And
maybe working with incremental cost will turn out too difficult of even
impossible. If so, one should report why and move to another concept
or simplification. In all cases, one should avoid pretending to do something
that one does not do: markets respond to real not intended price
signals. The auction of Transfer Capacity provides a market mechanism
for allocating interconnections. But it is not sufficient for dealing
with loop flows, contingencies and deviations from the forward market.
Cross-border counter-trading provides the adequate technological basis
to resolve the residual mismatch. But it should be cast in a proper
market framework. This may lead to a nodal price system, a notion
that is conspicuously absent from the Florence documents. In general
the language of the Florence Regulatory Forum appears much too soft.
However, systematically exploring the consequences of a combination of
TCs and cross-border counter-trading or re-dispatching and keeping the
logical consequences of a "real integrated single market" in mind can
produce significant results.
But before being developed, the principles should not be further
weakened during the legislative process. Specifically, the now common but
misleading interpretation of subsidiarity that wants to leave controversial
issues to Member States has been often invoked in the Florence Regulatory
Forum, fortunately not always with success. National artifacts do not
complete an incomplete market. This is especially true in an interconnected
electricity system where the very meaning of subsidiarity mandates a high
level of market harmonization. This is why, before thinking of strengthening
the language, it is necessary to ascertain that the discussion of the
draft Regulation in the Council and the Parliament does not water the
current document into a set of useless if not dangerous statements. Even
if the prospects look reasonable there are reasons to be worried. In this
respect, the introduction of the reference to "international" transactions in
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the definition of congestion of Article 2, compared to previous versions
of the draft Directive is certainly worrisome. The difference between the
current version of the draft regulation and what will ultimately come out
of the institutional EU process will be a strong indication on how serious
one is about implementing a "real integrated single market".
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