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C. SECOND PHASE OF THE SECTOR INQUIRY
a. RESULTS OF THE PUBLIC CONSULTATION
I. Gas
Introduction
(618)Out of the 60 responses to the public consultation, 36 respondents commented on the gas
part of the Preliminary Report. The range of organisations responding on gas included
vertically integrated gas suppliers, new entrants, national regulators and competition
authorities, consultancies and law firms, energy traders, transmission and distribution
system operators, customers, industry associations and national government agencies.
(619)These organisations commented both on pan-EU problems as well as Member State
specific issues. Some respondents focused only on the Member State in which they had
their main operations, whilst others commented on their efforts to expand operations into
other Member States. Respondents were mainly based in the EU although comments also
came from a non-EU company with close ties to the EU market.
(620)The vast majority of the respondents to the Gas Sector Inquiry welcomed the report and
its findings. There was broad agreement with the analysis presented in the report. Where
views were divergent, the focus was rather on the best way forward rather than on the
analysis itself.
(621)In particular, views on structural unbundling varied. Incumbent gas companies argued
against such an approach, whilst other types of respondents tended to be favourable. Out
of all the respondents on the section dealing with gas, more were in favour of structural
unbundling than were against it, while many did not declare a definitive position on this
issue.
(622)The comments received on each chapter in the Preliminary Report (i.e. Concentration,
Vertical foreclosure, Market Integration, Transparency, Prices) are reviewed in the
sections below. Where respondents chose to comment on specific issues, their comments
are discussed under the most relevant chapter heading.
Concentration
(623)The majority of respondents agree that EU markets are highly concentrated. Broadly
speaking non-incumbent respondents tend to see this as a serious problem which leads to
higher prices and market foreclosure. These companies were particularly critical of the
levels of market dominance in wholesale and retail markets in a number of Member
States. They expressed the view that, due to the ongoing dominance of incumbents, new
entrants will continue to find it difficult to enter many EU markets, even with full
implementation of the existing legislation.
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(624)Many respondents outlined their experiences of how high levels of concentration were
detrimental. For example, new entrants emphasised that they had problems getting access
to gas noting that incumbents appear to be reluctant to trade, even in circumstances where
it is clear they have "spare" gas.
(625)New entrants and customers also cited other barriers to entering the gas market including
difficulty of getting access to network capacity, storage capacity and conversion capacity.
There are also criticisms that existing dominance is frequently exacerbated by political
benevolence and intervention in support of 'national champions'. Respondents also noted
that rising wholesale prices have significantly enhanced the market power of incumbents.
(626)By contrast, vertically integrated incumbents tended to argue that there is a need for a
limited number of strong market players in order to deal with the high level of
concentration of gas producers outside the European Union as well as the financial risks
in gas trading and the necessity for high investment in infrastructure. Incumbents take the
view that concentration in itself is not the problem and that, in any case, market
integration will alleviate concentration in national markets. They argued that the full
implementation of the Directives and the additional transparency requirements in the Gas
Regulation will go a long way to creating effective competition318
.
(627)Gas hubs were generally welcomed as a valuable potential source of liquidity which
should enable new entrants to get access to gas more easily. However, respondents
highlighted problems with low levels of liquidity on the hubs, as well as problems in
getting access to hubs in terms of access to transport capacity to and from, and between
hubs. Incumbents expressed the view that prices on new gas hubs are, however, too short
term to provide indicators for new investment and that new players seem reluctant to
'assume a part of the investment risk' by entering into long-term transit contracts. They
also noted that obliging parties to trade on hubs may lead to hubs being dominated by the
same players and so discourage entry.
Regarding suggested remedies the following comments and proposals were made:
(628)Most respondents were fully supportive of the Commission’s intention to launch
individual anti-trust investigations. Some were concerned about possibly anticompetitive
behaviour by dominant undertakings such as cross subsidies and potentially
predatory behaviour. It was also noted that more co-operation between National
Competition Authorities and regulators would help to identify market power abuses. A
focus on the compatibility of down-stream long-term contracts with competition law was
also generally supported.
(629)Meticulous scrutiny of mergers was advocated in many responses. Respondents called
for structural remedies to merger cases and for steps to promote liquidity through
obligatory trading on hubs and gas release programmes (i.e. imposed auctions of parts of
contracted volumes bought under long-term import contracts).
318
One vertically integrated incumbent argued that Germany is less concentrated than other Member States and that
there is a lot of potential for competition. By contrast, customers and new entrants in Germany are highly critical of
the current market structure and complain that the high degree of concentration in Germany combined with the
existence of long-term contracts is highly problematic for them. From their view-point, national / regional dominant
positions still exist.
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(630)Gas release programmes, as a potential remedy to market concentration in merger
proceedings and other antitrust and regulatory proceedings, received particular attention.
Incumbents and producers tended to be against the use of gas release programmes, except
in some merger situations. They considered that such programmes are a serious breach of
the principle of legal certainty, have negative effects on security of supply and would
decrease incentives for investment. They also noted that in so far as suppliers have
obligations to end-customers, they cannot rely on winning an auction for getting access to
gas supplies. They also argued that gas release programmes may not have the required
effect on liquidity in national markets as the gas released may be exported from the
Member State where it is supposed to create more liquidity.
(631)Other respondents, including customers and entrants, were more positive about gas
release programmes. Customers considered them to be a good way to overcome market
concentration and support their more general use. Other respondents considered that gas
release programmes can be an effective method to make gas available for new entrants,
especially when the downstream market is dominated by one or a few players. However,
there were many calls for proper terms and conditions when applying gas release
programmes to ensure that markets are created with sufficient liquidity. Some
respondents considered that, so far, existing gas release programmes had not delivered
fully competitive markets and that such programmes must be combined with access to
networks (e.g. by capacity release) as well as access to storage, flexibility and suitable
balancing services. Suggestions were made that gas release “tranches” should vary in
terms of size, duration (including short duration lots) and location, and that auctions
should be carefully designed and implemented to prevent incumbents deterring entry by
third parties.
(632)It was furthermore suggested that the effect of market concentration could be reduced by
promotion of liquid trading, e.g. through an obligation to make the unused flexibility of
existing long-term contracts (or a percentage of new long-term contracts) available to the
wholesale market on hubs. Moreover a system of Hub to Hub trading (a European Title
Transfer Facility) might be considered. Other proposed remedies to high concentration
included asymmetric regulation for dominant companies in order to facilitate market
entry as well as market share caps to establish liquidity. Respondents also proposed caps
for long-term cross border capacity contracts. These should be limited in volume and
duration which would lead to more integration of markets at EU level and thereby reduce
concentration. Generally, in order to facilitate market entry, effective secondary markets
for trading gas and capacity were called for by some respondents.
(633)Finally, deeper and more effective unbundling was frequently suggested as a remedy to
high concentration since it would be likely to bring about more effective integration of
the European gas market and reduce the significance of any individual market participant.
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Vertical foreclosure
Long-term contracts and Take or Pay Agreements
(634)Many respondents commented on the role of long-term contracts between producers and
suppliers and their effect on investment incentives. Most respondents were in favour of a
stable framework for investments in new infrastructure. In this context, historical gas
market players, including producers and suppliers, strongly favoured the continuation of
long-term contracts, whilst entrants and customers were concerned that these contracts
can foreclose the market.
(635)Historical gas producers and suppliers argued that long-term contracts are fundamental to
the EU gas market. Although some acknowledged that there is a role for short-term
business in the gas market, they maintained that the gas business in Europe is
fundamentally orientated to long-term arrangements, especially given the increased
dependence on imports. They argued that long-term contracts limit the risk for investors
in gas infrastructure (transit, transmission, storage and LNG) and enhance security of
supply. Others expressed the view that undermining existing contracts would breach
existing property rights and hence reduce incentives to invest.
(636)One incumbent gas company considered that long-term contracts encourage external gas
producers to supply to the EU rather than other countries. They argued that, without longterm
contracts, external producers could more easily manipulate wholesale market prices.
In their view the current framework allows customers to benefit from more reliable and
stable supplies.
(637)By contrast other respondents agreed with the preliminary Sector Inquiry findings that a
network of long-term contracts forecloses the market and that there is a lack of effective
congestion management on pipelines where such contracts exist. They, therefore, argued
that the awarding of long-term contracts should be rigorously monitored and that, in any
case, strict use-it-or-lose-it (UIOLI) conditions must be applied. They called on the
Commission to make clear that legacy contracts are not exempt from the provisions of
the Gas Directive relating to regulated third party access. However they also accepted
that long-term contracts do play an important role in investment decisions. They
concluded that the Commission should issue guidance on this subject in order to dispel
uncertainty and encourage investment.
(638)Other respondents considered that long-term contracts are acceptable in the upstream
segment, to underpin investments, but share the Commission's concern at the existence of
such contracts in the transmission network and at downstream level.
(639)Regarding the take-or-pay obligations, which constitute a characteristic feature of
upstream long-term contracts, one vertically integrated gas market player argued that
such flexibility is a necessary part of their long-term contracts since it takes into account
the volume risk taken by them as a buyer and provides them with an alternative source of
flexibility to balance their portfolio. Contrary to this view, entrants noted that take-or-pay
obligations effectively internalise the role of wholesale markets in managing price and
volume risks with the harmful consequence of impeding the development of more
effective and efficient wholesale markets. They argued that liquid wholesale markets
would obviate the need for such flexibility clauses since the market could then be used to
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hedge the price exposures and provide flexibility to match customers’ and suppliers’
evolving requirements.
Vertical integration of supply and infrastructure
(640)Many respondents’ comments chime with the analysis in the Preliminary Report. Entrants
and customers described problems experienced with regard to vertical foreclosure.
Customers, in particular, are clearly concerned about the market position and influence of
vertically integrated incumbent companies. They are concerned that TSOs favour their
own supply businesses and particularly that long-term contracts between TSOs and their
affiliates are allowed to effectively dominate capacity on transport pipelines making
market entry difficult. Energy intensive industries also made the point that they need to
access producers and suppliers directly on a transparent market basis.
(641)Entrants are particularly concerned about what they consider to be serious anti-trust and
regulatory issues in several areas: access to gas infrastructure (transit, transmission and
storage); lack of transparency; and lack of effective anti-hoarding measures (secondary
trading and UIOLI). They noted that non-discriminatory open access to transit capacity
and other infrastructure (i.e. gas storage) is vital if the ultimate goal of a single European
energy market is to be realised. Concern was expressed that the market structure suffers
from systematic conflicts of interest resulting from vertical integration.
(642)Regulators [CEER] also identified insufficient unbundling as a major impediment to the
development of competitive markets.
(643)By contrast vertically integrated incumbents appear to be satisfied with the current
situation or point to expected improvements as new laws and rules on access,
transparency and legal unbundling bed in.
(644)Regarding suggested remedies, there was, on the one hand, general support for
competition law remedies especially in cases of discrimination by dominant companies.
(645)On the other hand, the discussion strongly focussed on the regulatory situation and the
need for additional regulatory measures. There was a lively discussion of the level and
effectiveness of the implementation of the Directive and many suggestions indicated that
there is a lot more to be done. A call for more effective regulation was generally
supported. There was vivid discussion of the pros and cons of regulated versus
negotiated third party access to LNG terminals, transit and transportation pipelines
and storage. In this context, regulators acknowledged the need for regulatory certainty
for continued investment in the sector but agreed that 'grandfathered' access rights
under contracts signed before the Second Gas Directive319
and the Gas Regulation320
are
in many cases preventing development of competition. Regulators suggested guidelines
to clarify responsibilities of long-term capacity holders.
(646)Many respondents argued for more powers to national regulators and strengthening of
their independence. There was concern that many national authorities choose to
implement only the minimum requirements of the Directives. One respondent
319
Directive 2003/55/EC of 26 June 2003 concerning common rules for the internal market in natural gas
(OJ 2003 L 176/57).
320
Regulation (EC) No 1775/2005 of 28 September 2005 on conditions for access to the natural gas transmission
networks (OJ 2005 L 289/1).
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commented that many national regulators do not have the resources, competence, powers
or the willingness to change the market. These respondents called for more legislation to
increase the powers of national regulators, especially so they can implement the ERGEG
Regional Initiatives. There was also concern that decisions are often reached in a nontransparent
& non-accountable manner. Risks that independence of national regulators
would be curtailed by national laws were also highlighted. Views on the need for a
European Regulator were split. German incumbents considered that ERGEG and CEER
are sufficient. By contrast, some entrants argued that a pan-European grid code and/or a
European regulator would facilitate required consistency and coordination for crossborder
regulation.
(647)Some respondents were cautious about extending regulation provided that effective
competition was developing well. They noted that regulation could be used as an
important tool in areas where competition for various reasons has not yet developed but
once competition takes off regulation should be gradually softened or removed. This
argument was set out in particular in view of the UK market.
(648)A large number of respondents commented on unbundling and the discussion very much
focussed on the issue of ownership/structural unbundling. There was widespread
consensus among respondents that effective unbundling is essential for fair and nondiscriminatory
access to networks.
(649)The majority of respondents to the gas Sector Inquiry were in favour of full structural
unbundling. However, there were a range of views expressed from those strongly against
full structural unbundling to those strongly in favour.
(650)Vertically integrated incumbent gas companies tended to be against full structural
unbundling and argued rather for the full and effective implementation of legal
unbundling. In their view, full structural unbundling is not necessary to ensure effective
competition is delivered across Europe. Some noted that there is no legal basis, at
present, for ownership unbundling. It was also argued that it is not empirically proven
that ownership unbundling leads to more competition and a higher degree of transparency
and network optimisation. Furthermore they considered the process of separating in
ownership terms to be cumbersome and that it could be seen as amounting to
expropriation. This would create significant uncertainty and cost for many companies,
even in markets where competition is established. Finally it was argued that ownership
unbundling was adopted in countries which had large gas resources and developed
distribution networks and that the negative effects of separation were not felt so much in
these countries.
(651)Other comments, while generally in favour of ownership unbundling, were undecided as
to whether the conditions were right for enforced ownership unbundling. It was noted
that some Member States have achieved full structural unbundling under the existing
Directives, whereas the fact that, in other cases, not even the existing unbundling
provisions have been fully implemented makes it difficult to assess the real benefits of
additional measures. Other suggested that legal unbundling could be effective if
rigorously regulated, but that the current situation was inadequate in this respect. They
concluded that national regulators should, at this stage, prioritise effective
implementation of existing unbundling requirements to ensure transparency and nondiscriminatory
access to networks and that Member States should take urgent action to
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ensure that the unbundling provisions of the Directive are implemented in a manner
which guarantees independent network operators.
(652)In aggregate, a larger group of respondents commented in favour of structural and/or
ownership unbundling. These include customers, incumbent companies (from Member
States in which there is already ownership unbundling), new entrants, regulators and
traders.
(653)The consensus of this group is that if companies are unable to demonstrate effective
internal separation, then a third legislative package should enforce full structural
unbundling.
(654)The respondents in favour of ownership unbundling argue that there are the following
advantages to ownership unbundling:
♦ It removes an incentive to distort the market.
♦ It eliminates the concern that the network manager can set out investment plans to
favour its mother company and prevent new entry by maintaining congestion at entry
points to the network.
♦ It does not require the close and costly compliance monitoring which is needed to
ensure that internal separation is effective.
♦ It encourages the TSO to maximise the use of systems, including for cross border
pipelines.
♦ It increases market confidence and thereby encourages investment and entry.
♦ New entrants do not have to ask their competitors for capacity.
♦ It eliminates the concern that supply companies would discover confidential
information while TSOs could more easily aggregate information to be published.
♦ It fills the gap in cross-border surveillance of unbundling provisions.
♦ It ensures a level playing field.
(655)Regulators [CEER] supported these views and called for further action on unbundling of
TSOs. They considered that the goal of unbundling arrangements is to ensure, so far as is
possible, that the TSO behaves independently of any commercial interests among the
users of the networks, such that it acts to promote competition on the wholesale market.
They argued that a TSO which is effectively unbundled will, for example, actively pursue
transparency and information handling goals, since it would thereby generate confidence
among its customers. Equally they argued that an effectively unbundled TSO would have
the incentives to maximise the availability of network capacity, including through new
investment where there is a market need, which can, for instance, be determined through
a transparent Open Season procedure. Regulators were also concerned about a gap in the
current rules regarding cross-border monitoring of legal unbundling: where TSOs in one
Member State have ownership links with supply businesses in a neighbouring Member
State, relevant unbundling rules need to be enforced across national borders. This view
was shared by most traders.
(656)As far as DSOs are concerned, regulators pointed out that they have an important role in
the customer switching process so it is also essential for effective competition that they
do not discriminate between different suppliers.
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(657)Two notes of caution were struck by respondents in favour of ownership unbundling.
Regulators remarked that in some circumstances it would be necessary, even after
ownership unbundling, to assess the impact of long-term contracts, which can have
similar effects (on incentives and on the development of competition) as ownership links
between companies, thus indicating a risk of contractual circumvention of ownership
unbundling. Second, it was pointed out that ownership unbundling will only improve
non-discriminatory access if it goes along with effective measures regulating the network
activities.
Specific comments on storage
(658)A substantial number of respondents specifically commented on storage, where
unbundling and access provisions lag behind those at transmission level. Whereas, as
many comments pointed out, access to storage is crucial for new entry and the risk that
foreclosure of entry occurs at this level is significant. In addition to the question of
ownership unbundling, issues relating to negotiated versus regulated access ranked high
among the comments received. Virtually all respondents who commented on storage
were of the view that there is a need for further investment in storage capacity. 321
(659)Vertically integrated incumbents acknowledge that most of the existing storage capacity
is integrated into their other infrastructure and not the subject of specific unbundling
measures. However, they asserted that storage is a competitive activity as there is a large
potential relevant market for flexibility instruments including imports. They supported
negotiated third party access system rather than regulated access and tended to be
sceptical about the applicability of the use it or lose it (UIOLI) principle. Incumbents
argued that long-term storage agreements are necessary because new storage facilities
require a high level of investment which should be encouraged through a stable
regulatory regime.
(660)Customers and entrants tended to take the view that the storage market is foreclosed by
long-term reservations. In their view, it is practically impossible for any new entrants to
enter some markets, because there is not enough storage available. They are concerned
that the current arrangements, where most access to storage facilities is under negotiated
access terms, presents opportunities for vertically integrated incumbents to abuse their
dominant positions on the storage market, including in ways which are very difficult to
detect as the area is so non-transparent, and thereby prevent entry and distort competition.
Amongst other things, customers argued that it is unclear to what extent storage facilities
are needed by the (vertically integrated) TSOs for the operation of the network and
therefore are not available to the market. They also argued that negotiated access to
storage facilities and long-term reservations cause rigidity in storage use and prevent the
realisation of efficiencies for users of storage. Some comments in favour of ownership
unbundling of storage were included in the discussion above.
321
In this context, some respondents also argued that Article 22 exemptions should be used to encourage new entrants in
the storage market where this would not undermine the competitiveness of the internal market.
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Market integration
(661)Many respondents considered market integration to be of utmost importance.
Respondents argue that a harmonised European energy market will boost operational
integration and thereby maximise efficiency. They noted that further integration and thus
an increase in the scale of the market (volumes, number of players and liquidity) was an
essential requirement to increase competition and security of supply. There was
widespread agreement between respondents that there is a lack of market integration
between Member States but there are diverging views on the reasons for and the solutions
to this problem. There was also agreement on the need for investment in infrastructure,
but there is disagreement over how to maximise the use of current infrastructure.
(662)Most vertically integrated incumbents agreed that there is a need for investment in both
new and existing infrastructure (cross border transit infrastructure, new pipelines
bringing gas from further away, storage and LNG facilities). With regard to gas transit
they indicated that such investment is typically linked to long-term contracts, reservation
of storage capacity and long-term down-stream supply commitments. They argued that
future investment largely needs to also be based on similar arrangements – for example
using the possibility for exemptions from requirements for third party access under
Article 22 of the Gas Directive. In addition, many system operators and incumbent
suppliers considered the sanctity of existing long-term transit contracts should be
respected, arguing that these contracts give customers security of supply.
(663)Some incumbents also argued that unused transport capacity has a security of supply role
for example in cold weather and for unforeseen circumstances. Other incumbents agreed
that unused capacity can be released but only on an interruptible basis in order not to
compromise security of supply.
(664)New entrants and customers explained in detail the problems they face due to a lack of
market integration. These are generally centred on difficulty getting access to capacity to
transport gas and difficulty transporting gas between hubs as a result of pipeline
congestion. Entrants indicate that ineffective access to transit is a serious impediment to
the development of the internal gas market. They noted that network congestion is both a
commercial and behavioural as well as a physical problem as booked capacities in the
pipelines often remain unused. They considered that mechanisms to reduce cross border
congestion are inadequate and even in some cases non-existent. These factors have made
it difficult for them to move gas between hubs. Taken in their entirety the arrangements
for cross-border capacity allocation and congestion management in the gas sector are
seen as ineffective by traders and customers and as frustrating the prospect of any future
competition in the gas market. Some concern was also expressed that there is widespread
non-compliance with new Gas Regulation322
especially the articles relating to secondary
capacity trading and short term UIOLI. Customers emphasised the need for speedy
reforms indicating that the consequences of delay could be closure of industrial energy
intensive plants in Europe.
322
Regulation (EC) No 1775/2005 of 28 September 2005 on conditions for access to the natural gas transmission
networks (OJ 2005 L 289/1).
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(665)German industrial customers and power companies in particular indicated that there is
almost no cross-border competition or competition between the main TSO areas in the
German gas market. These customers expressed the view that foreign suppliers can only
get capacities, storage and balancing to a limited extent. They stated that industrial
customers cannot switch suppliers as there is no rucksack principle whereby capacity
moves with the customer. Instead, the old supplier keeps the capacity rights in the
pipelines.
(666)Responses from customers also contended that the return on capital from network
investments are generally much higher than rates on financial markets and that the
Directive does not define a proper access regime to entry points.
(667)Finally, there was also criticism that market integration is impeded by political
intervention in support of 'national champions'.
Suggested remedies
(668)Many of the suggestions set out by respondents to remedy the lack of market integration
overlap with remedies suggested to other issues in this report. This refers in particular to
the following points:
• Measures to create efficient and liquid wholesale gas markets also increase
integration.
• Greater transparency is a pre-requisite for more integration.
• Tackling existing long-term cross-border contracts to minimise foreclosure
furthers market integration. Part of the cross border capacity should be released
to the market.
• New entrants expressed the view that market entry was the best way to increase
integration.
• The Commission needs to fully play its role to prevent nationalistic behaviour
by Governments that favour national incumbents and discriminate between
companies of different Member States. This applies in particular (but not
exclusively) to the scrutiny of mergers.
• Deeper unbundling will have an effect on incentives to fully use existing
capacity.
(669)Two aspects received particular attention: how to maximise the use of the existing
capacity (via secondary trading and the application of the UIOLI principle) and measures
to stimulate investments in capacity by granting exemptions from third party access to
new infrastructure under Article 22 of the Gas Directive.
(670)Regarding the maximisation use of existing cross-border capacity, the development of
an efficient system to release unused capacities (at least as interruptible capacities) was
generally regarded as necessary.
(671)Incumbents tended to prefer secondary capacity trading to use it or lose it (UIOLI)
mechanisms. They argued that secondary trading is the most effective method to promote
access to capacity which is currently booked long term. Other incumbents agreed that if
there is no functioning secondary market for transit, UIOLI should be applied to unused
capacity on an interruptible basis.
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(672)Entrants, customers and regulators called for effective UIOLI mechanisms. They argued
that such mechanisms, on which some respondents make more detailed suggestions,
would oblige the current holders of capacity to release and transfer non-used transit,
transportation and storage capacity. Some respondents argued that holders of unused
capacity should not only be obliged to make the free capacity available on the market but
also be obliged to actually sell it to other market players.
(673)Entrants, customers and regulators also believed that, as prescribed by the Gas Directive,
transit should be subject to regulation and to the control of independent regulators. In
their view, this should be carried out with the objective of establishing trans-national
cross-border market areas and to create a single European gas market. Transit tariffs
should therefore be regulated and cost reflective. Network tariffs should take into account
the cost of capital of transmission companies according to the WACC method and that
this would lead to a reduction in transit costs. Comments from this group also suggested
that the 'essential facilities doctrine' plus new or reinforced powers for regulators should
be used to ensure freedom of trade in gas over major pipelines.
(674)Exemptions from third party access to new infrastructure under Article 22 of the Gas
Directive and the current system for granting them are generally supported by
respondents who commented on this issue.
(675)Some respondents who are beneficiaries of exemptions expressed the view that an
exemption can be a good way to protect an investor against regulatory risks after the
investment in infrastructure has become a 'sunk cost'. They also pointed out that Article
22 has up to now been fundamental in enabling investment in new import capacity in the
UK and that the rigorous scrutiny by the Commission and the national regulator will
protect competition. In the view of these companies, the level of exemption (e.g. whether
there should be a cap of 80% of capacity) should take into account individual merits of
the project and whether there are any market power issues. The current case by case
approach enables regulators to impose conditions such as measures to prevent capacity
hoarding, allows investment to be funded privately and can enhance competition.
(676)Regulators and other commentators expressed the view that exemptions must be assessed
according to the principles set out in Article 22 of the Directive. This implies, for
example, that a new LNG facility should be granted an exemption if the undertaking
benefiting from it has a low market share and where this infrastructure will allow such a
company access to downstream markets (allowing entrants to challenge incumbent's
dominance of imports). However they noted that if the infrastructure is proposed by a
dominant company then any exemption could contribute to reducing the contestability of
downstream markets.
(677)Customers and other market players were of the view that, as a rule, national regulators
should determine the conditions, tariffs, access and use of networks in consultation with
the entire gas market including customers in order to improve the efficient operation and
integrity of networks. They argued that if exemption from TPA is granted then effective
UIOLI requirements should be placed on infrastructure owners and capacity owners.
Generally, they considered that exemptions should be limited to the absolute minimum.
German industrial customers pointed out that German law provides for an exemption
from the cost-oriented calculation of network fees when there is potential competition in
other pipelines ("Leitungswettbewerb"). They considered that this element of the German
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EnWG is in contradiction to the Gas Directive as under EU law the benchmark test
should be applied only in a complementary way and not as an alternative to cost related
tariffs.
(678)In addition, many respondents, including some incumbents, entrants, customers and
regulators considered that regional network cooperation is an important step on the way
to pan-European integration. The European Regulator’s Group for Electricity and Gas
(ERGEG) highlighted their regional initiatives programme which it sees as an
intermediate step to EU market integration. They considered that key issues to be tackled
are: identifying barriers to gas hub development, addressing gas quality issues, looking at
the cross border 'regulatory gap', regulatory barriers to infrastructure investment in
Member States, access to networks, information provision and more coordinated
procedures between TSOs and national authorities to enhance cross border flows. They
also noted the possible issues of removing the current pan-caking of network access
tariffs and the longer term possibility of a single EU TSO. This initiative was also
welcomed by other respondents.
(679)In addition to issues related to transit management, there were various proposals to
promote harmonisation including:
• requesting network operators to establish standard mechanisms for switching
customers;
• requiring network operators to offer shippers the possibility of converting gas qualities
under fair terms and conditions;
• aligning balancing rules across markets and concluding Operational Balancing
Agreements (OBAs) between neighbouring TSOs;
• harmonising rules for accessing existing storage facilities throughout Europe, even
beyond the status of the voluntary GGPSO guidelines;
• publication by network operators on capacity and tariffs in a harmonised and
comparable form.
Transparency
(680)The majority of respondents acknowledged that transparency is an important issue. It was
pointed out that greater transparency will increase confidence in price signals, which is
important for trading and investment decisions. It would also increase effective utilisation
of energy infrastructure and market liquidity. Traders, entrants and customers detailed the
problems they face due to the lack of transparency which supports the analysis in the
Preliminary Report. They strongly recommended more transparency to encourage entry
and support the development of wholesale markets. In contrast, incumbents tended to
express concerns related to increased transparency mainly due to fears related to
confidentiality.
(681)Entrants, customers and traders consistently expressed concerns over the lack of
transparency they have experienced in the market to date. More transparency regarding
information on the capacities of pipelines and storage facilities was repeatedly requested.
They contended that the lack of transparency added to the badly functioning use-it-orlose-it
mechanisms and worsens the network congestion problem. One customer pointed
out that when information is published it is often too late and so does not enable
consumers to consider it in decision making. Respondents also highlighted their concern
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that lack of transparency surrounding the operations of TSOs tends to benefit the
incumbent gas supplier.
(682)Network users generally called for greater transparency in all Member States and more
accurate, comprehensive information published on a daily basis regarding transit and
transportation capacity, network maintenance, storage, LNG and access to networks. This
was highlighted as an essential feature to ensure non-discriminatory access to
infrastructure, allowing all actors to have the same level of information. Many alleged
anti-trust and regulatory issues related to access to gas infrastructure in continental
European markets were seen as related to a lack of transparency.
(683)Regulators also took the view that there is a need for more transparency on key market
information as well as a process for TSOs to manage confidential data. Although some
respondents expressed views on whether more transparency would increase the
likelihood of collusion, regulators consider that fears of collusion should not cause too
much concern at this stage since more transparency would help regulators detect
collusion. Others concurred arguing that collusion would be more difficult to detect
without additional transparency measures.
(684)As an example, respondents commenting on problems in the North-West Europe region
during winter 2005/06, especially between the National Balancing Point (NBP) in the UK
and the Zeebrugge hub in Belgium argued that it is striking to what extent the lack of
transparency has even prevented precise identification of physical bottlenecks or
unexpected market behaviour.
(685)Some incumbent operators also argued that the criticism regarding transparency would be
obsolete once the capacity for the supply of final customers is guaranteed (e.g. through
application of the rucksack principle).
Suggested remedies
(686)In the view of entrants, customers and traders publishing more information is essential.
It was frequently considered that more information could be released under existing
legislation and that this would bring significant and rapid improvement. But many
respondents considered that further transparency obligations will be necessary to ensure a
level playing field.
(687)Entrants, customers and traders advocated the removal of the three or more rule in the
Gas Regulation whereby information may be restricted in the event that only one or two
shippers are using capacity at a particular point in the network. Incumbent gas companies
disagreed with this and expressed their concerns over confidentiality of business
information and are in favour of the 'three shipper rule'. Some respondents were in
favour of publishing ex ante figures only in aggregated form or only indicating a range in
order to help to protect commercially sensitive data of specific companies.
(688)Infrastructure operators proposed a Code of Conduct for transmission, which they
believed should be sufficient to provide necessary transparency. Some argued the case for
getting more experience with the existing rules on transparency before changing the
regulatory framework.
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(689)Respondents called on the Commission to actively implement and enforce transparency
and anti-hoarding measures.
(690)One customer group would like to see the establishment of a statistical bureau such as the
AEI (Agency for Energy Information) in the USA to supply transit, storage and turnoverper-hub
information.
(691)Regulators highlighted that transparency and information handling will be a key theme
in the Regional Initiatives. They state that the next steps may be to strengthen the
transparency requirements in the Gas Regulation. In the second half of 2006 regulators
will start work assessing the effectiveness of the new Gas Regulation.
Prices
(692)Comments on prices concerning the gas-oil price link and regulated tariffs were set out in
detail. There were also various other comments regarding pricing including reasons for
parties selling gas from the same field using the same price formula.
Gas-oil price link
(693)Respondents expressed starkly contrasting views regarding the role of the oil-gas price
link, which the Sector Inquiry has confirmed is used in most European long-term gas
contracts. Generally speaking the views fall into three group: incumbents and producers
argued insistently for the link; there are a group of regulators, entrants and traders who
considered the link as a symptom of the lack of competition rather than a problem to be
addressed in isolation; and finally there is a group of entrants, customers and government
agencies who argued strongly against the link.
(694)Incumbent gas companies and gas producers argued more insistently for the link. They
see the benefits of the oil price link in its transparency, stability, reliability and its ability
to enable investment. They contended that the link is a logical solution to low levels of
liquidity on gas spot markets. They considered that the link helps to avoid high volatility
on spot markets which would be detrimental to suppliers and consumers arguing that this
is particularly important in avoiding shocks such as the situation in Ukraine in winter
2005/06. They suggested that the resulting relative price stability is, from a financial
point of view, a merit in any business. Some respondents in this group also argued that
the UK NBP, in any case, follows a similar long-term trend to oil prices and that
therefore oil price indexation does not lead to higher prices than otherwise. A further
argument made by incumbents is that more volatile gas prices in the UK have not
provided pertinent investment signals notably for storage infrastructure. However, one
incumbent acknowledged that there is volatility in the oil market too and that prices
linked to oil are not necessarily more stable.
(695)Incumbents and producers tended to argue that a long-term correlation between oil and
gas is inevitable since the products are long-term substitutes. One producer took a more
nuanced view arguing that the regional supply-demand characteristics of gas resulting
from investment decisions mean there will always be specific relevant pricing factors to
the gas market in addition to the geopolitical and other factors driving the oil market. It
concluded that the oil link will continue to have a role for base-load deliveries between
producers and large customers even if liquid gas markets are established, but implied that
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there are other factors to be incorporated into gas prices as well. In its view the gas
specific factors could add uncertainty which would result in higher price volatility. A
higher level of risk could, however, lead to increased cost of capital with higher prices as
the ultimate outcome.
(696)In support of these arguments another producer argued that oversupply of gas is unlikely
to occur, and that Europe is on its way to becoming a sellers’ market. Given this, it
argued that a consumer would not want to risk the contract price being unduly influenced
by the seller, for example on a local hub and so it may prefer an oil price link.
(697)Still another producer argued that oil indexed contracts factor in the price of flexibility
since most annual oil indexed gas prices will include an element of seasonality. Prices
will not fluctuate in summer/winter in the same way as hub prices but over the year these
differences in fluctuations will average out.
(698)Many other respondents, including regulators, traders and entrants were of the view
that the oil-gas link is a symptom of the lack of effective competition rather than a
problem to be addressed in isolation. These respondents argued that with effective gason-gas
competition on liquid wholesale markets oil indexation would disappear or be less
prominent. Some respondents were of the view that regulators and the Commission
should not focus on contract prices and on the indexation of gas prices but on ensuring
that the conditions for competition are in place so that gas prices reflect gas market
fundamentals. Some of these respondents argued that until there is more liquidity on gas
markets it is important not to stifle innovation on pricing by excluding or limiting any
particular types of price indexation. One customer group agreed that buyers should have
the freedom to negotiate contracts, but they also argued that if there was adequate cost
transparency then there would be no need for the oil link.
(699)Some UK respondents cited how competition has developed there. They noted that before
liberalisation in UK most contracts were linked to oil. However as a result of market
reforms, they argued that the UK gas forward market has become a functional trading
market with efficient price-formation independent of the oil price.
(700)Customer groups argued that gas operators tend to refer to the so-called 'market price'
(from publications) which is not connected to oil products, whilst most contracts with
producers are, however, linked to oil prices. They contended that this situation makes it
very difficult to know the underlying market fundamentals. They called for all price
indices to be published where these are relative to real concluded transactions and for
prices to be regularly checked to ensure they are not used by dominant market players to
fix future prices. Also a trader called for the Commission to further investigate the gas oil
price link.
(701)Finally there are the views of respondents who are completely against the oil price link.
This group includes regulators, customers, traders and government agencies. This group
of respondents tended to argue that the currently existing price setting mechanism should
be replaced by a system in which an effective interaction of supply and demand
fundamentals will be possible. They argued that this would enable long-term contracts
based on true negotiations between producers and buyers. They called for transparency in
price setting mechanisms.
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(702)One regulator argued that oil and gas can be regarded as long-term substitutes, but that
short run substitutability is limited to some uses such as dual fired power plants. They
considered that the UK use of prices from a liquid hub more accurately reflects the
supply-demand conditions and gives better investment signals. In their view the Sector
Inquiry indicates that non-liquid hubs and the built-in flexibility in long-term gas import
contracts appear to perpetuate the oil-price link. They considered that as long as
incumbents do not have enough incentive to trade on existing hubs the price formation of
gas will still reflect the currently low levels of liquidity, compromising the move from oil
indexed price to gas prices. They contended that even with greater hub liquidity hub
prices would, for the time being, tend to reflect oil indexation in import contracts. In
general, they considered that the main issue is the contractual relations with gas
producers and that oil indexation favours producers, if in the long run oil markets tend to
be tighter than gas markets. They also acknowledged that for producers to accept hub gas
prices there needs to be more hub liquidity.
(703)Another respondent estimated that the annual cost to the EU of gas prices remaining
linked to the price of oil could, under certain assumptions, be extremely high (a value of
around 50 billion Euros was mentioned). It considered that this indicates that the price
benefits to EU consumers of introducing gas-to-gas competition are likely to be
significant.
Regulated tariffs
(704)Many respondents commented on the role of regulated supply tariffs in EU gas markets.
A key concern was that prices might be set below the wholesale price benchmark and
that this would lead to new suppliers not entering or being squeezed out of the market.
Concerns were expressed in particular in relation to tariffs in France, Spain and new
Member States.
(705)The Council of European Energy Regulators (CEER) expressed the view that domestic
prices should not be set by government but independent regulators.
(706)In Spain entrants were concerned that government-set tariffs bear little relevance to the
real cost. However, it was pointed out that these regulated prices should disappear by
2008. Entrants were particularly concerned about Spanish regulations which determine
that supply of the regulated market is made preferentially from pipeline gas purchased
from Algeria. The entrants pointed out that the incumbent faces no risks with this
contract -if it overshoots the required quantity it gets to keep the excess and sell it on the
market at inflated profit; if it undershoots it gets to buy more on the spot market for
which it is compensated (the regulated price includes an element of spot price in the
calculation).
(707)Entrants to the French market and the national regulator also expressed concerns that the
government-administered tariffs are below cost. In particular one entrant commented that
supply tariffs applying to eligible business customers connected to the distribution
networks create a significant barrier to competitive entry in this market. The entrant
called on the Commission to address the general issue of protection of incumbent
positions through low tariffs that are disconnected from underlying economic inputs.
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(708)Concerns were expressed by regulators and entrants that although the principles
underlying French tariffs do allow the possibility to have competitive tariffs, the last
price control by the Ministry of Economy set the tariffs at a lower value than would
permit it to cover the increase in the incumbent's costs. The respondents considered this a
serious impediment to effective competition. Even the French incumbent gas supplier
expressed concern that the maintenance of regulated tariffs could have negative effects
on competition and considers that regulated prices should reflect costs.
(709)Another respondent was concerned about tariff regulations in new Member States, which
it alleges leads to cross-subsidies from industry to residential customers and prevents the
reflection of real costs in gas prices.
Other comments on prices
(710)Two respondents defended reasons for different companies, selling gas from the same
field while using the same or very similar price conditions. They noted that price and
conditions tend to be more or less similar if the quality, production profile and entry point
are the same. They argued that customers are likely to demand similar terms from other
parties involved in the same field.
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II. Electricity
(711)The electricity part of the Preliminary Report received comments from 45 respondents,
including undertakings operating in the sector, their associations, national authorities and
other European stake holders. Geographical coverage can be considered as representative
since the respondents from 13 Member States, and one non-member state, comment not
only on their respective national markets but also on the broader EU issues. Moreover, a
number of comments come from the sector associations which group market players from
all over the Europe.
(712)By and large comments on the electricity part of the Preliminary Report are positive in
tone and supportive to the Commission’s findings. The respondents welcomed the
Commission’s open approach which has provided them with a chance to express views
on the issues raised in the Preliminary Report. In general, the respondents shared the
Commission’s concerns related to current market developments arguing that there is
insufficient progress in the implementation of the liberalisation package and generally
restricted prospects for future market development. Comments include numerous
proposals for steps which should be undertaken, at European and national level, in order
to promote competition and to encourage investments in the sector.
(713)A limited number of respondents also took a more critical stand towards certain parts of
the Commission’s analysis and their specific implications for the sector, for instance as
regards the need for further unbundling. This is, however, understandable if one takes
into account the interests defended by the respondents in question, in particular those
speaking on behalf of the incumbents.
(714)Most of the comments the Commission has received can be directly linked to the
particular issues discussed in the Preliminary Report. Therefore, the structure of the
present summary will reflect, in a natural way, the order of topics from the Preliminary
Report. This summary therefore begins with the outline of comments relating to the
Preliminary Report’s introductory issues concerning the regulatory framework and
functioning of wholesale markets and continues with comments on the five main issues
analysed in the Preliminary Report, i.e. market concentration, vertical foreclosure, lack of
market integration, lack of transparency and prices. Finally, an abstract of comments on
the potential remedies sketched in the Way Forward chapter of the Preliminary Report
will constitute a closing part of this summary.
Introduction issues
Regulatory framework
(715)The general perception is that the expected results of the liberalisation process have not
yet been achieved. However, the respondents are divided when it comes to pointing out
specific reasons of this failure. A group of the respondents whose interests can be
identified with the incumbent operators considered that the current regulatory framework
will prove to be sufficient once fully implemented. In the opinion of this group, any
further regulatory intervention, before the existing framework is truly in place, would be
premature.
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(716)The remaining respondents, who commented on the issue, were more critical of the
current regulatory framework. Besides stressing the importance of effective
implementation of the current framework, they advocate supplementary legislative steps
to address among other things: the lack of market transparency and the need for a more
coherent approach by the national regulators and TSOs to create a truly European market.
In the view of many respondents, current regulatory policy lacks coordination which
obviously hampers market development. This coordination gap, in the opinion of two
respondents, could be closed by establishing a pan-European grid and/or a European
regulator.
(717)Comments on the current regulatory framework also related to the existing unbundling
provisions, which are briefly summarised in the part on structural remedies below. The
imperfections resulting from the present Emission Trading Scheme (ETS) were also
identified by many participants.
Functioning of wholesale market
(718)A similar division of views can also be noticed in comments relating to the functioning of
wholesale markets. The respondents linked to vertically integrated undertakings showed
much more confidence in the wholesale markets, whereas other respondents were less
confident.
(719)A number of shortcomings were identified in the way that the wholesale markets are
currently operating. They were concerned with: (a) supply-side market concentration, (b)
structural problems in transmission (e.g. with a view to allowing cross border trade), (c)
“parallel bidding” on the neighbouring markets for CO2 emissions and for natural gas
and the impact of such parallel biding on the electricity market, (d) short and long-term
withdrawals of generation capacity by market operators in control of several plants
representing a cross-section of different technologies, (e) suspicious pricing strategies by
certain large market operators, (f) excessively large bidding steps in terms of volume on
some power exchanges (Powernext), (g) opacity of OTC markets and (h) absence of a
forward market (Italy).
(720)At the same time, however, a few respondents mentioned considerable progress as
regards market liquidity both in terms of increasing number of market participants and
increasing trading volumes over the last years.
Concentration and market power
Concentration in generation
(721)The most common opinion among respondent on the concentration in generation was that
prevailing high level of concentration constitutes an important obstacle for the
development of competitive electricity market. It was noted that the current situation is a
consequence of the pre-liberalisation market structure and might be further aggravated by
recent consolidations. Many of the respondents pointed to cross-border market
integration as the means to achieve a more balanced market configuration. In this context,
the CEER/ERGEG Regional Initiatives were mentioned as one of the means to push
forward further market integration. The Commission was also urged to scrutinise
meticulously future mergers and be vigilant in its control of state aid. Other suggestions
ranged from a recommendation to introduce a positive discrimination of newcomers and
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revamped VPP programmes to a call for the co-operation between competition and
regulatory authorities in order to develop more systematic and wider market surveillance
mechanisms.
Concentration in trade
(722)As in the case of concentration in generation, many respondents considered cross-border
market integration and VPP programmes as ways to counterbalance market concentration
in trade. One commentator, for example, proposed establishing thresholds that would
oblige the incumbents to trade certain minimum volumes on the wholesale market.
(723)The respondents, even if not always explicitly, made a link between concentration in
generation and in trade. One respondent argued that, in the assessment of market power,
concentration in trade is much less critical than concentration in generation. This is
because the spot prices usually hinge on the offers made by the sellers controlling
generation capacity. According to the same respondent, the spot market outcome is
decisive for setting forward prices, which in turn means that concentration in generation
has spill-over effects not only for spot prices but also for forward trading and that market
power may remain an issue of concern regardless how favourable the concentration ratio
in trade seems to be at the first sight. Another respondent added that the presence of
traders on a given market does not necessarily reflect the true confidence of other
participants in that market. Traders might be attracted by the arbitrage possibilities
generated by price volatility.
Price setting
(724)Views on the price setting mechanism are divided. Customers as well as some other
respondents lack confidence in the current wholesale market prices. One respondent gave
an example of one particular company for whom a comparison of costs against day-ahead
prices has revealed, for particular hours, a suspiciously high number of negative margins.
According to the respondent, such an observation may indicate an abusive conduct by the
market player whose interests lie in deterring new entry by reducing prices for certain
hours in combination with cross-subsiding from other periods where entry is less likely.
(725)On the other hand, there are, as well, respondents who doubted whether market players
have such an ability to distort prices over a sustained period of time.
(726)Several respondents pointed to the ETS scheme as to a likely source of price distortions.
Stranded costs payments schemes on the Iberian peninsula were also believed to distort
competition.
Withdrawals of capacity
(727)As already mentioned above, there were several respondents who suspect that short and
long-term withdrawals of generation capacity take place and that operators in control of
several plants representing a cross-section of different technologies may have incentives
to engage in this type of conduct.
(728)It is in this context that one respondent pointed out that there are certain markets on
which every big supplier is in fact, at present, indispensable to meet residual demand.
The fact of being indispensable may give such a supplier scope for strategic behaviour in
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the way it operates its generation capacity. However, the opposite view was articulated
by one of the power exchange operators.
Other comments relating to concentration
(729)A limited number of respondents also made general remarks on the specificities of market
analysis in the electricity sector. They advocated a narrow definition of the relevant
electricity market, for example on the basis of each hourly resolution as a separate
product market. In this context, it was noted that the traditional tools of market analysis
like concentration indices might not be straightforwardly applicable to the markets
characterised by very specific technical conditions. One of the respondents suggested that
the analysis should be restricted to individual technologies, for instance gas-fired plants.
In other words, the analysis should focus on a group of the plants operating in the
technology or technologies with marginal costs close to the system price at any particular
time period. Another respondent would prefer that the price analysis took into account
not only of price levels but also the average annual prices and profits. In their opinion,
the analysis of certain hours in isolation may provide biased results because it ignores a
substantial number of hours when prices would be expected to be low due to the must-run
production.
Vertical foreclosure and vertical integration
Vertical integration between generation and retail activities
(730)The respondents representing the electricity industry considered vertical integration to be
a consequence rather than a cause of insufficient liquidity. Taking into account the
current market conditions, their view was that vertical integration should be regarded as a
legitimate business model. However, it was also argued by one respondent that vertical
integration provides scope for negative retail margins. Such a cross-subsidisation of retail
activities with the profits generated further upstream may allow for the limitation of new
entrants’ ability to compete effectively for final customers.
(731)Several respondents called for liquidity to be increased via an increase of the quantities
being currently released under the Virtual Power Plant (VPP) programmes. One of the
respondents draws attention to a number of constraints that reduce usefulness of current
VPPs. The effectiveness of VPP is believed to hinge on its internal design, including its
pricing and other terms, as well as on external conditions, including concentration of the
market on which a VPP’s purchaser is supposed to sell the purchased power and/or
ability to acquire cross-border capacity that would correspond with the size of VPP. The
latter option is needed to provide protection against the risk of adverse price movements.
A number of respondents also agreed that power purchase agreements (PPAs) between
generators and suppliers also can add to the drying-up of liquidity.
Vertical integration between supply and network activities
(732)The respondents seemed to agree on the fundamental premise of network unbundling:
that is on the importance of transparent and non-discriminatory access to the network.
Nevertheless, the views departed sharply over the provisions required to ensure efficient
unbundling. Those respondents related to vertically integrated groups contended that as
long as the current unbundling regime is not fully implemented it is difficult to assess the
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real benefits of further initiatives and that it is too early to discuss any further actions
aiming at improvements of the current regime.
(733)Other respondents, who represent more diverse interests, including customers,
independent traders and suppliers with no transmission affiliates, considered that further
unbundling of network activities is required to solve the existing problems. The
respondents underlined that a lack of effective unbundling severely distorts market as
vertically integrated incumbents have little or no incentive to provide adequate access to
transportation/distribution infrastructure. Moreover, it was further argued that TSOs in
common ownership with dominant incumbents often lack the necessary incentives to
invest in additional cross-border capacity where this would facilitate competitive access.
These respondents also linked insufficient unbundling with such practices as crosssubsidising
of electricity prices and discriminatory use of data relating to customers.323
(734)Apart from the general criticism spelled out by many respondents arguing that
unbundling is not proving to function well on most of the European markets, a few
comments were more specific. For example, one respondent expressed his disbelief in the
effectiveness of the Chinese walls introduced by the integrated businesses and pointed to
gains from an exclusive access to information within integrated entities. Another
respondent noted that the grid owners have an additional advantage since they can use
their network assets as a collateral to acquire better conditions for financing the
development of their supply activities.
Market integration
Current institutional framework and investments in new cross border infrastructure
(735)A majority of respondents criticised the current institutional framework for the operation
of cross-border networks and complained, in particular, about insufficient capacity in
cross-border links. In their opinion, the present situation is due to inefficient allocation
mechanisms and incompatible market rules. In addition, the issues concerning crossborder
infrastructure were thought to be left in a regulatory vacuum where the current
regulatory framework fails to create the right incentives for TSOs to expand their
networks, in particular since the use of congestion revenues is not prioritised to the
expansion of cross border capacity. Comments were also made on the need for an
increased focus on coordination between TSOs. It was also claimed that, in the absence
of regulatory incentives, that TSOs may find it profitable not to increase but actually to
reduce available capacity. One of the respondents called for a review of how TSOs arrive
at capacity values. Another respondent suggested that current problems with the
unsatisfactory level of investments are due to insufficient unbundling.
(736)A number of the respondents referred to the 10% target of interconnection between
national grids discussed between Heads of State at the Barcelona summit in 2002. they
suggested that such arbitrary targets may no longer be useful reference point for crossborder
capacities. Instead they argued that investments should be undertaken where they
are justified by cost-benefit analysis on a case by case basis. Furthermore, several
respondents noted that in order to enhance capacity in cross-border links, investments
should also take place in the internal national networks because internal congestion can
323
A number of market participants preferred to comment outside the public consultation. They expressed concerns, in
particular with respect to the connection of new power plants to the grid of vertically integrated electricity
companies.
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often have a negative effect on capacity available in the interconnectors. The respondents
also pointed out the difficulties in acquiring necessary permissions from national and
local administrative authorities which TSOs face before any investment can actually start.
Allocation of existing cross-border capacity
(737)All the respondents agreed on the need to implement non-discriminatory market-based
methods for the allocation of cross-border capacity in line with Regulation 1228/03.
However, the respondents’ views departed over the specific methods that should be
adopted. The respondents can be split into three main groups. The first group argued that
implicit auctions are more efficient than explicit ones. For example, the power exchanges
contended that ‘market coupling’ will result in improved utilisation of interconnector
capacity and in more capacity available for trading thanks to netting of electricity flows.
Those respondents with experience from the Nordpool market(s) also advocated a shift to
implicit auctions as the main allocation mechanism for cross-border capacity. However, it
was noted that the allocation mechanism can only be changed from explicit to implicit if
spot markets are in place and are sufficiently liquid.
(738)The second group was against implicit auctions and ‘market coupling’ as they argue that
such mechanisms are more opaque and complex than explicit auctions. Moreover,
implicit auctions were claimed to give unnecessary influence over the wholesale market
to power exchanges and imply a restriction over the way electricity is traded. In
particular, the logic of implicit auctions, according to which cross-border energy flows
depend on the bidding results and clearing prices on respective power exchanges, was
considered to be difficult to reconcile with the bilateral model of OTC trade which are
not necessarily cleared on a power exchange platform.
(739)Finally, the third group favoured a combination of the explicit auctioning of forward
transmission capacity and day-ahead market coupling. Such a mix was believed to
guarantee efficient cross-border competition and the maximisation of the usage of
existing capacity.
(740)A few respondents argued that many of the present inefficiencies in the current explicit
auctions are not a consequence of explicit auctions per se but of the time gap between the
nominations of physical capacity usage and the clearing bids and offers into power
exchanges. Therefore, the key to improve the efficiency of explicit auctions is to work on
better cooperation between TSOs and on the harmonization of clearing times at power
exchanges.
(741)Several respondents were concerned by existing capacity reservations under long-term
pre-liberalisation contracts. It was argued that this leads to a situation in which
allocations on a number of the critical borders are not made on the basis of a marketbased
mechanism. One respondent also calls for the strict application of the use-it-orlose-it
principle.
Transparency
(742)With very few exceptions, respondents all asked for more transparency arguing that this
is necessary to ensure a robust mechanism of price setting and to reduce price volatility,
which in turn reduces barriers for new entrants. The respondents would welcome the
creation of an European-wide level playing field in terms of the availability of standard
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information on the functioning of energy markets. This calls for an effort of harmonizing
transparency requirements across the European Union. The levels of transparency
achieved on the Nordic markets and in the UK were most often cited as benchmarks
against which progress on other markets should be measured.
(743)As regards the data considered to be indispensable for effective decision-making, the
respondents mentioned among others: (a) data concerning system bottlenecks, (b)
information on system load, (c) real-time information on generation, (d) detailed
maintenance schedules, (e) information on unplanned outages and (f) progress against
CO2 emission targets by Member States. In a few instances, the respondents’ suggestions
differed with each other in the degree of data disaggregation that is required for market
transparency. While some respondents regarded aggregated production data as sufficient,
others believed that the aggregation must be at the lowest level consistent with protecting
commercial confidentiality.
(744)Several respondents mentioned different initiatives to induce a more harmonized
approach to the issue, for example the Euroelectric Roadmap for Transparency, the
ERGEG/CEER initiatives like the Guidelines for Good Practice (GGP) on Information
Management and Transparency in Electricity Markets and the GGP for Electricity
Balancing Markets.
(745)In the context of the discussion on transparency, one respondent made the remark that
independent TSOs tend to release more information than those that are not unbundled.
Price issues
External factors possibly explaining price increases
(746)The impact of the ETS scheme on electricity prices continues to cause serious concerns
among industrial customers. They considered that the ETS scheme now has a decisive
role in setting electricity prices at unfairly elevated levels providing the producers with
windfall profits. The industrial customers called for urgent relief, for example that
electricity producers should not be allowed to feed the CO2 prices into wholesale market
prices. In addition, windfall profits resulting from the process were considered to disturb
competition by strengthening unduly the incumbents.
(747)Others maintained that the CO2 prices are now a part of the cost function of generators
and, for that reason, have to be priced in to wholesale market prices. In the opinion of one
respondent, the problem is in fact more related to the currently observed mispricing of
CO2 caused by the imperfections of the CO2 market and the lack of information on
actual electricity generation disaggregated by fuel type.
(748)Another respondent contended that the higher prices reflect not only the increases in the
CO2 and fuel prices but also the tighter supply-demand balance. They considered that
this should be considered as a natural price signal necessary to trigger future investments
in generation capacity. Finally, one respondent argued in favour of long-term contracts
between suppliers and final customers believing that such contracts protect a purchaser
from the changes in short-term electricity prices that can be disproportionately inflated by
the prices of CO2 emissions.
ENERGY SECTOR INQUIRY – SECOND PHASE (Public consultation)
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Regulated supply tariffs and special support schemes
(749)In general, the respondents expressed a high level of discontent with the existence of
regulated tariffs which are believed to have severe anti-competitive and protectionist
effects. In the view of many, the termination of supply price regulation is a precondition
for market functioning. Several respondents substantiated their comments with examples
on how the French and the Spanish regime create serious market distortions and
substantially reduce the room for new entry.
(750)A few respondents considered the need for some possibility of price intervention to be
retained for the protection of vulnerable customers. However, the view was also
expressed that price caps and competition can co-exist provided that the regulators ensure
the caps are not set below the economic cost of supply.
(751)As regards special support schemes for energy intensive users, the Commission was
urged to scrutinise them in detail.
Way forward
Competition law remedies
(752)A number of the respondents expressed support for the Commission actions to tackle the
most serious problem areas where competition law infringements are identified. One of
the comments most often made relates to the need for tough merger scrutiny. In the
context of possible remedies, it was suggested to more frequently use release
programmes (e.g. VPPs, sites release for new electricity generation, capacity on
interconnections) which could ease effects of concentration. Only one respondent clearly
doubted the usefulness of existing competition law tools and argues that the electricity
sector merits a separate status.
Regulatory remedies
(753)With respect to the regulatory remedies, the respondents most often called for the
harmonization of legal and regulatory frameworks across Europe and for a more
integrated, coherent regulatory effort. To this end, two respondents advocated setting up a
pan-European grid and/or a European regulator.
(754)Many of the respondents urged the Commission to strengthen the transparency
requirements by means of binding European legislation, arguing that a level playing field
needs to be created quickly. They welcomed the ongoing initiatives of the Commission
and the regulators and called for completion of the process.
(755)Some incumbents, on the other hand, emphasised the need for a stable regulatory
framework and ask in the first place for complete implementation of the current
framework. In this context, one of the power exchanges argued that any further
regulatory burden placed on its operations will increase the costs of trading and thus
instead of boosting trade it may lead to the drying-up of the observable market.
(756)As regards the broader regulatory context, a few respondents proposed changes in the EU
ETS scheme. Depending on the particular perspective, the respondents wished to see the
resolution of the so-called windfall profit problem and for building a stable and consistent
ENERGY SECTOR INQUIRY – SECOND PHASE (Public consultation)
231
EU ETS scheme beyond 2012 and therefore allowing the industry to take on long-term
investments in the correct generation technologies.
Structural remedies
(757)The key issue is whether the respondents regarded full ownership unbundling as
necessary to ensure a true level playing field. Unsurprisingly the respondents’ opinions
were split in accordance with their market positions. The vertically integrated groups
defended the position that the most critical issue lies in the incomplete implementation of
the existing unbundling provisions and that ownership unbundling would be both
extremely cumbersome and legally difficult, as it could border on expropriation.
(758)The others favoured full structural unbundling, especially if the implementation of the
current provisions fails. Consumers considered the independence and full unbundling of
TSOs as the key issues, ensuring a level playing field and creating an incentive structure
to develop the network, which is undistorted by supply interests of associated supply
branches. Their position in this respect was supported by the respondents trying to
expand on new markets and by a number of the authorities with responsibilities in
overseeing operations on the market.
Other comments
(759)For the sake of completeness, it should be mentioned that several respondents, in their
replies, updated the Commission on the latest market developments and/or made certain
technical comments on the analytical tools adopted by the Commission.
Conclusions on the public consultation for gas and electricity
To a large degree, the findings of the Preliminary Report have been confirmed in the
public consultation. In general the Commission’s analysis is shared by the respondents, in
particular those not related to the interests represented by the incumbent players.
Nevertheless, even the incumbents agree with many points in the analysis of the sector
presented in the Preliminary Report. The main issue on which the views diverge is the
success of the existing unbundling provisions. The results of the public consultation are
reassuring as regards the general orientation of the Preliminary Report and suggest that
the current orientation favouring further market opening and integration should be
maintained.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
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b. GAS
I. Competition on downstream markets
Introduction
(760)Achieving competitive and integrated EU gas markets will ultimately benefit consumers
through lower prices, more choice and differentiated services. Therefore it is important to
consider customer experiences when assessing the effectiveness of competition in EU gas
markets. The ability for customers to switch is a driver of competition all along the
supply chain. The threat of losing customers encourages gas companies to obtain the best
offers on their purchase of gas, as well as transportation and ancillary services.
(761)This chapter therefore looks at gas customers’ experiences. It firstly gives an overview of
the market briefly discussing prices and switching levels. It then sets out the theory of
downstream foreclosure and analyses relevant data collected in the context of the Sector
Inquiry in relation to customer contracts. Finally it considers factors which restrict how
customers may dispose of their gas and how these may inhibit upstream competition as
well.
Overview of market
(762)Currently not all Member States have fully implemented the Second Gas Directive so
some customers are not yet able to switch. Many Member States introduced competition
in downstream markets in a phased process initially starting with the largest consumers
such as industrial customers, power plants, distribution and supply companies. However,
by 1st July 2007 all customers, including household customers, should have the ability to
switch, except in countries which still benefit from a derogation under the Second Gas
Directive.
(763)The charts overleaf compare prices in different Member States for industrial customers in
2005 and 2006. These show that prices vary considerably across Member States
illustrating the effects of a lack of integration. Indicative of the fact that the single market
is not yet a reality, Member States with the most expensive gas experience prices almost
twice as high as the cheapest Member States.324
It should also be noted that some
countries, where the liberalisation process is less advanced, have retail price controls.
Price divergence between Member States may also be indicative of a lack of investment
in networks and a lack of gas to gas competition. Problems related to regulated tariffs,
such as the danger of stifling competition through excessively low price caps, are
discussed in more detail in the section on prices and in the section regarding responses
from the public consultation.
324
This does not consider Member States whose network is not connected inside the EU to the main interconnected
European grid such as the Baltic countries and Finland.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
233
Figure 69
Large divergences in prices across the EUillustrate the lack of integration
2005 2ndhalf
0 1 2 3 4 5 6 7 8 9 10
eu25
CZ
DK
DE
ES
FR
IT
HU
AT
PL
SK
SE
UK
prices in Euros per GJ
Source: Eurostat Industrial Prices 2005 (including network tariffs but excluding taxes) for Standard
consumer 13-1, annual consumption of 41.86TJ (11.63GWh)
Figure 70
Large divergences in prices across the EUillustrate the lack of integration
2006 1st half
0 2 4 6 8 10 12
eu25
CZ
DK
DE
ES
FR
IT
HU
AT
PL
SK
SE
UK
prices in Euros per GJ
Source: Eurostat Industrial Prices 2006 (including network tariffs but excluding taxes) for Standard
consumer 13-1, annual consumption of 41.86TJ (11.63GWh)
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
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(764)Price differences and the lack of pan-European offers are lamented by customers. For
example, one industrial customer replied, “We would like to be able to conclude a pan
European gas contract where our small sites are consolidated into a corporate contract
in order to benefit from bulk purchasing of gas by the group. It is not possible to do this
across the EU at present. The inability to set up multi-site contracts negotiated centrally
means that we cannot buy gas or electricity at the best possible price.”
(765)Switching data also illustrates the ability of customers to benefit from competition. As
with prices, switching levels vary considerably across Member States. They range from
up to 90% of industrial customers switching in the UK (where contracts are generally
renewed on a yearly basis) to no switching activity at all in most New Member States325
.
Customers across the EU, who responded to the Sector Inquiry, indicate that they have a
very limited choice of suppliers and that it is very difficult to get competitive offers from
non-incumbent gas suppliers. e.g. one industrial customer commented: “Today national
markets remain largely dominated by historic suppliers and it is very difficult to obtain
competitive offers from more than one supplier.”
(766)The majority of end-customers are connected to distribution networks, although some
large users connect directly to transmission networks. Distribution system operators
(DSOs) are generally responsible for metering their customers’ consumption, and
therefore in competitive markets often have a vital role in ensuring the availability of
accurate consumption data and in ensuring a smooth customer transfer between suppliers.
The Second Gas Directive requires DSOs to be legally unbundled and management
unbundled (i.e. independent from activities not related to the network operation as
regards legal form, organisation and decision making). However, the legal unbundling
only has to be completed by 1 July 2007, and Member States can also exempt small
distribution system operators, serving fewer than 100.000 connected customers, from the
obligation of legal unbundling (but not from accounting unbundling). Therefore the
supply and distribution functions are not effectively unbundled in most Member States.
(767)The analysis in this chapter focuses on large gas consumers including industrial
customers, power stations and local distribution and supply companies. Together these
customers consume the majority of the gas, giving good market coverage. Because of
their size they are also some of the most attractive customers. Finally, in most Member
States competition has been established for these customers for longer than smaller
companies or domestic household customers.
(768)Given the high degree of vertical integration in the gas industry and foreclosure on upstream
markets (discussed elsewhere in this report) we would expect to see similar
foreclosure problems on the downstream markets. Importers with long-term gas purchase
contracts containing use restrictions, tacit renewal clauses and long notice periods, will
tend to seek to secure their downstream market shares through the same tools. This is
confirmed by the analysis in this chapter. Further, highly concentrated gas wholesale
markets and difficulties getting access to gas transportation and distribution also restrict
new entry at the downstream level.
325
See Communication from the Commission to the Council and the European Parliament: Report on progress in
creating the internal gas and electricity market, COM(2005) 568, {SEC(2005) 1448}, Technical Annex section 3.
Figures are on a cumulative basis.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
235
(769)The analysis in this chapter uses Sector Inquiry data collected from both customers and
suppliers. Suppliers selling natural gas to downstream customers were asked for
information on the contracts offered to eligible end-consumers. Each supplier contacted
was asked to provide information on its 30 biggest industrial customers, local distribution
and supply company customers and power generator customers. This provides a large
data set of about 1000 contracts covering about 200bcm of gas across five Member
States. The total consumption represented in these contracts covers 76% of the total
consumption in those Member States.326
In addition, the replies of a smaller sample of
industrial customers were analysed and used to check the responses of suppliers.
Foreclosure on downstream markets
(770)The concept of downstream foreclosure refers to the anti-competitive effects that may
arise from a series of parallel long-term agreements between final consumers and their
suppliers – be it a dominant supplier or a network of suppliers engaging in the same type
of practice327
. A network of parallel contracts can adversely affect the market as the
contracts prevent entrant suppliers from finding suitable outlets for their products, since
the customers have met their entire demand – or a large part of it – on the basis of longterm
contracts with incumbent suppliers and are thus no longer present on the market.
Since future gas demand is not expected to grow significantly (less than 2% per year
between 2003 and 2030328
) its impact on new market entry will be small.
(771)When assessing long-term exclusive supply relationships at least the following four
elements will normally be taken into account329
:
- the volumes tied under the individual contracts (exclusivity)
- duration of the contracts
- cumulative market coverage of the contracts, and
- efficiencies claimed by the parties (e.g. recuperation of sunk investments).330
Whereas efficiencies are to be considered on a case by case basis, the other three criteria
(exclusivity, duration, and cumulative market coverage) will be examined in turn in order
to obtain a first indication on whether downstream contracts raise barriers to entry. In the
present context the intention is not to spell out in which circumstances such contracts may
be incompatible with Articles 81 and 82, but to ascertain whether from a factual point of
view new entry and expansion by other market players is made more difficult.
326
The data contains some double counting as local distribution and supply companies also supply gas to industrial
customers.
327
Suppliers with a market share not exceeding 5% are in general not considered to contribute significantly to a
cumulative foreclosure effect (De-minimis Notice, OJ of 22.12.2001, C368, p. 13).
328
European Commission, Energy and Transport Trends 2030, Update 2005, page 74.
329
See DG Competition discussion paper on the application of article 82 of the Treaty to exclusionary abuses page 42f.
Other issues that can be taken into account include: other entry barriers, the nature of the customer (key customer
justifying a market entry in its own right) and countervailing buyer power.
330
See paragraph 44 of the Commission Guidelines on the application of Article 81(3) of the Treaty [2004] OJ C101/97.
The present chapter aims at describing markets, and so deals with the first three elements. However, in the
application of Articles 81 and 82 to individual cases all four elements are taken into account.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
236
Exclusivity
(772)From the market foreclosure perspective, contractual exclusivity provisions are the most
common tools to ring-fence the customers from potential competitors throughout the
entire contractual period. These provisions may take the form of either de jure or de facto
obligations to meet the entire or most of the demand from a given gas provider.
(773)De jure obligations oblige the customer to meet its entire demand or a very high (fixed)
percentage thereof with the current supplier. De facto obligations can take a variety of
forms. They may be created through fixing past consumption levels as minimum off-take
or they may give customers an incentive (e.g. through rebates) to meet its (entire)
demand with the incumbent supplier.
(774)The analysis of Sector Inquiry replies from suppliers suggests that a substantial number of
their downstream contracts contain provisions which incite buyers to purchase (de facto)
exclusively from one supplier throughout the entire duration of the contracts. One
indication of such de facto exclusivity is the number of contracts with rebate clauses. A
rebate clause is defined as a contract clause providing for a lower price where certain
targets, such as volume thresholds, either in percentage of overall requirements of the
customer or in absolute figures have been met.331
The following table shows that the
percentage across Member States varies, between 13% in Germany and 29% in Italy.
Table 35
France Germany Italy Netherlands
Rebates 23% 13% 29% 28%
Contracts containing rebate clauses
Source: Energy Sector Inquiry 2005/2006
Note: Only yes/no replies were considered.
(775)However, de facto overall exclusivity of suppliers is likely to be much higher than
suggested by the table. As well as those resulting from rebate clauses a de facto exclusive
off-take obligation can also result from a take-or-pay clause which is close to the
customer’s foreseeable total demand. In addition, there are often technical obstacles or
obstacles in the network codes which prevent dual-supplier arrangements (for example
two metering stations may be required for a particular site). Taking the data from
customers and suppliers together, the Sector Inquiry has found that dual supplier
relationships at the final customer level are certainly not the norm and very rare in some
Member States.332
Even most local distribution and supply companies, which consume
very large volumes of gas, generally appear to have a single wholesale supplier.
Contracts which, in one way or another, oblige or incentive the customer to source a
certain share of its requirements from a single supplier will quickly lead to de facto
exclusivity.
331
Whereas the question posed to suppliers aimed at rebate clauses which contain an element of exclusivity incentive
(i.e. excluding rebates which are entirely linear), some respondents may have misinterpreted it. It is noted that rebates
can be relevant in possible abuse cases under Art. 82 EC.
332
This is of course with the exception of multi-site customers who have the possibility to choose different suppliers for
each of their sites.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
237
Duration of contracts
(776)The second important element to be considered when assessing downstream foreclosure
is the duration of contracts.333
As explained above, long-term contracts curb customer
choice and prevent the customers from choosing the best offer available on the market at
a given moment in time. On the other hand, depending on the structure of the individual
contract, in particular on the pricing formula, locking into long-term contracts may allow
the customers to better manage the risks related to adverse price movements. However,
the benefits of price security, which for certain customers may represent real value, may
not outweigh the negative foreclosure effects of long-term retail contracts on competition
and overall consumer welfare.
(777)Figure 71 shows the percentage of contracts which have been entered into for longer than
one year or for an indefinite period in a selection of Member States. The data is split so
that the first column for each country shows the length of the contract from the time it
entered into force and the second column shows the length of the contract from 1st
June
2005.334
Figure 71
A significant proportion of contracts last longer than one year* or are indefinite
0
10
20
30
40
50
60
70
80
90
100
From
entry
into
force
From
Jun 05
From
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into
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From
Jun 05
From
entry
into
force
From
Jun 05
From
entry
into
force
From
Jun 05
From
entry
into
force
From
Jun 05
%ofcontracts
Contract longer than 1 year Indefinite duration
Poland
Netherlands
France
Italy
Germany
A significant proportion of contracts last longer than one year* or are indefinite
0
10
20
30
40
50
60
70
80
90
100
From
entry
into
force
From
Jun 05
From
entry
into
force
From
Jun 05
From
entry
into
force
From
Jun 05
From
entry
into
force
From
Jun 05
From
entry
into
force
From
Jun 05
%ofcontracts
Contract longer than 1 year Indefinite duration
Poland
Netherlands
France
Italy
Germany
Source: Energy Sector Inquiry 2005/2006
Note: * Contracts for longer than one year do not include contracts for exactly one year.
(778)The chart illustrates that there are a large number of long contracts. However, there are
contrasts between Member States. Poland and Germany appear to have many long-term
contracts. In Germany, only around a quarter of contracts in June 2005 were due to expire
over the next year. The rate for Poland was even less (lower than 20%). In France and the
333
The Bundeskartellamt recently adopted a decision against long-term supply contracts in the proceedings against
E.ON Ruhrgas AG (Bundeskartellamt, 8. Beschlussabteilung, B8 -113/03 -1, 13 January 2006). The immediate
enforceability of the Bundeskartellamt decision was confirmed by the Düsseldorf Higher Regional Court (VI-2 Kart
1/06 (V), 20 June 2006).
334
For example in a purely hypothetical situation in which there are three 6 year contracts which are concluded, and
renewed, at 2 year intervals, the average contract duration one day before the expiry of one of these contracts will be
2 years (contract 1 runs for 4 more years, contract 2 for 2 more years and contract 3, 1 day before expiry and renewal
for 0 more years).
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
238
Netherlands about 60-70% of contracts were to expire within one year. For Germany, it
can be expected that the situation will improve for the customer group with the highest
percentage of long-term contracts, namely local distribution and supply companies,
following the Bundeskartellamt’s decision regarding long-term contracts in Germany for
supplies to regional and local distributors.335
(779)Figure 72 illustrates the percentages of contracts which will last for: less than one year,
one to two years, two to three years, three to five years and longer than five years.336
It
illustrates that there are very few contracts of less than one year and many contracts of
five years or longer.
Figure 72
Many contracts are concluded for five years or longer
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
France Germany Italy Netherlands Poland
< 1yr 1 to < 2yrs 2 to < 3yrs 3 to < 5yrs 5 yrs or more
Source: Energy Sector Inquiry 2005/2006
(780)Figure 72 mirrors the trends illustrated in the other charts on duration where Poland and
Germany seem to have the most long-term contracts (for both Member States over 50%
of contracts last for five years or longer), and Italy significantly fewer (less than 10% of
contracts last for five years or longer). However, Figure 72 also illustrates that about 20%
of the French and Dutch contracts in our sample were concluded for five years or longer.
(781)In Italy the majority of contracts for five years or longer are with power generators. In the
other Member States represented, power generators do not dominate this set of contracts;
there are also many industrial customers and local distribution and supply companies
with contracts of five years or longer.
335
Decision of 13.01.2006 “Langfristige Lieferverträge” (Case B8-113/03).
336
Precisely the groups are as follows: less than but not equal to one year; one year to less than but not equal to two
years; two years to less than but not equal to three years; three years to less than but not equal to five years; and five
years or more.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
239
(782)Figure 73 sets out average contract durations. As the sample does not include contracts
with indefinite duration, results will tend to underestimate the effect of long-term
contracts for Poland and the Netherlands.
Figure 73
Average contract duration is too long
0
20
40
60
80
100
120
140
160
180
200
France Germany Italy Netherlands Poland
Averagecontractduration(months)
Straight Average Volume Weighted average
Source: Energy Sector Inquiry 2005/2006
(783)Figure 73 shows that for all Member States (except Italy) the volume weighted average
contract duration is over 31
/2 years. Contract duration is highest in Germany (9 years by
straight average and 15 years by volume weighted average).
(784)However, the available data also shows that average contract durations have declined
since 1998, indicating an effect of the liberalisation of gas markets. For example, in
Germany the average contract duration for contracts concluded after 1998 decreased to
around 6 years for power generators and LDCs (which is nevertheless still a very high
value), and to around 3 years for industrial customers (by straight average).
(785)Tacit renewal clauses may have a similar effect to indefinite contract periods as the
possibility of tacit renewal seems to have a chilling effect on customers’ switching
behaviour. It is important to consider that any foreclosure effect linked to tacit renewal
clauses comes on top of the foreclosure effect stemming from the contract durations
themselves.337
337
Of course, this effect will be stronger with unsophisticated buyers than with sophisticated.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
240
Figure 74
Tacit renewal of contracts is common
0
10
20
30
40
50
60
70
80
90
France Germany Italy Netherlands Poland
%contractswithtacitrenewal
By number of contracts By Volume
Source: Energy Sector Inquiry 2005/2006
(786)The data from suppliers suggests that the majority of contracts have provisions for tacit
renewal. Figure 74 shows that tacit renewal is more common in Member States that in
general have long-term contracts such as Germany and Poland. Whilst in France and Italy
the proportion of contracts with tacit renewal varies considerably depending on which
measure is used (number of contracts or volume of gas covered by contracts).
(787)A notice period is another time-related element which has to be considered when
assessing the duration of contracts. The possibility to terminate a contract would seem to
allow a customer, at least in principle, to look for alternative suppliers. However, other
elements need to be taken in account in order to get a full picture. For example, some
contracts may include incentives not to make use of early termination opportunities or
contracts may include obstacles to effectively exercising the possibility to terminate the
contract. A long notice period significantly increases the obstacles to switching, as any
potential benefits will only be realised at a much later date. This creates uncertainty for
the buyer and a potential new supplier. This uncertainty will have a price-wedge effect
creating risk premiums both on the demand and supply side. Therefore, a lengthy notice
period lowers the likelihood of successful switching.338
338
Again, this effect will be stronger with unsophisticated buyers.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
241
Table 36
Notice periods in percentage: France Germany Italy Netherlands Poland
No option for early termination 67% 2% 33% 78% 0%
1 month or less 29% 3% 12% 0% 0%
More than 1 month but less than 3 months 4% 23% 51% 10% 6%
More than 3 months but less than 12 months 0% 56% 5% 12% 28%
More than 12 months 0% 16% 0% 0% 67%
Sample size (number of contracts) 144 218 248 91 69
Notice periods are often long
Source: Energy Sector Inquiry 2005/2006
(788)Notice periods give an indication of the extent to which customers are able to switch gas
supplier339
. In Germany 16% of contract have notice periods of above one year and
almost 60% of contracts have notice periods of between three months and one year.
Whilst in Italy 50% of contracts have notice periods of between one and three months
allowing customers to switch more easily. Poland has particularly long notice periods
with an average of 25 months.
Cumulative effect
(789)The final element to be considered in the foreclosure analysis is the cumulative market
coverage of the bundle of contracts. The gas market is characterised by a high level of
maturity, which manifests itself in a relatively low number of new connections to the
network as compared to the total number of customers. Therefore, the bulk of new clients
can only be recruited among the already existing customers by means of offering lower
prices and/or better terms and conditions of sales. However, in order to profit from a
competitive offer, the existing customers must be first free to switch suppliers.
(790)If a large part of demand or the commercially most attractive key customers are tied by
long-term contracts, this leads to the situation in which the new entrant suppliers are
effectively foreclosed from the market. The prevalence of de facto exclusivity of
suppliers and the cumulative effect of long-term contracts, indefinite duration contracts
and tacit renewal clauses in contracts combined with a long termination period give rise
to concerns in many Member States analysed. These factors mean that customers do not
return to the market for years in some Member States, which makes it very difficult for
entrants to pick up new customers. The exception to the rule is Italy where the notice
periods are generally very short due to regulation. Concerns are low to medium in the
Netherlands and in France. However, for Germany and Poland the available data leads to
very high foreclosure concerns.
Restrictions on how customers dispose of their gas can limit competition
(791)Market performance is generally improved when customers are free to dispose of their
gas in the most efficient manner. Industrial customers and power plants may wish to
manage a gas portfolio covering several plants and/or be free to trade their gas (simply to
dispose of excess gas or as part of a more sophisticated gas management strategy). Local
339
A short notice period may be necessary for technical reasons such as metering or communication purposes.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
242
distribution and supply companies may wish to sell their gas both within and outside their
normal business area.
(792)The freedom to dispose of the gas can be limited by contractual restrictions, such as use
restrictions or destination clauses. A use restriction prevents or restricts the buyer from
using or reselling the gas purchased for anything other than the specified purpose. The
clause may take a variety of forms: exclusively restrict the use of gas to one purpose or to
one site; prohibit resale of gas; allow resale only back to the original supplier or against a
fee; or allow resale only upon written permission. Destination clauses, similarly, prevent
or restrict the customer from freely reselling the gas purchased from the supplier, e.g.
outside a certain area.
(793)The freedom to dispose of the gas can also be hampered by certain delivery practices. A
customer should theoretically be able to take delivery of the gas at a variety of different
points, which could include, for example, at its consumption site, at the connection to the
TSO’s network, on a gas hub (physical or virtual), or on other important nodes on
transmission networks. This choice leaves the customer with the possibility of choosing
where the gas will subsequently flow. When a customer is limited in its choice of
delivery point, this can lead to practical problems to resell the gas, to buy gas from other
suppliers or to otherwise manage its gas supply portfolio. While this additional flexibility
may, in some cases, involve additional costs for the supplier, there are no general
functional constraints on the supplier not to comply with such a wish by its customer340
.
(794)All these kinds of contractual restrictions and limitations hinder arbitrage and will,
therefore, enable a given supplier to price discriminate between its individual customers.
Since power generators, distribution networks and large industrial customers receive
large quantities of gas, their ability to trade that gas, if they so choose, would contribute
to hub liquidity and potentially bring more gas to the wholesale market.
(795)The Sector Inquiry has identified use restrictions/destination clauses in a significant
number of contracts spread across the EU. The data presented below for a selection of
Member States is based on data provided by suppliers. The values for the Netherlands
and Poland are particularly high while, judging from a more limited sample of industrial
customers responses, these figures appear somewhat on the low side for Italy, France and
Germany.
340
Different Member States have different regulatory structures, there may be a need to re-configure grid rules in order
for re-delivery to be possible. See COMP/M.3868-DONG/Elsam/Energi E2, paragraph 360.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
243
Figure 75
Use restrictions and destination clauses are prevalent in downstream
contracts
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
France Germany Italy Netherlands Poland
%ofcontractswithuserestrictions/destination
clauses
By number of contracts By volume
Source: Energy Sector Inquiry 2005/2006
(796)The Sector Inquiry has looked at the delivery practices mainly in relation to industrial
customers. For customers with several consumption sites it can be of particular interest to
be able to divert gas between plants, but also other customers may wish to increase their
flexibility by reselling the gas under their main contract and/or purchasing additional
short-term gas. Naturally, it will mostly be larger customers that have an interest and an
ability to arrange their own transport and/or trade in gas.
(797)In order for a customer to have a real freedom when it comes to diverting or reselling gas,
it is not sufficient that there is a choice as regards the delivery point. As discussed above,
there must also be no contractual restrictions (use restrictions/destination clauses)
preventing the customer from managing its gas. Moreover, the regulatory burdens must
not be so heavy that the customer is de facto unable to trade on the market (when the
volumes are limited and traded only occasionally, the administration will easily become
dissuasive). Furthermore, transport services must be separately and transparently
available.
(798)Whereas a majority of customers will clearly find it practical to have deliveries made to
their site of consumption, at a competitive “all-inclusive” price, it is essential that the
system is designed in a manner that can also encourage efficiencies for those customers
who are interested in more actively managing their gas supplies.
(799)It appears from the Sector Inquiry that an overwhelming majority of industrial customers
take delivery at their site of consumption (in many cases corresponding also to the
connection to the TSO network). However, it also appears that a number of big industrial
customers are interested in the possibility of alternative delivery points. Several of these
customers also consider that there is an active supplier policy in limiting their choice of
delivery point, as well as practical obstacles hindering them from managing their gas.
Such a pattern emerges most clearly in the Netherlands and Germany, whereas the
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
244
statistical sample assessed in relation to other countries makes it more difficult to draw
clear conclusions.
(800)In the Netherlands, a majority of industrial customers responding to the Sector Inquiry
point to problems relating to delivery points. Several of these customers indicate a
supplier policy of limiting the choice of delivery points and, in particular, an
unwillingness to deliver gas on the hub (TTF). The customers point out that this is
reinforced by an entry/exit system on the network that leads to double entry/exit charges
and transport costs, which make it economically not viable to resell or divert the gas. The
rules regarding exit capacity (the need to contract long-term or arrange a transfer of exit
capacity), as well as a heavy shipper regime (including the risk of imbalance payments),
are also indicated as reasons why the customers are unable to manage their gas as they
would wish. When combined with the widespread use of contractual use
restrictions/destination clauses that are imposed on many customers, a picture emerges of
customers without any real choice when it comes to diverting or reselling gas.
(801)In Germany, there are also many large industrial customers that point to problems relating
to the delivery point. Whereas some customers point to a practice of explicitly limited
delivery points, many others comment on the practical impossibility of making use of the
network system. All-inclusive contracts for delivery at the consumption site are the norm,
and transport costs are not usually specified separately on the bills when purchasing gas.
Many customers point to the difficulties in organising their own transport, which is
considered very complex, non-transparent and with a chronic lack of capacity. The costs
of separate gas and network usage also risk being higher than the “all-inclusive” price.
The contractual use restrictions/destination clauses that are imposed on many customers,
further limit the choice of customers to divert or resell gas.
(802)Industrial customers in several other Member States also point to explicit policies of
limited delivery points. Considering the widespread practice of delivering gas at “the
factory gate”, the many critical responses in relation to lack of transport capacity and
transparency, the still quite common use of “all-inclusive” pricing and the fairly common
practice of contractual use restrictions/destination clauses, it is clear that the customers’
freedom to dispose of their gas is generally limited.
Conclusions
The degree to which customers are tied to incumbent suppliers on a long term basis differs
significantly between Member States. In some countries, the duration of retail contracts with
industrial customers and of contracts to local distribution and supply companies may have a
significant impact on the possibility for alternative suppliers to successfully enter the market.
The cumulative effect of long contract durations, contracts with indefinite duration, contracts
with tacit renewal clauses and long termination periods can be substantial.
Restrictions on how customers can dispose of their gas, in combination with restrictive
practices by suppliers regarding delivery points, limit competition and prevent efficiency
gains by these customers.
Customers demand more competitive offers by non-incumbent suppliers and regret the
absence of pan-European supply offers.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
245
II. Balancing in gas market
Preliminary remarks
(803)Balancing requirements and the mechanisms for determining the price and availability of
balancing services constitute an essential element of EU gas markets. The Preliminary
Report of the Energy Sector Inquiry, while containing remarks on related issues such as
storage, did not analyse balancing markets. However, answers received to the Sector
Inquiry questionnaire emphasise that balancing and nomination rules were perceived to
result in discrimination by suppliers, to the advantage of the incumbent.
(804)This chapter will analyse gas balancing in greater detail. It reflects the answers to DG
COMP’s Energy Sector Inquiry questionnaire and is limited to 9 Member States,
including both “old” Member States (Austria, Belgium, France, Germany, the
Netherlands) and “new” Member States (Czech Republic, Hungary, Poland and
Slovakia). Obviously, changes have occurred since the answers were received, in 2005.
Whenever possible, such modifications have been taken into account.
(805)In all MS network access rules are established to encourage users to balance the amount
of gas being injected into the network with the amount being withdrawn by their clients.
If this is not the case, the network user is said to be “out of balance” and will be required
either to buy gas from, or sell gas to, the TSO. The balancing mechanism therefore
constitutes an ultimate default “market” where shippers can buy and sell gas. The
operation of the balancing mechanism will therefore affect all other parts of the
wholesale market.
(806)Often the calculation of the imbalances will be done on the basis of individual “balancing
zones” which are smaller than the TSO’s area. Balancing zones exist for a variety of
reasons: technical necessities of pressure and congestion management341
, differences in
gas quality342
, administrative reasons (operational and ownership ‘reach’ of a TSO) and
applicable regulatory rules343
. Balancing zones can be composed of a single pipeline or of
a complex network/grid/system of pipelines.
(807)In each zone, every shipper is encouraged to balance the gas injected into the network and
the gas withdrawn from it. The balance of a shipper’s injections and withdrawals is
controlled for quantities of gas measured hourly (hourly balancing) or daily (daily
balancing)344
. In many cases there is a tolerance range for imbalances for which shippers
are not required to make payment to the TSO for additional gas. However beyond this
zone an implicit penalty is charged. This is because the price charged by TSOs for
341
Saturation of a gas pipe prevents it from transporting as much gas as required from one part of the network to
another. The necessity to observe a minimum pressure in pipelines leads to a tendency to take such points as border
points of a balancing zone.
342
There are two main gas qualities H gas and L gas but the existence of distinct balancing zones might also result from
narrower tolerances for PCS or Wobbe index in different areas. For instance, for RWE, in Germany, gas quality
specifications differ almost in all the balancing zones.
343
Each TSO controls the balancing on its network, whatever its size, in terms of technical controls but also in terms of
administrative/accounting controls of the supply/off-take balance of each market participant. Historically, TSOs
have operated in no more than one country. Cross border integration of TSOs has also been impeded by different
regulatory set-ups in neighbouring countries.
344
The quantity can also be controlled continuously for hourly quantities cumulated from the beginning of the
contractual day with a prohibition on exceeding a certain level of imbalance , and penalties attached in case of
cumulative excess imbalance (cumulative hourly imbalances).
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
246
“selling” gas to shippers who are out of balance (due to having put less gas on the system
than has been taken out by them or their customers) is higher than the reference market
(e.g. 150% of that reference price). Whereas the price paid by the TSO in the case of too
much gas being injected by a shipper is lower than the reference market price (e.g. 50%
of that reference price).
(808)Pursuant to Directive 2003/55/EC of 26 June 2003, terms and conditions for the provision
of balancing services should be non-discriminatory and cost reflective and approved by
the regulatory authorities345
.
II.1. Balancing zones are too small and too numerous:
this hinders competition and the creation of a single market
(809)The following table indicates the number of balancing zones for the TSOs operating in
the 9 countries.
Table 37
Country TSO
H L
Austria (1) OMV 1
Belgium Fluxys 3 1
Czech Republic Transgas 8
France GRTgaz * 4 (1)
TIGF 1
Germany BEB ** 1 1
RWE 4 5
E.ON Ruhrgas 3 1
Wingas 4
Hungary MOL 1
Netherlands GTS * (1) 1
Poland Europol 1
Slovakia SPP 1
Number of zones
Number of balancing zones in 2005
Source: Energy Sector Inquiry 2005/2006
Notes: (1) Excludes transit pipelines and two very small zones in the west of Austria, isolated from the OMV
zone (but connected to German zones).
* For GRTgaz and GTS, high calorific H gas and low calorific L gas have to be balanced
separately, which is equivalent to having two balancing zones.
** BEB also has an “LL” (very low calorific) balancing zone, very limited in size, for gas with
calorific value lower that L gas calorific value.
345
Article 8(2) “Rules adopted by transmission system operators for balancing the gas transmission system shall be
objective, transparent and non-discriminatory, including rules for the charging of system users of their networks for
energy imbalances. Terms and conditions, including rules and tariffs, for the provision of such services by
transmission system operators shall be established pursuant to a methodology compatible with Article 25(2) in a
non-discriminatory and cost-reflective way and shall be published.”
Article 25(2) “the regulatory authorities shall be responsible for fixing or approving prior to their entry into force,
at least the methodologies used to calculate or establish the terms and conditions for […] (b) the provision of
balancing services.”
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
247
(810)In Figure 76, each square represents a zone and its surface is proportional to the
maximum daily flow recorded for the period 2004-2005, which is an indication of the
importance of the consumption in the zone. The hugely differing sizes of the squares
indicate the vast differences in sizes of balancing zones.
Figure 76
GTS
MOL
Fluxys
GRTgaz
TIGF
OMV
SPP
Transgas
RWE
BEB
E.ON-Ruhrgas
Wingas
Size of balancing zones
GTS
MOL
Fluxys
GRTgaz
TIGF
OMV
SPP
Transgas
RWE
BEB
E.ON-Ruhrgas
Wingas
Size of balancing zones
Source: Energy Sector Inquiry 2005/2006
Note: For E.ON –Ruhrgas and for Wingas it is assumed that the different zones are of equal size, as the
corresponding data were not available.
(811)It appears that the ratio between the smallest zone and the biggest is 1 to 278. If
correction is made for the smallest zone, corresponding to a specific “LL” gas situation,
and the largest zone, for which the part of transit gas is important, the ratio is still around
1 to 40.
Small balancing zones are a significant barrier to competition
(812)In the answers to the Sector Inquiry, the size of the balancing zones is a major complaint
of the network users. Small balancing zones correspond to smaller portfolios in these
zones resulting in higher risks of imbalance and onerous penalties.
- The existence of different zones implies the presence of barriers to operate across zones;
fragmentation of zones multiplies such barriers
(813)Balancing zones in themselves increase the complexity of shipping gas from one point to
another in Europe resulting in higher costs. Imbalances, if they exceed a certain tolerance
level, are sanctioned by penalty payments collected by the TSOs. Along a certain path,
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
248
the addition of such payment risks due to the existence of several balancing zones
increases overall costs and risks for shippers.
(814)Even in the absence of any imbalances, administrative and transaction costs are increased
by the number of usually highly complex and divergent rules along the path which a
shipper has to absorb. Barriers are also created by the obligation to reserve capacity at
each border point when gas enters or leaves a balancing zone. At theses points shippers
are subject to the constraints of capacity allocation mechanisms. This effect is obviously
larger when the number of different balancing zones and balancing regimes which exist
along a certain path are higher. It is important for a new supplier, operating only on
distribution networks, to be able to avoid balancing costs. This might be achieved by, for
example, purchasing its gas at the transmission network exit point.
(815)Unequal costs for balancing between incumbents and newcomers, and the resulting
distortions of competition, have also been pointed out as a substantial impediment to new
entry within certain zones. In addition, several shippers have stated that significant
differences in the rules between zones, including the time element of balancing rules, are
a material deterrence to transporting gas along certain routes. Overall, if such differences
are not objectively justified the resulting deterrence will unnecessarily weaken the overall
responsiveness of the European gas network to short term cross border shifts in demand
and supply. This will result in an inefficient use of the overall European infrastructure.
- These barriers are higher for newcomers and for small companies
(816)Imbalances are mainly due to uncertainties in forecasts. Most network users state in their
replies that the risk of imbalances is greater when the portfolio of clients is smaller. This
is because risks are partly neutralised between clients and the diversification of clients
smoothens the global profile of consumption, making it less sensitive to forecasting
errors due to climate or other consumption uncertainties. The division of a network in
balancing zones results in a decrease of the size of the portfolios and increases problems
for new suppliers whilst favouring incumbents. This is a major barrier for newcomers.
(817)In addition, administrative and transaction costs are fixed costs and are therefore greater
when they have to be spread over small quantities of gas. Multiple zones therefore
increase the cost of entering the market.
- Partial remedies are insufficiently effective
(818)A shipper transporting gas in different balancing zones, operated by the same TSO, is not
always subject to the same constraints. In some cases, it is possible to balance between
balancing zones of the same TSO. This may be possible under certain conditions such as
if cross-zonal capacity is available and by paying cross-zonal entry and exit fees
(GRTgaz in France, Fluxys in Belgium, E.ON Ruhrgas in Germany). Such possibilities
reduce the risk of a penalty for being out of balance, but the management cost of
balancing and the cost of crossing zones must still be paid.
(819)Differences in gas quality are in effect barriers to exchanges between zones. To alleviate
the constraints, conversion facilities can be used, either virtual (through swaps) or
physical ones. However, such partial remedies are currently insufficiently developed.
Vertically integrated TSOs have limited interest in facilitating entry into their supplier’s
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
249
incumbency area. Barriers also remain high if the conversion facilities exist but are either
too costly or managed in an inflexible, cumbersome way.
II.1.1. Differences in balancing rules – hourly balancing is a barrier to entry
(820)Shippers have to ‘nominate’ the quantities they expect to sell (i.e. their network off-take)
and the quantities they will make available to balance these sales (i.e. their network
input). These nomination procedures will be discussed below (see below, section 4 of this
Chapter).
(821)Subsequent to nomination, various circumstances, such as a difference between the
forecasted and the real temperature, will create discrepancies between the nominated
quantities and the actual ones, creating imbalances.
(822)The network operator has an obligation to balance the sum of all such deviations in order
to guarantee network stability. Technically the pressure in a network should not drop
below a certain point and the entry capacity of the network is limited by the maximum
pressure. The network operator thereby encounters certain balancing costs (see below
section C.b.II.3).
(823)These costs ultimately need to be borne by those causing them, i.e. the shippers whose
network input and off-take is in imbalance. However, shippers do not only have to bear
the mere costs of this balancing service performed by the TSO for them. Imbalances
larger than the tolerance band also usually include a penalty element to deter the shippers
from taking actions detrimental to the network.
(824)Before discussing the level of these balancing charges (see below section 3), two
important criteria for measuring the charges need to be discussed. These are (i) the timeperiod
against which any such imbalance is measured and (ii) the level from which a
deviation is considered to be detrimental and therefore justifying a penalty (tolerance
level).
Time period: Hourly balancing is a barrier to entry of new suppliers
(825)The time period relevant for measuring imbalances varies across TSOs. The imbalance
may be measured at the end of the hour or at the end of the day, or both (or, rarely, even
at the end of a longer period). Imbalances can also be measured during certain periods,
e.g. instead of measuring the imbalance (only) at the end of the hour and at the end of the
day (each imbalance for each hour and each day triggering penalty payments) there can
also be, additionally or alternatively, a control of the cumulated hourly imbalances during
a day. Under this system, the cumulated hourly imbalance intra-day must not exceed a
certain tolerance level any time during the day.
(826)The Sector Inquiry has shown that the practices of TSOs are far from uniform and that
this is felt to be an obstacle to entry by shippers, in particular when hourly balancing is
required.
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250
Table 38
Hourly imbalances Daily imbalances Monthly imbalances
Not cumulated
OMV
Fluxys
BEB
RWE
E.ON Ruhrgas
Wingas
GTS
Fluxys
Transgas
GRTgaz
TIGF
MOL
Europol
SPP
Transgas
Cumulated
Fluxys
BEB
GRTgaz
TIGF
Balancing practices
Source: Energy Sector Inquiry 2005/2006
Note: Most TSOs combine hourly (or daily) imbalances with hourly (daily) cumulative imbalances, which
means that multiple penalty payments are possible. e.g. Fluxys cumulate three levels of imbalances.
(827)The problems related to the spatial division of balancing zones also apply to the time
division of the balancing mechanism: the smaller the division, the smaller the quantities
involved and the higher the risk of imbalance. Several suppliers stated in their replies that
they had been deterred from entering certain markets because of their hourly balancing
requirements. Hourly balancing in itself is felt to be a barrier to new entry of newcomers
as it requires a very accurate follow up of the flows346
. For a newcomer with a small
portfolio the necessary management and organisation is very significant. It requires very
accurate forecasts which are particularly difficult for clients whose consumption is
strongly influenced by temperature. It also requires good information on the measured
quantities consumed by clients to be fed back to shippers in a timely way. The risk of
imbalances is especially high on the temperature-sensitive domestic consumer market,
but the effects are not seen as limited to this market.
Tolerance provisions
(828)The level of tolerance, that is the limit of the non-penalized imbalance, is of crucial
importance for a shipper’s balancing costs. Values are given in the figure below and
range from 0% of the hourly capacity (for OMV) to 50% for small portfolios in the
Netherlands. Tolerances differ according to the size of the portfolio on the GTS, Fluxys,
GRTgaz and TIGF networks. The fact that tolerances are more favourable for small
portfolios responds to the needs of smaller suppliers, particularly if imbalance charges are
punitive.
346
Including during the night.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
251
Figure 77
Hourly tolerance vs portfolio size
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
55%
0 10.000 20.000 30.000 40.000 50.000 60.000 70.000 80.000 90.000 100.000 110.000 120.000 130.000 140.000 150.000 160.000 170.000 180.000 190.000
Size of the portfolio (MWh/day)
Tolerance
(percentageofhourlyexitcapacities)
E.ON Ruhrgas hourly tolerance
BEB and Wingas hourly tolerance
GTS hourly tolerance
Fluxys hourly tolerance
Source: Energy Sector Inquiry 2005/2006
Figure 78
Daily tolerance vs portfolio size
0%
5%
10%
15%
20%
25%
0 10.000 20.000 30.000 40.000 50.000 60.000 70.000 80.000 90.000
Size of the portfolio (MWh/day)
Tolerance
(percentageofdailyexitcapacity)
GTS daily cumulative tolerance
Fluxys daily tolerance
GRTgaz and TIGF daily tolerance
E.ON Ruhrgas daily cumulative tolerance
Fluxys daily cumulative tolerance
Source: Energy Sector Inquiry 2005/2006
Note: Daily tolerance is the level that should not be exceeded at the end of the day; daily cumulative
tolerance is the level not to be exceeded any time during the day; it is then more stringent than the daily
tolerance.
II.2. Balancing charges are non-transparent and favour incumbents
(829)All the network users indicate that they could not say if balancing costs are cost reflective
or not, which proves at least that these costs are not transparent. Some shippers add that
the penalty level is calculated for the worst case scenario rather than actual costs and is
too costly for normal situations.
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252
(830)Balancing charges contain two components, namely:
• a clearing cost, for the TSO’s buying or selling the gas necessary to rebalance the
system when the shipper is out of balance, and
• penalties if the shipper exceeds the tolerance.
Of these, it is only the first component which can be cost reflective. It is usually linked to a
published market price, without verification whether this choice is justified.
II.2.1. Clearing costs are not cost reflective;
this leads to an increased risk of cross subsidisation
(831)As the imbalances are mainly due to uncertainties in forecasts, seen over a long period,
the excess quantities and deficits should level out. The cost of balancing over a long
period is therefore mainly a cost of flexibility, and not a cost of gas quantities. However,
in the short term, a certain amount of gas is needed by the network operator in case the
majority of shippers underestimate demand at the same time. Also, a certain amount of
gas off-take capacity is needed in reserve in case the majority of shippers at a given date
over-estimated demand.
(832)TSOs first react to imbalances with so-called ‘line pack’ (i.e. with varying the pressure
level in the pipelines). They subsequently have to revert to the normal line pack pressure
again or allow it to drop back to the normal operation pressure. TSOs may profit from the
fact that, in practice, the deviation of one group of shippers is often neutralized by the
opposite deviation of another group of shippers. The process could be largely simplified,
and hence made less costly, if the network operator’s balancing action was restricted to
the residual deviation. However, in fact, on top of this role, it often acts as a trader: if
shipper A and shipper B on a given day (or hour) level out, the TSO nevertheless buys
gas from the shipper in excess and sells it to the shipper in deficit whereas A and B could
have exchanged their imbalances (excesses and deficits) either directly or through an
actual trader (e.g. via an internet trading platform).
(833)In any event, even if such direct exchanges between shippers are developed, at the end of
the balancing period the gas supplied or received by the TSO (i.e. the gas in deficit or
surplus on the network) will have to be traded, at a clearing cost that should:
1) reflect the cost for the TSO, to avoid subsidies from transmission activity to balancing
service, or vice versa, or from balancing services to trading, supply or storage, and
2) reflect market conditions, to prevent the shippers from speculating on differences
between the TSO tariff and the market price and in order to minimize the volumes
traded by the TSO.
(834)The first way to achieve these two goals is that the TSO buys (or sells) its gas on the spot
market when it needs it, on a day to day procurement basis. This solution ensures that
every day the price reflects market conditions, which also contributes to developing
market liquidity. However, as a minimum, this requires market organisation and liquidity
to ensure the price is fair. If the market place is not sufficiently liquid then the vertically
integrated company can, by exerting market power, increase its gas procurement costs.
By contrast, if liquid reference markets exist only outside the TSO’s grid, then transport
costs to and from such liquid markets will arise. The TSO may profit from such costs by
charging exit and entry capacity on its network.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
253
(835)The second tool available to the TSO is longer term gas procurement. The TSO anyhow
buys gas for its own needs, in particular for fuelling compressors or for creating line-pack
in new pipes. The TSO also requires some flexibility, since the compressor needs are not
constant over the year. This flexibility or an extra flexibility in the contract could be used
for balancing. However, this leads to the problem, highlighted by respondents to the
Sector Inquiry, that to date, these gas procurement contracts are usually signed with the
incumbent supplier (often the affiliate of the TSO), in a non transparent way347
.
Obviously such intra-group procurement opens the door to risks of cross subsidisation.
(836)The third possible source of gas for balancing is underground storage. As imbalances
result from uncertainties for all shippers, the total of these uncertainties over a year
should be close to zero. The quantities of gas sold by the TSO should, over the year, be
equivalent to the quantities of gas bought; the gas purchased could be stored and the gas
sold extracted and the stock level at the end of the year would be the same as at the
beginning. However, this entails a particular problem, linked to the working of gas
storage facilities. In order to achieve the required withdrawal capacity from the storage
facility, a certain amount of gas has to be injected since the withdrawal capacity increases
with the amount of gas stored. While this perfectly corresponds to the cyclical seasonal
modulation needs of suppliers it does not fit the TSO’s short-term needs for flexibility348
.
In order to achieve its required withdrawal capacity the TSO would therefore need to
store a large amount of gas which it would never use and which would freeze a
disproportionate amount of the storage capacity. This is costly and uneconomic when
underground storage capacities are scarce349
. If the TSO and the storage operator belong
to the same vertically integrated group, this also opens the door to issues of cross
subsidization. As in the absence of any meaningful procurement procedure, there is no
guarantee that the price of the gas and of the flexibility correspond to a market price.350
(837)Generally, the cost of balancing through contract flexibility and storage appear to be in
the range of 2% of the transmission charges. In addition, the TSOs incur costs for staff
and equipment necessary for balancing management and accounting. However, it should
be possible to keep these costs sufficiently low so as not to act as a major barrier to the
development of gas supply and transport/transit markets, unless the number of zones is
inflated as discussed above. The main impact of balancing on competition and the
opening of the gas market therefore appears to arise not from these pure and objective
cost factors. Rather balancing tends to distort competition due to a bundle of factors.
Most importantly incumbents’ cross subsidisation. But also, so called “pancaking” costs
for customers arising from geographical multiplication of zones and (hourly)
fragmentation of balancing periods in addition to elevated penalty levels.
347
Although article 8(4) of the Gas Directive specifies “Transmission system operators shall procure the energy they use
for the carrying out of their functions according to transparent, non-discriminatory and market based procedures.” It
should also be noted that TSOs are subject to Directive 2004/17/CE of 31 March 2004 coordinating the procurement
procedures of entities operating in the water, energy, transport and postal services sectors.
348
This constraint is less important for salt cavern storages, but the delay for withdrawing all the gas stored is still of 2 to 3
weeks.
349
A solution to this problem might lie in the fact that some purchasers require less withdrawal and injection capacity than
the amount of gas stored by them actually would permit. Such users could directly or indirectly “sell” their excess
withdrawal and injection capacity to the TSO on the secondary market. However, it is likely that for extreme
temperatures large imbalances are likely and no excess withdrawal capacity is available.
350
As a fourth source for balancing gas LNG storage (including peak shaving facilities) can be mentioned. The limitation
of this tool is that it does not allow physical re-injection.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
254
II.2.2. Penalty levels
(838)The existence of an imbalance at the end of the day (or of the hour in case of an hourly
balancing) jeopardises the network operation by, for example, reducing or increasing
network pressure beyond safe limits. The evaluation of the threshold over which a
penalty is due is non-transparent. It has been suggested that transparency obligations
require the TSOs to publish technical and/or economic justification for such thresholds
above which they charge penalties.
(839)Where a penalty charge exists, this is usually designed not only to reflect costs, but also
to deter shippers from taking positions that jeopardise network operation. Unfortunately,
it is difficult to draw a line between what is deterring imbalance and what is deterring
market entry.
(840)The total amount of penalty payments due to imbalances is relatively small as compared
to the payments for reserving capacity on the network. Still, for a single shipper, such
amounts can be very high. The ratio of total penalties for imbalance as compared to total
network charges reached 14%, 18% and 23% on one particular network.351
For another
network, the same ratio is recorded as being for most shippers in the range 1% to 2%.
(841)The following tables show the ratios of imbalance penalties paid by shippers compared to
the total network charges for two TSO networks. These ratios were calculated from data
received in the context of the inquiry and the tables retain only the shippers who paid
penalties and the incumbent on the corresponding networks.
Table 39
Shipper Ratio
Shipper 1 23%
Shipper 2 18%
Shipper 3 14%
Shipper 4 9%
Shipper 5 9%
Shipper 6 5%
Shipper 7 5%
Shipper 8 2%
Shipper 9 2%
Incumbent 0%
All imbalanced shippers 2%
Total penalties for imbalances as compared to total network charges
TSO "A"
Source: Energy Sector Inquiry 2005/2006
351
Many complaining remarks concerning this system were received in the Sector Inquiry. Subsequently the balancing
system has been amended.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
255
Table 40
Shipper Ratio
Shipper 1 2%
Shipper 2 2%
Shipper 3 1%
Shipper 4 1%
Shipper 5 1%
Shipper 6 1%
Shipper 7 1%
Incumbent 0,01%
All imbalanced shippers 1%
Total penalties for imbalances as compared to total network charges
TSO "B"
Source: Energy Sector Inquiry 2005/2006
(842)For TSO A, even if the revenue from penalties is low as compared to the total revenue of
the operator, it appears that these penalties are very high for some shippers. This is a
strong deterrent from operating on the TSO A’s network, all the more as their main
competitor, the incumbent, is not affected by this additional cost.
(843)For TSO B, the level of penalty is lower for all shippers compared to TSO A. The
difference between the new entrants and the incumbent mainly shows the advantage due
to the size of the portfolio as regards balancing.
(844)The common denominator between situation A and B is therefore that in both scenarios
the incumbent has a degree of competitive advantage.
In Figure 79 we have compared penalty levels between TSOs.
Figure 79
GTShourly
Fluxys(1)
GRTgaz
TIGF
BEB
mayto
september
GTSdaily
Fluxys(2)
Fluxys(3)
Wingas
Ruhrgas
RWE
BEB
january
february
Penalty levels as compared to market price
0,0
0,5
1,0
1,5
2,0
2,5
3,0
3,5
4,0
market price
penalized price for gas in excess
penalized price for gas in deficit
penaltyfordeficitnotlinkedto
gasprice
Source: Energy Sector Inquiry 2005/2006
Note: The penalty level is equal to the clearing price plus the penalty.
For Fluxys, the penalties are different if the imbalance is more than the tolerance (Fluxys (1)), more
than twice the tolerance (Fluxys (2)) or more than three times the tolerance (Fluxys (3)).
For MOL the penalty is not proportional to the gas market price but is equal to 0,0004 €/MJ.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
256
(845)Figure 79 shows that the differences between TSOs are considerable. Some TSOs charge
up to 3 times the reference market price for gas in deficit while others only charge the
market price plus 50%. The differences for excess gas appear less striking but indeed also
vary considerably between 40% penalty (reimbursement at 60 % of market price) and 80
% penalty (reimbursement at 20 % of market price).
(846)While penalty levels are to deter shippers from taking positions that jeopardize the
network operation, imbalance charges should not in general increase the TSOs’ profits.
Therefore, the level of the penalty is often deducted from the transmission tariff later on.
However, considering the market shares, this means that it is mostly the incumbent who
profits from this rebate. For TSO A and TSO B of paragraph (841) it was calculated that
90% of the penalties would benefit the incumbent suppliers, who pay no penalties or only
very limited amount and pay most of the transmission charges. While a shipper with a
(transmission) market share of e.g. 2% in certain area may pay e.g. 20% of the total
penalties, it will only be "reimbursed" through a rebate on its transmission tariff for its
2% transmission market share (the rebate being derived from a financial surplus of the
TSO on its balancing activities). By contrast a shipper with 90% market share who may
pay next to no penalties will be reimbursed for much more out of the same title, namely
45 times more for its 90% (transmission) market share. Therefore the majority of the
TSOs' balancing surpluses will go into the incumbent shipper's pocket (often belonging to
the same vertically integrated groups).
II.2.3. Imbalance trading could significantly reduce balancing costs; the absence of
access to short term liquidity aggravates the problem
(847)Respondents to the Commission’s Sector Inquiry have underlined that in order to save
costs for shippers (both clearance costs and penalty costs), priority should be given to
direct balancing between the shippers. Of great benefit to reducing imbalance payments
would be adapting the balancing rules to exchanges. Exchanges could allow easy access
to short term gas liquidity (for both buying and selling gas) or to exchange mechanisms
allowing a shipper to sell its surplus gas to another shipper. The widespread absence of
such liquidity was highlighted by market participants as a major obstacle to overcoming
the barriers associated with the balancing regimes. The functioning of such “imbalance
avoidance system” is of course only possible if there is a liquid market place in the
balancing zone in question. Clearly the smaller the balancing zone, the less liquid the
market for trading away imbalances is likely to be.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
257
II.3. Nomination rules are fairly uniform in the countries analysed;
further harmonisation is possible and expected;
the quality of information provided to shippers is crucial.
(848)For an efficient operation of the network, the TSOs need to know in advance the forecast
quantities of gas that will be injected into the network or taken out of it. The shippers
transmit their forecasts to the TSO for the next day following a nomination procedure.
(849)In some Member States, under certain conditions, shippers are not obliged to nominate. In
theory, this applies to all the shippers. In fact, however, the conditions are met only by
the incumbent and such measures are perceived by new entrants as discrimination in
favour of the incumbent. Apart from this problem, in most of the network users’ answers,
nomination procedures were not considered as a major obstacle to access the network (in
the countries concerned by this chapter). However, some network users regret the lack of
harmonization of the rules352
. In particular, the absence of standardised communication
tools and standardised templates for electronic messages was deplored.
(i) The nomination and re-nomination process
(850)The first stage of nomination is nominating on day minus one (D-1) for day (D). For D
day all the TSOs concerned have adopted a gas day from 6 am to 6 am, except OMV,
whose gas day is from 8 am to 8 am.
The deadlines for nomination are the following:
Table 41
12:00 13:00 14:00 14:30 15:00 16:00
MOL GTS Transgas OMV SPP GRTgaz
RWE Fluxys TIGF Europol
BEB
E.ON Ruhrgas
Wingas
Nomination times
Source: Energy Sector Inquiry 2005/2006
The suppliers should then receive a confirmation of the quantities recorded by the TSO.
352
The existence of different systems of nomination was seen as an obstacle to the opening of the market by EASEE gas, a
European association where gas industry participants can discuss the harmonisation and simplification of business
processes. Most of the TSOs participate in EASEE gas and agreed on common business practices on nomination for
implementation in 2005. Most of the TSOs quoted in this chapter comply strictly with them, some do better on some
points. (EASEE-gas common business practice 2003-002/01 "Harmonisation of the Nomination and Matching
Process").
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
258
(851)The deadline for the confirmation by the TSO is 15:00 for Transgas (i.e within 1 hour),
16:00 for GTS (within 3 hours), 18:00 for GRTgaz (within 2 hours), SPP (within 3
hours), TIGF, Wingas and E.ON Ruhrgas (within 4 hours).
(852)The second stage, for those TSOs with hourly balancing regimes, is the possibility to renominate
all along the gas day to be able to get closer to a balanced situation over the
day. This possibility exists for all the relevant TSOs, with a lead time of 2 hours, and one
hour for OMV.
(853)Some specificities per TSO exist353
but it is unclear whether they are burdensome. If they
alleviate the incumbents’ constraints disproportionately, they will have a discriminatory
effect.
(ii) Re-nomination and the feedback information given to clients
(854)Re-nomination is a flexibility tool that permits a shipper to adjust day-ahead their
estimate/nomination by an intra-day (re-) nomination.
(855)Obviously the feedback given to clients within the balancing period is important for
allowing clients to correct original estimates and limit the fall-out of incorrect estimates.
In this context, the quality and timing of information given to clients, for instance
through better access to metering data in electronic format, is of key importance. When,
during a day, a shipper realizes, through the information given by the TSO, that he is out
of balance, or risks going out of balance, he can react by modifying his nominations and
try to come back to a balanced situation. When penalties are based on hourly imbalances,
it is still possible to improve nominations for the coming hours through information
received. However, in a system of hourly balancing this has no mitigating effect on
penalties already paid.354
(856)To conclude, it appears that nomination systems per se are not seen as particularly
burdensome by network clients. However, there is clearly room for improvement, in
particular regarding harmonized nomination tools. There is some scope for discrimination
although this is not strongly perceived by market participants. The degree of competition
that is achievable by newcomers for temperature-sensitive clients will depend, to a
significant degree, on the existence of client friendly feedback systems and re-nomination
rules.
II.4. Perspectives and remedies; conclusion
(857)Although some of the criticisms expressed in the inquiry have been taken into account in
improvements to systems and procedures since mid 2005, much work remains to be done
to transform an aggregation of small independent balancing zones into a single European
network system. To achieve progress, what is most required is a de-fragmentation of the
system and a harmonization of rules and tools. A more favourable, market-based and
353
E.g. for E.ON Ruhrgas “The network operator shall be entitled to limit the maximum number of renominations per
shipper and day”. GTS can grant exemptions from the obligation to nominate for specific entry points or exit points in
a number of cases and the obligation to nominate does not apply in case GTS and the customer have agreed so in
writing.
354
At the time of the initial conduct of the inquiry, GTS was strongly criticized for this absence of timely information. In
its last procedure some of this criticism was taken into account by GTS as the inputs of an hour are balanced with
outputs two hours sooner.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
259
cost-effective environment, and in particular more market liquidity, are also necessary
prerequisites.
- De-fragmentation of the system is required
(858)The temporal and spatial fragmentation of balancing on the transportation system results
in a fragmentation of the portfolios of the suppliers, which is a bigger problem when the
portfolio is already small. This is a major obstacle for the new suppliers entering the
market. An overwhelming majority of suppliers agree on this point.
(859)The priority therefore needs to be action to suppress the physical constraints that prevent
(i) the dramatic reduction of the number of balancing zones in the European Union and
(ii) removing hourly constraints in balancing.
(860)The benefits of de-fragmentation are obvious, as they suppress a major obstacle to the
entry of newcomers. However, it is necessary to achieve this goal, which includes new
investment requirements, in a cost-effective way. Targets should be set and, where
needed, investment programs should be prepared, submitted to regulators and published.
These programmes for balancing may be integrated in those broader aims necessary to
face the growing demand for gas and to cope with gas coming from new sources. The key
principles to such balancing improvement programmes appear to be: (1) Whenever the
existence of different neighbouring balancing zones is due to congestion, the TSOs
should make these reasons clear and explain how and within which timeframe they will
solve the problem. (2) When the existence of distinct neighbouring balancing zones is
due to the existence of different gas specifications, all available means should be used to
overcome these barriers by widening, to the extent possible, permissible gas
specifications in a certain zone thus paving the way to dismantling artificial separations
of zones. (3) When the existence of different zones is due to different ownership of
networks, the conditions for effective cooperation or concentration between these
operators need to be created. (4) Cross-border mergers of balancing zones should be
facilitated, inter alia by regulatory harmonisation. (5) There should be no hourly
balancing except when hourly balancing is justified by a line-pack not sufficient to face a
strong variation of the demand during more than an hour (this could happen particularly
in case of strong load variations for gas turbines in power plants). If hourly balancing is
justified due to the demands of a few clients only (e.g. power plants), then the costs
should be attributed to the suppliers of those clients and not to all suppliers serving other
categories of clients (household, commercial and industrial customers). For those other
categories, no hourly balancing should apply.
- Harmonization of rules and, to the extent possible, gas qualities will bring cost savings
(861)The single European gas market will be all the more achievable when the rules for
nomination and balancing, including the determination of imbalance prices, are the same
everywhere.
(862)Harmonization of gas quality specifications would help to lower (and finally suppress)
some barriers. This would facilitate exchanges and help balancing across different
Member States. This standardisation effort between Member States should be
accompanied by a suppression of the balancing zones corresponding, for the same
Member State and the same TSO, to different specifications.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
260
(863)When harmonization of gas quality is not possible (for instance between L gas and H
gas), providing sufficient and cheap capacities for adapting gas qualities is a necessity.
(864)EASEE gas efforts for the harmonization of nomination rules should be encouraged.
- Creating a more favourable environment
(865)There is little incentive for a vertically integrated group to spend time and money on the
network in order to favour competition as it would, as a result, cut its profits in its own
supply activity. A condition for accelerating a free and non-discriminatory access to the
European gas network is reinforcement of TSO unbundling.
(866)Cooperation among both regulators and TSOs needs to play an important role in the
process. Convergence of rules and procedures regarding third party access can be a step
towards the reduction of the number of balancing zones. Cooperation of network
owners/operators will be beneficial if it aims at furthering best practices but the existence
of opposing incentives should not be ignored. Close cooperation of regulators on both
sides of the border, accompanied by appropriate powers, is likely to facilitate exchanges
between zones. Further, the activity of regulators can also play an important role in
reducing the number of balancing zones within a country. For example, the German
regulator is playing a central role in planning the reduction of the number of balancing
zones in its Member State. Since the answers to the questionnaire were received, BEB
and Wingas have suppressed one balancing zone each.
(867)There is also a role for remedies in competition cases. The settlement of the Marathon
competition case brought by the European Commission obliged Gaz de France to reduce
its balancing zones, from 5 to 2, which will be fully effective from 2009. It also obliged
Ruhrgas to reduce its tariff zones from 6 to 4 in 2006.
(868)More liquidity in the market would help the shippers to trade their imbalances and reduce
the role of TSOs in this field. Therefore, all the efforts made to develop hubs will be
beneficial to easier and less costly balancing, contributing to the encouragement of
newcomers.
Conclusion
The (temporal and spatial) fragmentation of balancing on the transportation system results in a
fragmentation of the portfolios of the suppliers, which is a bigger problem when the portfolio is
already small. This is a major obstacle for the new suppliers to enter the market.
Harmonization of nomination and balancing rules and, to the extent possible, gas qualities will
bring cost savings. Where harmonisation of gas qualities is not possible, cost-effective
measures to overcome this obstacle need to be put in place.
Effective unbundling of TSOs from supply and trading activities is necessary.
More liquidity in the market would help the shippers to trade their imbalances and reduce costs.
Regulators, TSOs and competition authorities need to play their roles.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
261
III. Gas Study - Liquefied Natural Gas
III.1. Introduction
(869)The previous sections of this report have discussed the difficulties for new entrants to
source gas in a market context characterised by long-term contracts between producers
and suppliers and by the lack of hub liquidity. In this context, LNG is often seen as an
opportunity which could provide a possibility to new entrants to bypass these difficulties.
Investment in LNG infrastructures is considered important also with regard to
diversification of supply and market integration. Several new LNG import facilities have
therefore benefited from exemption from third party access under Article 22 of the Gas
Directive.355
(870)In view of the important role that LNG could potentially play in the EU energy markets,
the Commission has sought to improve its understanding of the current state and likely
development of demand and supply for LNG in the EU, and on issues relating to
competition, regulation and other policy considerations which the development of LNG
might raise at Community level.356
This chapter, most importantly, includes information
gathered in discussions and meetings with stakeholders (investors, producers, shippers,
potential customers).357
Some information was collected specifically for the purposes of
the Sector Inquiry, other information – where necessary on an anonymous basis - was
used from other sources.358
III.2. LNG current and future demand
(871)Demand for LNG in the EU has been increasing in the past years. In 2005, the EU as a
whole imported 43 bcm of LNG, corresponding to 9% of total gas consumption.359
Table 42
Natural gas demand, imports and LNG in the EU (bcm).
Year Gas demand Total Import Import via
LNG
Import
LNG/Demand
%
Import
LNG/
Total
Import
2000 417 296 28 6,7 9,5
2001 427 286 27 6,3 9,4
2002 427 310 33 7,7 10,6
2003 447 325 34 7,6 10,5
2004 459 339 34 7,4 10,0
2005 475 369 43 9,0 11,6
Source: IEFE, 2006.
355
See paragraph (873).
356
As part of this exercise, a study has been commissioned within the framework of the Energy Sector Inquiry to the
consortium: Università Bocconi – IEFE (Istituto di economia e politica dell'energia e dell'ambiente) / Ernst & Young
Financial Business Advisors S.p.A.
357
e.g. information gathered in Art.22 exemption procedures, from participation in conferences, monitoring of industry
publications, meetings with stakeholders.
358
Some of this information is of confidential nature and is reported in anonymous form.
359
BP Statistical Review of World Energy, 2006.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
262
Currently, no more than seven Member States (E, P, F, GR, BE, I, UK) have functioning LNG
import facilities360
. The average importance of LNG for these 7 Member States is of
course, much higher. As Figure 80
(872) shows, Spain is, in relative terms (measured as a percentage of national consumption),
the main importer of LNG in the EU, followed by Portugal and France.
Figure 80
ITALY
(3,2% LNG)
SPAIN
(67,5% LNG)
GREECE
(18,4% LNG)
FRANCE
(28,5% LNG)
PORTUGAL
(52,7% LNG)
BELGIUM
(17,7% LNG)
UK
(0,5% LNG)
EU LNG
Consumption 2005:
43 bcm
ITALY
(3,2% LNG)
SPAIN
(67,5% LNG)
GREECE
(18,4% LNG)
FRANCE
(28,5% LNG)
PORTUGAL
(52,7% LNG)
BELGIUM
(17,7% LNG)
UK
(0,5% LNG)
ITALY
(3,2% LNG)
SPAIN
(67,5% LNG)
GREECE
(18,4% LNG)
FRANCE
(28,5% LNG)
PORTUGAL
(52,7% LNG)
BELGIUM
(17,7% LNG)
UK
(0,5% LNG)
EU LNG
Consumption 2005:
43 bcm
LNG suppliers:
• Algeria 48%
• Nigeria 25%
• Egypt 9,6%
• Qatar 9,6%
• Others 7,8%
LNG demand (in % of total national gas demand) in 2005
ITALY
(3,2% LNG)
SPAIN
(67,5% LNG)
GREECE
(18,4% LNG)
FRANCE
(28,5% LNG)
PORTUGAL
(52,7% LNG)
BELGIUM
(17,7% LNG)
UK
(0,5% LNG)
EU LNG
Consumption 2005:
43 bcm
ITALY
(3,2% LNG)
SPAIN
(67,5% LNG)
GREECE
(18,4% LNG)
FRANCE
(28,5% LNG)
PORTUGAL
(52,7% LNG)
BELGIUM
(17,7% LNG)
UK
(0,5% LNG)
ITALY
(3,2% LNG)
SPAIN
(67,5% LNG)
GREECE
(18,4% LNG)
FRANCE
(28,5% LNG)
PORTUGAL
(52,7% LNG)
BELGIUM
(17,7% LNG)
UK
(0,5% LNG)
EU LNG
Consumption 2005:
43 bcm
LNG suppliers:
• Algeria 48%
• Nigeria 25%
• Egypt 9,6%
• Qatar 9,6%
• Others 7,8%
LNG demand (in % of total national gas demand) in 2005
Source: Ernst & Young, 2006.
(873)In 2005 Spain was also the most important LNG importing country in the EU in absolute
terms (21.85 bcm imported), followed by France (12.83 bcm), Belgium (2.98 bcm), Italy
(2.50 bcm) and Portugal (1.58 bcm)361
. The volume imported by the UK can be expected
to rise steeply from 2006 onward.
(874)Regarding future supplies it is generally expected that the importance of LNG imports
will rise significantly both in relative and absolute terms. Considering new re-gasification
projects planned and under construction, the available receiving capacity of EU terminals
is likely to expand from 74.8 bcm per year to around 141.9 bcm per year by 2010362
.
According to IEA projections and other forecasts363
, LNG deliveries are expected to
reach 240 bcm per year by 2030. This would correspond to a six-fold increase compared
to the current figure, representing about 31.8% of the total gas demand in 2030.
360
The main facilities necessary to import LNG are berths and unloading equipment, storages and regasifiers.
361
BP Statistical Review of World Energy, 2006.
362
IEFE, 2006 (GTE, Drewry Shipping Consultants Ltd., press releases on the internet).
363
Cedigaz.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
263
Figure 81
LNG share of the total EU gas demand, 2030 vs. 2005
2005
8,9%
2030
31,8%
LNG share of the total EU gas demand, 2030 vs. 2005
2005
8,9%
2030
31,8%
Source: BP Statistics (2006).
(875)However, it is important to note that rather than displacing current pipeline gas imports,
LNG is expected to take a large share of incremental import needs arising from the fact
that EU demand for gas is increasing364
, while European domestic gas production is in
decline.
Figure 82
LNG share of the total European gas demand/imports
0
50
100
150
200
250
300
350
400
450
2000 2001 2002 2003 2004 2005
Year
bcm
Imports via LNG
Imports via pipeline
Domestic production
Source: IEFE, 2006.
364
See paragraph 21 in section B.a.I.1.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
264
(876)A number of factors explain the interest of many energy companies in importing LNG
and that of governments in facilitating such investments.
• First, it allows diversification of their gas purchasing portfolio, thus contributing to
a diversification of sources of imported gas.
• Second, the flexibility potential of LNG can contribute to developing spot markets.
• Third, LNG can be beneficial in optimising the performance of grids.
• Fourth, LNG can be an option for supplying geographical regions far from existing
gas grids365
.
(877)Looking at the global picture, the Asia-Pacific region is currently, by far, the world’s
most important LNG consuming region (year 2005 figures), with its LNG trade
accounting for about two thirds of the world’s LNG trade.
Figure 83
North America,
17.87, 9%
Europe, 47.6,25%
Asia Pacific,
122.42, 66%
Others, 0.92, 0%
LNG imports by world region (data in bcm), 2005*
North America,
17.87, 9%
Europe, 47.6,25%
Asia Pacific,
122.42, 66%
Others, 0.92, 0%
LNG imports by world region (data in bcm), 2005*
Source: BP, Statistical Review of World Energy, 2006.
Note: * Europe includes Turkey. The EU imported 42,72 bcm; others refer to Central and South America.
365
For example to connect large islands or other regions which are difficult to reach pipelines.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
265
III.3. Overview of LNG supply chain
(878)In order to understand the development of LNG supply, it is important to look at the key
characteristics of its value chain. Three main segments can be identified: i. production, ii.
shipping, and iii. operation of LNG receiving terminals.
Current and potential suppliers
(879)World LNG production is growing rapidly as new liquefaction plants are being installed
in exporting countries, allowing new players to enter the LNG world market.
Considering the number of projects in progress, overall production capacity will double
by 2010366
. In particular, Qatar has made huge investments that will make it the world’s
largest LNG producer by the year 2010.
(880)At the same time, the supplier structure of LNG into Europe is becoming more
diversified. In 2002, Algeria had a share of 77% of the total EU market (and the
remainder was supplied by Nigeria, Qatar, Brunei, Oman, Libya, Malaysia, Trinidad and
Tobago, UAE and Australia). In 2005, the main LNG suppliers to the European market
were Algeria (48% of current supplies), Nigeria (25%) and Qatar (9.6%). Other suppliers
(7.8%) included Trinidad, Libya and Egypt. In the future, the regions relevant to the EU
will probably include the Middle East (Qatar, Oman, Yemen, Iran), where 40% of world
gas reserves are located, as well as Africa (Algeria, Libya, Egypt, Nigeria) and Norway.
The extent to which Russia will produce LNG within the geographical reach of Europe is
currently unclear. At least for spot trades South American and Caribbean producers such
as Trinidad and in addition Venezuela could be viable relevant suppliers. Producers in the
Far East, by contrast, are unlikely to supply directly to Europe, due to transport costs and
high demand for LNG in the Far East.
(881)A trend registered in the last few years is that LNG operators are moving downstream or
upstream, increasing the level of vertical integration in the main segments of the LNG
chain. In particular, producers are moving downstream and obtaining access to both regasification
terminals in Europe as well as transportation segments367
while importers are
increasing their presence in the shipping industry and, to a lesser extent, in the
liquefaction segment.
366
Assuming no delay in construction timing, an additional liquefaction capacity of 187 mtpa, could be available by
2010.
367
E.g. the partners in Qatar’s LNG projects, Qatargas and Rasgas, will produce LNG and ship it to those import
terminals (in the UK, France and Italy) partly owned by the same partners.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
266
Figure 84
Main exporting regions in 2005 (%)
Africa
24% Americas
23%
Middle East
9%
Asian
Countries
44%
Source: BP Statistics, 2006.
Shipping capacity
(882)Shipping represents an important link in the LNG value chain, currently undergoing
major transformation. The recent increases in LNG demand have resulted in the
expansion of the LNG shipping industry and many tankers have been built in the past few
years. In just three years – between 2003 and 2006 – the total number of vessels has
increased by 35% and the transportation capacity by 57%. In the next decades the
shipping industry is expected to grow further and by the year 2015 the total transportation
capacity is likely to double, as 145 tankers are either planned or already under
construction368
. By the end of this decade, 25 new tankers will serve Europe, thus
increasing the total transport capacity by 60%. The tables in the Annex K provide a
detailed picture of the shipping capacity on the primary routes to the EU.
368
Maritime Business Strategies. At the moment, about 64 tankers serve the European market.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
267
Figure 85
World LNG Industry
153
207
352
49,1 bcm
15,8 bcm
24,8 bcm
0
50
100
150
200
250
300
350
400
2003 mid - 2006 2015
N°ofShips
0
10
20
30
40
50
60
TotalShippingCapacity
(bcm)
N° of Ships Total Shipping Capacity (bcm)
Source: Ernst & Young's elaboration of Maritime Business Strategies' data.
(883)In the past decades, LNG tankers used to be built for specific (very) long-term contracts
and routes, tending to be rather small in terms of size. However, the recent trends are
towards ever larger ships being built for charter contracts of shorter duration or even
without a link to specific contracts.
(884)The available data on the new vessels planned and assigned to serve the EU market show
a clear tendency: on average, the planned tankers are larger than the existing ones. In
particular, as the following chart illustrates, there are no small tankers under construction,
while a large number of extra size ships (more than 200,000 cm) will be delivered in the
coming years.
Figure 86
Capacity profile of newbuilding LNG fleet, EU market
12%
56%
32%
Medium Size (50,000 to 125,000 cu.m) Big Size (125,000 to 155,000 cu.m)
Extra Size (more than 200,000 cu.m)
Source: Ernst & Young's elaboration of Maritime Business Strategies' data.
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(885)According to the available data, less than 10 transportation companies control about two
thirds of the available capacity. Among them, Bonny Gas Transport – a wholly owned
subsidiary of Nigeria LNG limited – holds about 25% of the total existing shipping
capacity devoted to serve the European market.
Figure 87
Share of capacity dealt with by major ship-owners
Oman Gas /
MOL, 6%
BW Gas, 10%
Kristen
Navigation, 4%
Peninsular
LNG, 8%
A. P. Moller,
4%
Bonny Gas
Transport, 25%
Others, 33%
Teekay LNG
Partners, 6%
SNTM-Hyproc,
4%
Share of capacity dealt with by major ship-owners
Oman Gas /
MOL, 6%
BW Gas, 10%
Kristen
Navigation, 4%
Peninsular
LNG, 8%
A. P. Moller,
4%
Bonny Gas
Transport, 25%
Others, 33%
Teekay LNG
Partners, 6%
SNTM-Hyproc,
4%
Source: Ernst & Young's elaboration of Maritime Business Strategies' data.
(886)Vertical integration between producers and ship owners is quite widespread. Of the 64
available tankers serving the European market, at least 25 ship owners are vertically
integrated with the producers. Producers often cover the transportation segment directly
through a wholly-owned transportation company or as shareholders in a transportation
company. This type of integration also exists between importers and ship owners.
Usually, large incumbents (such as Gaz de France or ENI) operate in the transportation
segment, directly managing LNG tankers, or by means of a controlled shipping
company369
.
Receiving terminals in the EU
(887)Currently, 12 LNG regasification terminals are operated in the EU in 6 Member States.
12 more are under construction, while 38 terminals have been proposed by prospective
operators (and are in various stages of the planning and permission process), also in
Member States not previously importing LNG, such as Cyprus, Germany and Sweden.
Table 43 and Table 44 provide a cross-country comparison of such terminals.
369
E.g. Messigaz is 100% owned by Gaz de France.
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269
Table 43
Status of EU-25 regasification terminals by country in 2006
Existing
Under
construction
Proposed Total
Country Belgium 1 1 0 2
Cyprus 0 0 1 1
France 2 1 3 6
Germany 0 0 1 1
Greece 1 1 2 4
Ireland 0 0 1 1
Italy 1 2 13 16
Latvia 0 0 1 1
Netherlands 0 0 3 3
Poland 0 0 1 1
Portugal 1 0 1 2
Spain 5 4 5 14
Sweden 0 0 1 1
UK 1 3 6 10
Total 12 12 39 63
Source: IEFE, 2006.
Table 44
Maximum capacity of EU-25 regasification terminals in bcm, in 2006
Existing Under construction Total Proposed
Country Belgium 4,5 4,5 9,0 Cyprus
- - - 0,7
France 14,8 8,3 23,1 16,0
Germany - - - 10,0
Greece 2,3 4,3 6,6 n.a.
Ireland - - - n.a.
Italy 3,5 16,0 19,5 84,2
Latvia - - - n.a.
Netherlands - - - >12,0
Poland - - - 3,0
Portugal 5,2 - 5,2 3,3
Spain 39,9 12,8 52,7 >9,6
Sweden - - - n.a.
UK 4,6 26,5 31,1 >18,9
Total 74,8 72,4 147.2 Source:
IEFE, 2006.
(888)Most of the existing capacity (73%) on the existing terminals is currently allocated to
national incumbents, 21% is held by other operators (within the same Member State) and
6% by non-EU producers (namely, Qatar and Algeria). The situation is somewhat
different for the terminals under construction, where – for the terminals for which the
planned capacity allocation is known - only 30% of the capacity will be controlled by the
national incumbents, while the remaining 64% will be held by operators different from
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
270
the incumbents370
. The remaining 6% is yet to be allocated371
. The 64% held by
operators other than the national incumbents, can be split into 25% allocated to national
competitors, 37% to competitors from other EU countries and 38% to non-EU producers
seeking to access downstream markets. As this analysis372
shows, the ongoing
construction of new LNG capacity opens possibilities for new entry. LNG terminals
therefore have a potential of promoting market integration and competition within the
European gas sector.
(889)As regards the capacity of proposed terminals, the only information currently available
concerns ownership structure, which does not allow any reliable forecast of future
capacity reservations. The terminals proposed will be owned, to varying degrees, by
national incumbents (11% of invested capital), by national operators other than national
incumbents (51%) and by foreign competitors (37%). Proposed terminal ownership
participation of non-EU producers is currently minor (1%)373
. Capacity reservation will
depend on a number of factors. However, the ownership structure of current LNG
terminal projects confirms the previously stated trend of entry of new players and
therefore towards a greater degree of market integration and competition for EU gas
markets.
III.4. The role of LNG for security of supply and competition in EU gas markets
(890)This section deals with the role that LNG is expected to play for the functioning of energy
markets in terms of security of supply and increased competition downstream. It also
considers possible obstacles to these developments.
III.4.1. Security of supply
(891)The development of LNG market is generally expected to contribute to the objective of
security of supply. This is (i) because the range of LNG producers is broader than the
number of countries from which gas can be delivered to the EU via pipelines, and (ii)
because the flexibility of LNG supply (through spot trade) increases the ability of EU
market to respond to short term supply and demand variations.
(892)Firstly, a greater reliance on LNG allows the EU to import gas from regions otherwise not
reachable via pipeline and thus to diversify its supplier base. Diversification of suppliers
through LNG has already taken place over the past few years with new Middle East and
African producers having started to sell LNG to various Member States. Based on new
contracts with deliveries starting over the next 2-3 years it can be expected that this trend
will continue. Spot trade may occasionally involve even producer countries located in
more distant regions.
(893)Secondly, LNG has a significant potential for enhancing the flexibility of gas markets. An
advantage of LNG is that its production and transport infrastructures are less regionally
constrained compared to pipelines. This fact allows the redirection of supply if the
370
These figures are calculated on the basis of just 8 out of the 12 terminals under construction – which account for 86%
of the total capacity under construction -, because of the lack of detailed figures for the 3 remaining projects
(Revithoussa expansion 1; Huelva expansion 1; Cartagena expansion 1; Barcelona expansion 1).
371
This corresponds to the share of the LNG terminals under construction in Italy which is reserved for third party
access.
372
IEFE, 2006.
373
IEFE, 2006.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
271
circumstances make it more profitable. Arbitrage transactions – in so far as they are not
restricted – then permit LNG flows to rapidly react to market signals.
(894)This supply flexibility potential was not utilised in the traditional business model in
which incumbent EU suppliers contracted dedicated long-term upstream LNG supply,
transported it with dedicated ships and imported it through their LNG terminals which
were dedicated to serving this very limited number of the incumbent’s long-term
contracts. However, LNG trade is gradually moving away from this rigid structure and is
now converging towards a more flexible structure, which is more sensitive to market
signals. The factors that foster the development of a flexible short-term LNG market are:
(i) the presence of uncommitted liquefaction capacity; (ii) the presence of excess capacity
on receiving terminals; (iii) the availability of tankers not committed under long-term
contracts; (iv) use it or lose it measures imposed on capacity holders in terminals.
(895)The main trends of the LNG supply chain that have been presented in the previous section
seem to confirm the current development of such factors on the world LNG market.
Indeed, it appears that new liquefaction facilities in Algeria, Oman, Qatar and Trinidad
are increasing the available spare capacity for spot trade. In addition, an increasing
number of new vessels are being delivered with no link to specific routes which will thus
be dedicated to LNG spot trade. As a result of these trends, LNG spot trade has emerged
alongside long-term trade in the last ten years and in 2005 it accounted for 11% of the
global LNG trade374
. In Europe, the development of the Spanish market is most
advanced with regard to spot transactions.
374
Petrostrategies, 2006. Spot trade refers to transactions of less than a year.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
272
Table 45
Spot LNG Trade, 1992-2005
(bcm and %)
1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005
Trade movements (bcm) 1,06 1,59 2,34 3,27 2,33 1,64 2,12 4,72 7,6 10,75 11,44 16,3 19,8 20,7
Share of the world LNG trade 1,3% 1,9% 2,7% 3,5% 2,3% 1,5% 1,9% 3,8% 5,5% 7,5% 7,6% 8,9% 10,9% 11,1%
LNG spot market
Source: "Security of gas supply in open markets", OECD/IEA, 2004, Table 4.5, p192.
.
Table 46
Spot LNG sales and purchases as % of total LNG exports and imports in 2003Spot LNG sales and purchases as % of total LNG exports and imports in 2003
Source: "LNG cost reductions and flexibility in the LNG trade add to security of supply", published in
Energy Prices & Taxes, OECD/IEA, 1st
quarter 2005, Table 2, page xxxi.
(896)The share of LNG spot transactions is expected to increase in the next decade. It is
forecast that by 2020, LNG spot trade could account for 30% of the global LNG trade375
.
Obviously, this also means that by far the largest part of LNG supplies (about 70%) will
continue to be made on the basis of long-term contracts.
III.4.2. Competition in downstream markets
(897)The increasing role played by spot transactions in enhancing flexibility of the gas market
could also facilitate the emergence of competition in downstream markets since new
entrants can more easily source gas in liquid markets. The diversification of gas
producers and the emergence of LNG spot transactions, which have been illustrated in
the previous section, seem to open up new opportunities for a new entrant to source gas.
To the extent that LNG increases the liquidity of EU markets, it can be expected to
contribute to creating an environment which is more favourable from the point of view of
creating competitive and integrated markets.376
375
Cedigaz, "Security of gas supply in open markets", 2004, IEA.
376
Increased liquidity brought about by LNG spot trade may furthermore provide an impetus to a shift in reference
prices. E.g. in the US, the benchmark price for short-term transactions is the Henry Hub price.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
273
(898)It is therefore important that this pro-competitive potential of LNG supplies is indeed
realised. For this purpose, the Commission will monitor the development of the upstream
gas market and the trends emerging in the different segments of the LNG value chain
(including access to LNG terminals) to ensure that the ability of new entrants to access
this type of gas at competitive conditions is not unduly restricted.
III.4.3. Pipeline to LNG competition
(899)The ability of a new entrant to compete in downstream markets through access to LNG
will also depend on the cost-competitiveness of the LNG chain in comparison with
pipeline gas. In the past LNG technology was considered too expensive to be able to
compete directly with gas delivered via existing pipelines. However, in recent years the
competitiveness of LNG compared with pipeline gas has improved, in particular in an
environment of rising gas prices, and thanks to technological changes that have
substantially reduced costs. For example, between 1990 and 2000 liquefaction costs have
fallen by 25% to 35% and shipping costs by 20% to 30%.377
(900)The Commission has asked an economic consultant to carry out a simulation which
allows a comparison of the cost of LNG with gas from long-distance pipelines.378
A
comparison has been made between the costs of pipelines of different throughputs (10,
25, 40 billion m3
/year) and LNG costs necessary to cover the same throughput. This
comparison is based on a number of critical assumptions, and it is therefore of purely
indicative value.379
For pipeline gas, capital expenditure related to laying pipelines on
land and building gas compressor stations was considered380
. As regards LNG, the
project chosen includes a tanker of 135,000 m3
LNG and a re-gasification terminal with a
capacity of 8 bcm per year. All facilities, including the liquefaction plant are assumed to
be according to current best technological practice.381
377
Sources: Drewry, Poten and partners, LNG Observer, Oil and Gas Journal.
378
Consortium: Università Bocconi – IEFE (Istituto di economia e politica dell'energia e dell'ambiente) / Ernst & Young
Financial Business Advisors S.p.A.
379
In particular, only the industrial cost of gas transportation is considered. More, specifically, taxes, royalties,
efficiency gains, commodity value, extraction costs, production costs, operators’ mark-up, financing costs have not
been included.
380
These costs have been calculated as a function of the distance and on the pipeline’s diameter. There are vast
economies of scale associated with inland pipelines. The main CAPEX cost driver is assumed to be the price of steel
($35/inch/meter with a price of steel of $1,250/ton). CAPEX are considered as referring to an inland pipeline on a
flat ground. Costs increase as the territory becomes more mountainous.
381
The main assumption is that all economies of scale are achieved at the nominal capacity of 7.5 million tonnes per
year for the liquefaction plants, 135,000 LNG m3
for tankers and 10 billion m3
for regasification terminals. Because
of the above assumptions, in the LNG chain there are significant economies of scale only relating to distance.
Furthermore, for a new liquefaction plant a total installed cost of $200/tpy has been used. A specific fuel-gas
requirement of 7% of the inlet gas is used for calculating the cost of fuel gas needed for liquefaction. The lifespan of
the LNG liquefaction terminal is assumed equal to 25 years, while annual OPEX (operating expenditure) is 2% of
CAPEX (capital expenditure). With regard to shipping, it is assumed that CAPEX is equal to $170m and OPEX
$11.3m/year. Finally, as far as regasification is concerned, it is assumed specific fuel-gas consumption of 1.5% of
the LNG to be evaporated and maintenance costs of 2% / year of the plant investment.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
274
(901)The results of these comparisons suggest that, for a typical 25 bcm/year pipeline project
a. if the pipeline is built on a completely plain territory, it remains cheaper than the
LNG project up to a 6,500 km distance from the production site;
b. if the pipeline is built on a topographically more mixed territory382
, LNG
becomes cheaper from 5,500 km.
For smaller projects (10 bcm/year) LNG becomes cheaper from 3,000 km if the pipeline
is built on a completely plain territory and for shorter distance in case of mountainous
territory. For bigger projects (40 bcm/year) the pipeline remains more competitive for
all distances. These results would change in case of submarine pipelines whose costs are
assumed to be twice the cost for inland pipelines in plain territory.
Figure 88
Cost comparison between inland pipeline and LNG (flat territory)
LNG versus inland PIPE
0
1
2
3
4
5
6
7
8
0 2000 4000 6000 8000 10000
Km
Eurocent/cm
PIPE 10 PIPE 25 PIPE 40 LNG
Cost comparison between inland pipeline and LNG (flat territory)
LNG versus inland PIPE
0
1
2
3
4
5
6
7
8
0 2000 4000 6000 8000 10000
Km
Eurocent/cm
PIPE 10 PIPE 25 PIPE 40 LNG
Source: IEFE, 2006.
382
For the "mixed" scenario the following topography is assumed: 70% flat, 25% hilly and 5% mountainous.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
275
Table 47
Cost comparison between inland pipeline and LNG (flat territory)
Eurocent/cm
distance 1000 1500 2000 3000 4000 5000 7000 8000
PIPE 10 0.82 1.24 1.66 2.54 3.44 4.38 6.35 7.39
PIPE 25 0.46 0.70 0.94 1.43 1.94 2.47 3.58 4.17
PIPE 40 0.36 0.54 0.73 1.11 1.51 1.92 2.78 3.24
LNG 1.91 2.03 2.16 2.41 2.66 2.91 3.43 3.69
Source: IEFE, 2006.
Note: data in c€.
LNG competitiveness versus PIPE 10
LNG competitiveness versus PIPE 25
Table 48
Cost comparison between inland pipeline and LNG (mixed territory)
Eurocent/cm
distance 1000 2000 2500 3000 4000 5000 5500 6000
PIPE 10 0.93 1.89 2.38 2.88 3.91 4.97 5.51 6.07
PIPE 25 0.52 1.07 1.34 1.62 2.20 2.80 3.11 3.42
PIPE 40 0.41 0.83 1.04 1.26 1.71 2.18 2.42 2.66
LNG 1.91 2.16 2.28 2.41 2.66 2.91 3.04 3.17
Source: IEFE, 2006.
Note: data in c€.
LNG competitiveness versus PIPE 10
LNG competitiveness versus PIPE 25
(902)This comparison illustrates that the economics of transportation (distance between
production and consumption centres, topography of territory, economies of scale, etc.)
strongly influences the ability of LNG to compete with gas delivered via pipeline and
thus to constrain the price of the latter. However transport cost will only be one factor for
the producer in deciding the best-suited transport mode. Considerations such as the
increased flexibility of LNG (which can also bring higher value to the producer) and
considerations of political stability of transit countries will also influence decision
making. Finally, producers at a large distance from major centres of consumption or
separated by the sea do not, in any case, have the option of supplying by pipeline at all.
III.5. The regulatory framework
III.5.1. Introduction
(903)In order to fully reap the potential benefit of LNG for enhancing competition and security
of supply, it is essential that the right regulatory system is put in place in Europe. In this
respect, the Second Gas Directive contains a number of provisions with regard to, or with
a particular impact on, LNG infrastructure. These can be summarized as follows:
a. The Directive requires that prices for accessing LNG infrastructure and capacity
allocation are regulated.
b. This includes obligations on the TSO to ensure that the rules for access to the
system (i.e TPA or third party access rules) are non-discriminatory and also
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
276
requires that the tariffs charged for using the system are approved by the
relevant regulatory authority.
c. However, a derogation possibility exists in the Second Gas Directive by which
new or upgraded infrastructure can be exempted from the third-party access
rules.
d. The granting of an exemption is subject to a number of conditions, including,
crucially, that the exemption not be detrimental to competition. These exemption
criteria are set out in full in Article 22 of the Second Gas Directive.
e. For operators of LNG infrastructure unbundling requirements are limited to
accounting separation.
f. The combined operation of transmission, LNG, storage and distribution remains
possible. It is only required that the combined operator is independent in its
legal form and organisation from the remaining areas of activity.383
III.5.2. Investment issues including exemptions under Article 22 of the Second Gas
Directive - trade off between openness of access and investment incentives
(904)The Preliminary Report of The Energy Sector Inquiry contained a number of remarks
with regard to investment issues which remain valid and have a particular importance for
investment in LNG terminals and the regulatory framework applicable to them. The main
themes are reproduced and complemented below:
(a) The nature of gas flows across the EU is likely to change significantly over the
medium- to long-term due to factors such as the relative decline of domestic
production and the drive to further diversify supplies. This will most likely
require substantial investment in new LNG terminal infrastructure. As explained
above, a significant number of LNG terminals are already under construction or in
the planning stage.
(b) New infrastructure can, by increasing competition between outside EU producers,
often have pro-competitive effects when allowing for new competitors in national
markets or new sources of gas to reach the EU. However, the existing long-term
reservations on transit lines demonstrate the risk of cementing market shares in
destination markets. It is therefore important to ensure that the conditions of any
procedure for allocating LNG receiving capacity do not perpetuate the current
level of foreclosure observed on existing transit lines. This has already been
achieved for the new LNG terminals under construction. A significant share of
their capacity will be allocated to operators different from the incumbents, both to
new entrants and to producers themselves.
(c) Since LNG projects require significant capital investment384
, the nature of the
financing arrangements is key in order to ensure their viability. Projects without
383
The issues of vertical integration and insufficient unbundling are dealt with in chapter B.a.II.2.
384
This is the case although, of the three main steps in the LNG chain, it is the re-gasification terminal which requires
the least investment (14%) while it is the liquefaction terminal which needs the highest investment (60%).
Transportation, in turn, accounts for 26% of the total investment required.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
277
appropriate financial security will not take off at all. Typically, project developers
attempt to mitigate their risk by long-term contracts, guaranteeing the developers
sufficient future revenue to meet the costs of financing the project. It is important,
therefore, that the regulatory regime strike a balance between providing the right
incentives to build new capacity and ensuring that any long-term contracts do not
have detrimental effects on competition.
(d) Article 22 of the Second Gas Directive provides an exemption possibility from
TPA rules for new or enhanced infrastructure. This is an important means to
encourage investment. It should, however, be noted that the granting of an
exemption, as an exception to the default arrangements, is not necessarily a
requirement in order for new infrastructure to be built. Indeed, it has been
highlighted that other ways of encouraging investment exist, e.g. through an
enhanced regulated rate of return.385
(e) In assessing an exemption request from the point of view of competition, one of
the key facts to consider are the rules followed for allocation of such capacity386
and the nature of any contracts allocating capacity on the new or upgraded
infrastructure, and in particular the counterparties concerned, the scope of the
contracts, and their duration. The impact of these elements will be assessed in the
light of the degree of competition in downstream markets and the possibilities for
access to other terminals in the vicinity.
(f) In addition, another consideration is whether the specific conditions of such a
procedure indeed allow for different types of companies (including new entrants)
to participate in the expansion. For example, it will be harder for new entrants,
whose market share is not (yet) established to commit themselves to ship-or-pay
contracts for 20 years, especially when the existing capacity on transit lines is
booked long term and where there is no liquid wholesale market for gas. In certain
situations, the risk that access to short-term capacity is foreclosed for a long time
must therefore be taken into account even if this can run counter to the desire of
the project developer to lay-off as much risk as possible through locking-in longterm
contracts.387
(g) Moreover, strong incentives for an effective functioning of the secondary market
should be set, e.g. through ensuring an effective application of use–it-or-lose-it
principles or use-it-or-lend it principles. This is particularly important whenever
there is the possibility that the LNG terminal may provide the capacity for the gas
at the margin and set the market price. In that case, the long-term capacity
holders, even if they are not in a dominant position on a national wholesale
385
Cf. the CEER paper ‘Investments in gas infrastructures and the role of EU national regulatory authorities’. Reference
can also be made to the Spanish LNG market which does not take recourse to TPA exemption provisions and has
found other means to secure investment.
386
For instance, it has been widely acknowledged that any capacity allocated on the new or upgraded infrastructure
should be allocated pursuant to a pro-competitive process, such as an ‘open season’ or similar procedure, organised
before the expansion and allowing for interested third parties to participate in the expansion.
387
Reference can be made to decisions of the Italian regulator, not to exempt a maximum of 20% of the terminal
capacity from regulated TPA. While this may lead to the risk that the remaining 80% of exempted capacity also have
to guarantee the income of the remaining 20% to the developer (thus increasing their costs), such effect is not
inevitable: (i) the developer can be expected to take over a certain minimum amount of financial risk (mitigated by
the fact that the operational time of the terminal may well go beyond the 20 [or even 25] year period upon which
many project-finance calculations are based (ii) some initial higher capacity reservation payment by the long-term
capacity holders could be paid back to the from the (regulated) revenues of the short-term sales.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
278
market, may not always have the commercial incentive to use free capacity to the
maximum. The only exempted terminal in operation is the first phase of the Isle of
Grain LNG terminal. It is worth noting that shortly after the beginning of its
operation an issue of capacity underutilisation arose at a time of rising prices.388
(h) Thus, while the exemption scheme has so far worked satisfactorily in stimulating
investment, it is necessary to consider that the experience gathered so far with
regard to the exemption procedure and its specific effect on the market is still
limited and that the effect of future exemption applications has to be assessed
carefully.389
III.5.3. Current national regulatory conditions in EU LNG terminals, in particular
with regard to capacity allocation mechanisms and pricing
(905)The importance of pro-competitive primary and secondary capacity allocation
mechanisms, both in exempted and non-exempted (regulated) TPA regimes, has already
been underlined. The current section looks at the regulatory regimes in Belgium, France,
Italy, Spain and the UK.390
Exempted and non-exempted ("regulated") terminals
(906)Only in the UK and in Italy exemption mechanisms from TPA for new investments have
been applied. Exemption periods for these terminals are 20-25 years. For two terminals
in Italy (Brindisi and Rovigo) the exemptions cover 80% of the capacity, whereas for
three UK terminals 100% of the capacity was exempted, the British regulator having a
review possibility if market conditions should be substantially different to the expectation
at the time of the exemption. As only one of the exempted terminals (the Isle of Grain
terminal in the UK) is currently in operation, the large majority of LNG terminals in the
EU are currently subject to regulated TPA.
(907)For the "old", pre-Directive, regulated terminals in Belgium, France and Italy, two
capacity allocation mechanisms for primary capacity in old terminals currently exist side
by side. At Zeebrugge (Belgium) and in France, capacity is allocated according to the
principle of first-come-first-served (FCFS). In Italy's Panigaglia terminal, capacity
allocation follows a priority order by which first priority is given to holders of take-orpay
contracts signed prior to 10 August 1998.391
In spite of these differences, the
outcomes in these three countries are similar. Due to long-term capacity bookings, even
today a large part, sometimes even all, of this old-terminal capacity continues to be
reserved for the incumbents.
(908)Regarding new terminals or terminal expansions of regulated-access terminals, there is
again a difference in approach. In Belgium, capacity for the terminal expansion has been
allocated through an open season process, while in France 90% of new capacity at the
388
Reference can be made to the UK case study in section B.a.II.3.4., regarding the contractual congestion problem at
the Isle of Grain terminal at the beginning of winter 2005.
389
Five terminals have obtained exemptions of which one has started operations while three others are being built and
are scheduled for entering into operation in the next few years.
390
The two terminals in the two countries still benefiting from a general exemption from the liberalisation provisions of
the Second Gas Directive (Sines in Portugal and Revithoussa in Greece) were not considered in this context.
391
Subsequently, the merit order foresees the allocation of the remaining capacity to holders of other pluriennal
importing contracts and then to holders of annual importing contracts. (Capacity requests of the same priority class
within that merit order which can only be partly satisfied are split on a pro-rata basis.)
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
279
new Fos Cavaou terminal is reserved to project sponsors and 10% is available for third
parties on a pro-rata basis. In both cases, the incumbent (or its group) secured the largest
part of the new capacity. Capacity allocation for the regulated part of the Brindisi and
Rovigo terminals will be subject to a different priority order than for existing terminals.
In particular, this is intended to favour the access to capacity by final consumers392
and
by shippers wishing to trade gas at the Italian hub (PSV).
(909)In Spain, where capacity is allocated following a FCFS method, the situation is different
from Belgium, France and Italy insofar as a much larger number of shippers have gained
access to primary capacity. Several circumstances can be expected to have had an
influence on this situation, in particular (i) ownership unbundling of supply and import
and transmission infrastructure, (ii) the construction and operation of additional terminals
by third parties and (iii) specific regulatory action. As a specific regulatory measure, a
cap applies to short-term capacity in Spain. While 75% of the total capacity is set aside
for contracts with a minimum length of 2 years, the remaining 25% is for contracts with a
duration of less than 2 years. No shipper is to hold more than half of this short-term
capacity on the same terminal.
(910)Regarding the exempted terminals in the EU, an open season procedure was used to
allocate primary capacity at the Isle of Grain terminal in the UK where the operator of the
terminal is a separate entity from the shippers who have reserved the whole capacity. As
regards the other exempted terminals in the UK (Dragon and South Hook) and in Italy
(Brindisi and Rovigo), the users of capacity are largely the same companies who own and
sponsor the project.
Secondary capacity and anti-hoarding provisions
(911)In all countries examined, terminal operators have organised a secondary market for
capacity allocation although the only country with explicit regulation for a secondary
market is Belgium. The mere existence of secondary markets at EU terminals is,
however, not sufficient to ensure their well-functioning. It is generally acknowledged that
in Europe secondary trading has not fully developed yet.
(912)Anti-hoarding clauses are present in the five countries analysed (B, F, I, ES, UK) but are
characterised by a considerable variety of specific provisions. They are mainly in the
form "use it or lose it" (UIOLI)393
with either an ex ante or an ex post effect. In an ex ante
system each slot that is not used by the capacity holder has to be offered to the market. In
an ex post system, the degree of unused slots is afterwards taken as an indication of
changes that need to made for future capacity allocation: should the operator that has
reserved capacity on the terminal not use a certain amount of it for a certain period of
time, the booked future capacity (or a part of it) will be lost.
(913)More specifically, in Belgium the user of the LNG terminal must notify Fluxys LNG of
the slots that will not be used two months in advance at the latest. In France, three
conditions must be fulfilled for the user to lose its allocated capacity: underutilisation of
part of allocated capacity in a terminal where there is no more available capacity; the
capacity owner refuses to sell that part of capacity on the secondary market at a higher
price than the tariffs; the capacity owner is unable to justify its behaviour. In Italy, if
during a gas year more than 20% of the exempted capacity is not used, the user loses the
392
Excluding electricity producers.
393
In Belgium the term "use it or lend it" is also applied.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
280
exemption right for the overall capacity starting from the following year. In Spain, a real
UIOLI system does not exist, but every operator can apply to the TSO, informing him of
under-utilisation of capacity which is then attributed to other interested competitors394
.
The primary users can however also notify that they intend to use a smaller amount of the
capacity reserved up to three months in advance. Finally, in the UK (Isle of Grain) if the
capacity holders do not sell their unused capacity, the LNG terminal operator is allowed
to sell that capacity to another party395
. In this case, the notice period is ten days. It has to
be pointed out that penalties, although of quite different deterrent effect, are present in all
the above countries with the exception of the UK.
(914)At this stage, experience with the effectiveness of the various anti-hoarding measures is
still limited and will need to be closely monitored. A factor of some importance in this
context is the advance notice period of available slots. Shippers should obviously have a
sufficient possibility to react to the availability of a slot in order to re-direct the route of
their ships. It can be noted that sailing time for an LNG vessel from the Arabian Gulf to
an existing UK terminal has been stated as 15 days, and sailing times from Nigeria,
Trinidad and Egypt as 7-10 days.
Pricing issues
(915)The determination of access charges to LNG terminals is complex. Various models exist.
However, as an in-depth survey on the views of stakeholders is absent, this report
abstains from taking position on this issue, apart from making the following remarks.
(916)Firstly, an issue that has been brought to the Commission's attention is the separate
marketing (and split tarification) of individual services (berthing and unloading; storage;
send-out). It has been argued that such split marketing and pricing can be an advantage
whenever shippers' individual needs differ. e.g. a small shipper with a low frequency of
cargoes can have substantially higher terminal storage needs than a large player with a
high frequency of cargos. The split marketing of these service components on the
secondary market should therefore be encouraged.
(917)Secondly, regarding pricing of spot cargos, tables below provides a comparison, for 4
Member States, of the cost of a spot unloading of 1 TWh with an emission on the
transmission network of 30 days. The result shows that the costs for France and Italy
(730 000 EUR and approximately 850 000 EUR, respectively) are significantly lower
than for Belgium (3 720 000 EUR). It must be noted, however, that this result for
Belgium is strongly influenced by the fact that the standard period for send-out in
Belgium is 10 days only and any shipper surpassing that period would have to buy this
service for the whole year (instead of only for additional 20 days as in the example
given). Such spot cargo shippers, in Belgium, would therefore be dependent on the
secondary market where a long-term shipper could offer them either a whole berthing slot
including more generous send-out conditions or just such send-out conditions in isolation
at a much more favourable price than in the example. Nevertheless, even without any
costs for additional emission time, the price for Belgium would clearly be the highest (1
010 000 EUR). For Spain, no such booking could take place in practice since the amount
of storage an LNG shipper can have on a terminal is subject to more stringent
394
In this case, the primary holder of capacity loses as well part of the guarantee provided for the utilisation of capacity.
395
Capacity can only be advertised when there is the right combination of a berthing slot, tank storage and sufficient
time to send gas out into the network before the next scheduled slot.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
281
limitations396
. A variation of this example calculates the price for a shorter send-out
period of 8 days.
Table 49
Cost of a spot unloading of 1 TWh
With an emission on the transmission
network of 30 days
With an emission on the transmission
network of 8 days
Belgium 3 717 043 EUR 1 010 443 EUR397
France 730 000 EUR Not possible398
Italy 851 929 EUR 851 929 EUR
Spain Not possible399
635 333 EUR
Source: Commission elaboration of IEFE and national regulators data.
(918)The details of these calculations are shown in the Annex 2. This illustrates that not only
tariff levels (including gas consumptions and guarantees), but also tariff structures differ
substantially across Member States.
Further sensitive aspects concerning access to capacity
(919)There are an number of areas where regulatory provisions and/or operational rules may
play an important role in ensuring effective access to the capacity of LNG terminals such
as: the duration of individual slots400
, the conditions of access to the national grid, the
conditions of access to the terminal's storage capacity, transparency on the operation and
utilisation of the terminal, vetting procedures necessary for new ships.
(920)The ways these aspects are dealt with differ substantially between Member States. While
individual situations can vary and can call for certain terminal-specific solutions it is
nevertheless unlikely that such wide variations even on fundamental issues such as
transparency reflect an optimal outcome. Further possibilities for regulatory
improvements, e.g. through adoption of best practice, should therefore be explored401
.
396
Storage is limited to the greatest amount between 30 GWh or 8 days of the contracted capacity calculated as an
average of the last 30 days. An emission on the transmission network of 30 days would not respect these limitations.
Holding storage capacity over a longer period could be obtained as a result of swaps among different users of
capacity.
397
In Belgium a slot includes unloading, storage and re-gasification capacity for 10 days
398
For France, the calculation is not possible for less than 30 days, since GdF proposes only a constant emission during
30 days for a spot cargo. Nevertheless, it is technically possible to decrease the number of days of emission by using
the secondary market on the point of exchange of LNG.
399
See footnote 396.
400
Berthing times of slots can limit the overall capacity of the terminal if they are too long. Unloading times of vessels
are always less than 24 hours. Nevertheless berthing slots in some countries have a duration of 1 day and in others of
5 days. In some cases the access conditions to the grid discourage utilisation of slots.
401
NERA is currently preparing a study for CEER/ERGEG which has as its main topic the various regulatory
approaches to LNG re-gasification terminals. This study can be expected to make a valuable contribution to such
discussion.
ENERGY SECTOR INQUIRY – SECOND PHASE (Gas)
282
Conclusions
LNG supplies widen Europe’s upstream supplier base and are important for
both security of supply and competition between upstream suppliers.
The potential of LNG supplies to reduce concentration on downstream markets
still needs to be realised.
Traditionally LNG has been imported by national incumbents who also own LNG
terminals, which has not permitted the potential of LNG imports to increase
downstream competition to be realised. Recent trends, however, point to more
capacity going to new entrants and to producers themselves. This is likely to have a
positive impact on fostering downstream competition unless such effects are frustrated
by access, LNG-storage or emission rules with negative effects on competition, or by
anti-competitive behaviour.
Strong investment in LNG terminals has taken place and is scheduled to continue in
the coming years. Investment in some LNG terminals has benefited from exemptions
from third party access obligations under a test applied by national regulators under
Commission supervision. This test seeks to achieve a balance between ex ante
incentives to invest and competition once the investment has been made.
The regulatory regime to be put in place in the EU needs to ensure efficient short-term
access to unused slots and to prevent any foreclosure of the market.
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283
c. ELECTRICITY
I. Downstream market
(921)Competition at the retail level is an essential element of well-functioning markets. The
confidence of electricity consumers in the liberalisation process relies precisely on
effective downstream competition. Moreover, any imperfections of the retail market can
be expected to have serious spill-over effects for the wholesale markets including
generation activities (and vice-versa). If retailers do not have to vigorously compete for
final customers, they also do not need to secure the lowest cost generation portfolio,
whether it is their own production or from other producers. Thus competitive pressure
from the demand side is required for effective wholesale trade. This in turn increases the
risk of collusion between wholesale suppliers.
(922)Even if the wholesale trade is highly concentrated, customers can still benefit from the
existence of competitive downstream markets. Competition at the retail level prevents
double marginalization, which occurs when downstream firms mark up over their input
cost. Hence, thanks to competition on the downstream market, a mark-up on a mark-up,
i.e. double marginalization, is less likely.
(923)This chapter gives an overview of some basic features of the downstream market. It
essentially deals with the question of possible market foreclosure through long-term
supply contracts and the number of the offers from competitors available for customers.
The chapter aims at providing provide some indication as to the level of downstream
competition.
(924)The focus of the chapter is on the industrial clients. These industrial customers were first
to become eligible, so this segment of the retail market has the longest history of being
open to competition. Furthermore, it encompasses the most attractive clients in terms of
consumption volumes. Finally, the industrial clients, all other things being equal, are the
best informed consumers, whose price sensitivity is expected to be the highest among all
customers.
I.1. Foreclosure on downstream markets
(925)The concept of downstream foreclosure refers to the anti-competitive effects which can
arise from a bundle of parallel long-term agreements between final customers and their
suppliers - be it a dominant supplier or a network of suppliers engaging in the same type
of practice402
. A network of parallel contracts can adversely affect the market when the
contracts prevent alternative suppliers from finding suitable outlets for their products.
The customers have met their entire demand – or a large part thereof - on the basis of
long-term contracts with incumbent suppliers and are thus no longer available on the
market.
402
Suppliers with a market share not exceeding 5% are in general not considered to contribute significantly to a
cumulative foreclosure effect (De-minimis Notice, OJ of 22.12.2001, C368, p. 13).
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
284
(926)When assessing long-term exclusive supply relationships at least the following four
elements will normally be taken into account403
:
- the volumes tied under the individual contracts (exclusivity)
- duration of the contracts
- cumulative market coverage of the contracts, and
- efficiencies claimed by the parties (e.g. recuperation of sunk investments) 404
.
Whereas efficiencies are to be considered on a case by case basis, the other three criteria
(exclusivity, duration, and cumulative market coverage) will be examined in turn in order
to obtain a first indication on whether downstream contracts raise barriers to entry. In the
present context the intention is not to spell out in which circumstances such contracts may
be incompatible with Articles 81 and 82, but to ascertain whether from a factual point of
view new entry and expansion by other market players is made more difficult.
I.1.1.Exclusivity
(927)From the market foreclosure perspective, contractual exclusivity provisions are the most
common tools to ring-fence the customers from potential competitors throughout the
entire contractual period. As described in the downstream chapter for gas, these
provisions may take the form of either de jure or de facto obligations to meet most of or
the entire demand from a given electricity provider.
(928)De jure obligations oblige the customer to meet its entire demand or a very high (fixed)
percentage thereof with the current supplier. De facto obligations can take a variety of
forms. They may be created through tight scheduling of the off-take quantities based on
historical data (fixing past consumption levels as minimum off-take). Suppliers may also
apply other clauses, which can strengthen the impact of the above-mentioned provisions.
For example, suppliers might remove the necessary flexibility that previously existed in
contracts to switch at least for partial deliveries to an alternative supplier or they may
give customers an incentive (e.g. through rebates) to take all or large part of their
requirements from the incumbent supplier.
(929)In the framework of the Sector Inquiry, a number of suppliers selling electricity to final
customers were asked to provide copies of their standard contracts which they offer to
eligible end-consumers with an annual consumption equal to or larger than 5 GWh405
.
The analysis of these standard contracts has confirmed that most of these contracts
contain provisions which give rise to de facto exclusivity of supply during the entire
duration of the contracts. The suppliers require the customers to sign up to a specific offtake
obligation that is usually fixed at values close to the customers’ total consumption.
Such an off-take obligation is often additionally sheltered by a take-or-pay clause or an
excess charge that are to be applied when actual consumption diverges from an off-take
403
See DG Competition discussion paper on the application of Article 82 of the Treaty to exclusionary abuses page 42f.
Other issues that can be taken into account include: other entry barriers, the nature of the customer (key customer
justifying a market entry in its own right) and countervailing buyer power.
404
See paragraph 44 of the Commission Guidelines on the application of Article 81(3) of the Treaty [2004], OJ
C101/97. The present chapter, which aims at describing markets, deals with the first three elements. However, in the
application of Articles 81 and 82 to individual cases all four elements are taken into account.
405
This does not, however, exclude that certain customers, in particular the biggest customers, are offered tailor-made
contracts to suit their requirements. For example, one of the UK suppliers informed about its commercial policy to
offer the ‘over 120 GWh customers’ a possibility of splitting their purchases into separate tradable products.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
285
forecast. One of the standard contracts from the sample explicitly obliges a customer to
agree ‘to take only from the Supplier its total requirements of electricity at each of the
Customer’s Premises during the Term [of the agreement]’.
I.1.2.Duration of contracts
(930)The second important element to consider when assessing downstream foreclosure, is the
duration of contracts406
. As explained above long-term contracts curb the customers’
mobility and prevent the customers from choosing the best offer available on the market
at a given moment in time. On the other hand, depending on the structure of the
individual contract, in particular the price formula contained in the contract, long
duration may allow the customers to better manage the risks related to adverse price
movements, to which they would otherwise be exposed. The benefits of price security,
which for certain customers may represent a real value, may not however outweigh the
negative effects on competition and overall consumer welfare of long-term contracts on
market contestability. This fact must also be considered when discussing the recent calls
for re-introduction of long-term reservations (of the already congested and scarce
interconnections) in order to enable long-term supply contracts.
(931)Contracts can be signed for a fixed or an indefinite period. In the first case, the original
contract term may be subject to a tacit renewal clause. Tacit renewal seems to have a
constraining effect on customer switching. For the purpose of competition analysis,
contracts containing such a clause are usually considered to have a similar impact on the
market as contracts of indefinite duration, particularly for small customers for whom the
electricity price is only a minor proportion of overall productions costs.
(932)The Sector Inquiry shows that when the standard contracts foresee a specific term, as is,
for instance, the case in the United Kingdom, France and Germany, the agreement is
usually signed for the period of 12 months or of a factor of 12 months (for more on the
duration of contracts see Figure 89 to Figure 95 ). These standard contracts often contain
a tacit renewal clause, which applies in the absence of prior notice to terminate the
agreement.
(933)A notice period is another time-related element which has to be considered when
assessing the duration of contracts. Whilst the possibility to terminate a contract would
seem to allow a customer – at least in principle - to look for alternative suppliers, other
elements might need to be considered, such as incentives not to make use of the
possibility or obstacles to effectively exercise the possibility to terminate the contract
(see also above on tacit renewals of a contract). A long notice period implies that the
customer must have a new contract with an alternative supplier in place long before the
existing contract expires. A short notice period on the other hand gives him the
opportunity to find an alternative supplier shortly before the contract expires. For the
alternative supplier this means that he has better knowledge as regards his ability to
deliver. A long notice period has a price-wedge effect creating expectations of a risk
premium both on the demand and supply side. Consequently, it lowers the likelihood of
switching.
406
The Bundeskartellamt recently adopted a decision against long-term supply contracts in the proceedings against
E.ON Ruhrgas AG (Bundeskartellamt, 8. Beschlussabteilung, B8 -113/03 -1, 13 January 2006). The immediate
enforceability of the Bundeskartellamt decision was confirmed by the Düsseldorf Higher Regional Court (VI-2 Kart
1/06 (V), 20 June 2006).
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
286
Table 50
From To
France
Germany 3 months 6 months
United Kingdom 28 days 60 days
Notice period
Country
45 days
Source: Energy Sector Inquiry 2005/2006
(934)The Sector Inquiry reveals that notice periods differ between Member States as well as
between individual suppliers (see Table 50). In the United Kingdom, notice periods range
from 28 to 60 days. In France, the standard contracts fix a notice period at 45 days,
whereas in Germany the most common notice period is 3 months. The threefold, or even
sixfold, difference in the duration of notice periods appears to be rather high, especially
taking into account that the level of risk faced by the big suppliers on the three markets in
question is similar. The shorter duration in UK contracts shows that short time notice
periods do work in practice.
I.1.3.Cumulative effect
(935)The final element to be considered in the foreclosure analysis is the cumulative market
coverage of the bundle of contracts. Since electricity markets are characterised by a high
level of maturity, which manifests itself in a relatively low number of new connections to
the grid as compared to the total number of customers, the bulk of new clients can only
be recruited among existing customers by means of lower prices and/or better terms and
conditions of sales. However, in order to profit from a competitive offer, the existing
customers must be first free to switch. One occasion where such conditions typically
prevail are households changing their residence. On that occasion, in principle, a
considerable number of potential clients are free to switch or even have to decide on a
new supplier. Mobilizing this market might therefore facilitate market entry by new
suppliers. However that means specific rules whereby new entrants get access to
necessary data about customers who are moving house.
(936)If a good part of demand or the commercially most attractive customers are tied by longterm
contracts, it leads to a situation in which the new entrant suppliers are effectively
foreclosed from the market.
(937)Figure 89 to Figure 95 demonstrate the impact of contracts of different durations on the
electricity markets in Belgium, Czech Republic, Hungary, Poland, Germany, France and
United Kingdom. The figures are based on the replies of industrial customers who were
asked to submit information concerning electricity supply contracts for each site with an
annual consumption of over 1 GWh during 2004407
. With a few exceptions, there was
only one contract per industrial site, which suggests that a large majority of the contracts
is at least de facto exclusive.
(938)The analysis of the cumulative market coverage of supply contracts consists of two parts.
First, the total duration is verified and then the results are recalculated to reflect the time
remaining before the supply contracts expire. The latter calculation shows after how
many months the customers and the demand quantities represented by them were
407
The sample includes a limited number of supply contracts predating the liberalisation of the electricity sector.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
287
expected, as of 1 June 2005, to return to the market in search for new offers408
. For those
months, the part of the overall demand tied in the existing supply contracts was
unavailable for potential competitors which would seek an opportunity to enter the
incumbent’s market.
Figure 89
41,869 GWhFinal electricity consumption – Industry and Transport (in 2004)
38 sites Total contracted supplies 10,342 GWhNumber of sites
Sample size
41,869 GWhFinal electricity consumption – Industry and Transport (in 2004)
38 sites Total contracted supplies 10,342 GWhNumber of sites
Sample size
7
24
63
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
40Simple average
92Consumption weighted average
Months till expiry (as on 1 June 2005)
24Most frequent contract duration (mode)
Statistics on contract duration (in months)
7
24
63
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
40Simple average
92Consumption weighted average
Months till expiry (as on 1 June 2005)
24Most frequent contract duration (mode)
Statistics on contract duration (in months)
Belgium
Contract duration
Months till expiry (as on 1 June 2005)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Contract duration
(in months from start to expiry date)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Source: Energy Sector Inquiry 2005/2006, Eurostat Energy Statistics
(939)Figure 89 shows that a vast majority of demand from industrial customers in Belgium is
tied by contracts which were to continue for a period of 37 and more months calculated
from 1 June 2005. Nearly 70% of the total contracted supplies in the sample were
originally agreed for a period exceeding 5 years. The difference between the weighted
and the simple average contract duration till expiry, 63 and 24 months respectively,
indicates that the most important contracts in terms of quantity are foreclosed for
potential new entrants for the longest time. The statistics on contract duration also show
that the duration of contracts was increasing before the date of the Sector Inquiry,
because the remaining period till expiry is longer than a half of their total duration.409
408
In order to make the statistical picture as complete as possible, the duration of retail contracts is described with three
measures, these are: weighted average, simple average, and mode (the value that appears most often in the data set).
409
Another possible explanation would be that an external factor, for instance opening of the market, ushered in a new
wave of long-term contracts that have not, for the time-being, reached their mid-term and thus they bias the sample.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
288
Figure 90
24,526 GWhFinal electricity consumption – Industry and Transport (in 2004)
59 sites Total contracted supplies 3,985 GWhNumber of sites
Sample size
24,526 GWhFinal electricity consumption – Industry and Transport (in 2004)
59 sites Total contracted supplies 3,985 GWhNumber of sites
Sample size
7
7
7
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
17Simple average
14Consumption weighted average
Months till expiry (as on 1 June 2005)
12Most frequent contract duration (mode)
Statistics on contract duration (in months)
7
7
7
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
17Simple average
14Consumption weighted average
Months till expiry (as on 1 June 2005)
12Most frequent contract duration (mode)
Statistics on contract duration (in months)
Contract duration
Months till expiry (as on 1 June 2005)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Czech Republic
Contract duration
(in months from start to expiry date)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Source: Energy Sector Inquiry 2005/2006, Eurostat Energy Statistics
Figure 91
10,590 GWhFinal electricity consumption – Industry and Transport (in 2004)
27 sites Total contracted supplies 2,301 GWhNumber of sites
Sample size
10,590 GWhFinal electricity consumption – Industry and Transport (in 2004)
27 sites Total contracted supplies 2,301 GWhNumber of sites
Sample size
7
5
7
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
15Simple average
12Consumption weighted average
Months till expiry (as on 1 June 2005)
12Most frequent contract duration (mode)
Statistics on contract duration (in months)
7
5
7
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
15Simple average
12Consumption weighted average
Months till expiry (as on 1 June 2005)
12Most frequent contract duration (mode)
Statistics on contract duration (in months)
Contract duration
Months till expiry (as on 1 June 2005)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Hungary
Contract duration
(in months from start to expiry date)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Source: Energy Sector Inquiry 2005/2006, Eurostat Energy Statistics
(940)In the Czech Republic and Hungary (see Figure 90 and Figure 91), the opposite trend can
be observed. Although the size of the respective samples in terms of contracted supplies
is too small to draw any firm conclusions, it is sufficient to notice the predominance of
one-year contracts overlapping with the calendar year (hence, on 1 June 2005, most of
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
289
the contracts were to expire in 7 months, that is at the end of the calendar year).410
Perhaps the same conclusion, as to the trend, could be drawn for Poland (see Figure 92).
However, the Polish sample contains a very limited number of sites and in addition is
biased due to the impact of two particularly long contracts that were signed for 25 and 30
years respectively. This is, however, a natural consequence of the tiny size of nonregulated
market in Poland, where, in 2005, only 35 users exercised their eligibility
purchasing some 12 TWh.
Figure 92
46,670 GWhFinal electricity consumption – Industry and Transport (in 2004)
12 sites Total contracted supplies 9,891 GWhNumber of sites
Sample size
46,670 GWhFinal electricity consumption – Industry and Transport (in 2004)
12 sites Total contracted supplies 9,891 GWhNumber of sites
Sample size
7
47
44
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
72Simple average
60Consumption weighted average
Months till expiry (as on 1 June 2005)
12Most frequent contract duration (mode)
Statistics on contract duration (in months)
7
47
44
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
72Simple average
60Consumption weighted average
Months till expiry (as on 1 June 2005)
12Most frequent contract duration (mode)
Statistics on contract duration (in months)
Contract duration
Months till expiry (as on 1 June 2005)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Poland
Contract duration
(in months from start to expiry date)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Source: Energy Sector Inquiry 2005/2006, Eurostat Energy Statistics
(941)A more robust picture emerges from the German data (see Figure 93). The average
duration of the supply contracts in case of the German industrial customers has been
decreasing over time along with a certain number of long-term contracts approaching
their term. The most common contract is signed for 24 months and, on 1 June 2005, was
expected to expire in 7 months. The difference in the duration of the supply contracts
struck for the sites with relatively high and low consumptions has also been narrowing
down. The German sample, however, excludes a number of smaller contracts that were
signed for unlimited periods or have a tacit renewal clause and thus could not been
included in the calculations without an attribution of certain arbitrary duration to this
group of contracts.
410
In this context, it is interesting to note that, both in Hungary and Czech Republic, the downstream contract periods
overlap with the January-December terms adopted for the annual cross-border capacity auctions in the two countries
as well as for the annual VPP auctions run by CEZ, the Czech incumbent.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
290
Figure 93
250,042 GWhFinal electricity consumption – Industry and Transport (in 2004)
255 sites Total contracted supplies 32,806 GWhNumber of sites
Sample size
250,042 GWhFinal electricity consumption – Industry and Transport (in 2004)
255 sites Total contracted supplies 32,806 GWhNumber of sites
Sample size
7
16
23
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
37Simple average
69Consumption weighted average
Months till expiry (as on 1 June 2005)
24Most frequent contract duration (mode)
Statistics on contract duration (in months)
7
16
23
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
37Simple average
69Consumption weighted average
Months till expiry (as on 1 June 2005)
24Most frequent contract duration (mode)
Statistics on contract duration (in months)
Contract duration
Months till expiry (as on 1 June 2005)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Germany
Contract duration
(in months from start to expiry date)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Source: Energy Sector Inquiry 2005/2006, Eurostat Energy Statistics
Figure 94
146,332 GWhFinal electricity consumption – Industry and Transport (in 2004)
159 sites Total contracted supplies 13,701 GWhNumber of sites
Sample size
146,332 GWhFinal electricity consumption – Industry and Transport (in 2004)
159 sites Total contracted supplies 13,701 GWhNumber of sites
Sample size
55
37
26
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
54Simple average
46Consumption weighted average
Months till expiry (as on 1 June 2005)
57Most frequent contract duration (mode)
Statistics on contract duration (in months)
55
37
26
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
54Simple average
46Consumption weighted average
Months till expiry (as on 1 June 2005)
57Most frequent contract duration (mode)
Statistics on contract duration (in months)
Contract duration
Months till expiry (as on 1 June 2005)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
France
Contract duration
(in months from start to expiry date)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Source: Energy Sector Inquiry 2005/2006, Eurostat Energy Statistics
(942)The French market is characterised by a variety of contractual periods. Although the
category of the contracts of 37 and more months till expiry represents only some 20% of
the total contracted supplies from the sample, the number of contracts to expire in the
course of next 12 months was, on 1 June 2005, noticeably lower than in Germany and
UK, not to mention the East European markets in the Czech Republic, Hungary and
Poland.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
291
Figure 95
125,183 GWhFinal electricity consumption – Industry and Transport (in 2004)
112 sites Total contracted supplies 10,237 GWhNumber of sites
Sample size
125,183 GWhFinal electricity consumption – Industry and Transport (in 2004)
112 sites Total contracted supplies 10,237 GWhNumber of sites
Sample size
10
13
17
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
19Simple average
37Consumption weighted average
Months till expiry (as on 1 June 2005)
12Most frequent contract duration (mode)
Statistics on contract duration (in months)
10
13
17
Most frequent contract duration (mode)
Simple average
Consumption weighted average
Contract duration (in months from start to expiry date)
19Simple average
37Consumption weighted average
Months till expiry (as on 1 June 2005)
12Most frequent contract duration (mode)
Statistics on contract duration (in months)
UK
Contract duration
Months till expiry (as on 1 June 2005)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Contract duration
(in months from start to expiry date)
0%
20%
40%
60%
80%
100%
0-12 13-24 25-36 37-60 61+
months
%ofthetotal
contractedsupplies
fromthesample
Source: Energy Sector Inquiry 2005/2006, Eurostat Energy Statistics
(943)In the United Kingdom, the supply contracts offered to the industrial customers are of
relatively short duration. The predominant number of sites has contracts signed for 12
months, and these are 71 out of 112 sites within the presented sample. This duration can
be also considered to be at the bottom end of the scale since only a few contracts were
signed for less than 12 months. Finally, it must be noted that the UK weighted averages
are influenced by the existence of a single 9-year contract covering some 2.2 TWh. If that
contract was excluded from the sample, the difference between the weighted and the nonweighted
average contract durations would substantially narrow down. New weighted
averages, expressed in time till contract expiry and in overall contract duration, would
amount to 10 and 17 months, respectively.
I.2. Number of offers
(944)When a supply contract expires, the customer is potentially free to turn to the market in
search for the best offers. In this context, the degree of customer choice is largely
dependent on the number of competitive offers available on the market. In the framework
of the Sector Inquiry, industrial customers provided information on the number of
companies that had been invited to tender for supplies to the customers’ individual sites
as well as on the number of the suppliers that, in the end, submitted offers.
(945)The number of companies that are invited to tender can be considered a first indicator of
whether customers expect to find any potentially competitive offers on the market. All
other things being equal, the lower this number, the weaker competition on the
downstream market is likely to be and also the lower are the chances that the customer
will receive competitive offers.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
292
Figure 96
0
2
4
6
8
10
Belgium
(36 sites, 10,232
GWh)
Czech Republic
(53 sites, 2,438
GWh)
Germany
(233 sites, 30,521
GWh)
France
(147 sites, 13,271
GWh)
Hungary
(27 sites, 1,969
GWh)
Poland
(9 sites, 9,177 GWh)
United Kingdom
(103 sites, 7,548
GWh)
No of tender invitees - non-weighted average No of offers - non-weighted average
Source: Energy Sector Inquiry 2005/2006
(946)Data for a selection of national markets, including both the old and the new Member
States (see Figure 96) indicate that the situation varies substantially between the
individual markets. The Belgian and the French industrial customers invite the lowest
number of companies to tender and also receive the lowest number of offers. In Belgium,
the weighted average number of offers is close to two, which means that some sites may
have problems finding any alternative offers.
(947)Both in France and Belgium, industrial customers most frequently receive only one offer
(see Figure 97). This situation concerns some 30 per cent of industrial customers in the
respective samples. At least half of the industrial customers in these two Member States
invite only three or less companies to tender. This situation mirrors the high market
concentration ratios reported for the two Member States in question (see chapter
B.b.II.1).
(948)The values for other Member States like Germany, United Kingdom, Czech Republic,
Hungary and Poland look more favourable (see Figure 96). However, these values are not
directly comparable. First of all, the results for Member States like Hungary and Poland
have to be analysed with much caution due to the small proportion of eligible customers
exercising their rights in these two Member States. In addition, the customers on the
newly liberalised markets are, all other things being equal, more likely to have difficulties
in identifying potential suppliers that will submit truly competitive offers. It is natural
that such customers show a tendency to send more, but less targeted, invitations to tender
than the better informed customers operating in more mature markets. As a matter of fact,
this is also the most plausible explanation for the mid-range values and the high tender
response ratio observed in the UK, whilst Hungary and Poland are characterised by a
relatively low response rate.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
293
Figure 97
0
1
2
3
4
5
6
7
8
9
10
Belgium
(36 sites, 10,232
GWh)
Czech Republic
(53 sites, 2,438
GWh)
Germany
(233 sites, 30,521
GWh)
France
(147 sites, 13,271
GWh)
Hungary
(27 sites, 1,969
GWh)
Poland
(9 sites, 9,177
GWh)
United Kingdom
(103 sites, 7,548
GWh)
Numberofoffers
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percentageofthemostfrequentvalueinthesample
No of offers - most frequent value (mode) Share of the most frequent value in the sample
Source: Energy Sector Inquiry 2005/2006
(949)In Germany, United Kingdom, Czech Republic, Hungary and Poland, industrial
customers are on average able to discern at least 5-6 potential suppliers to which they
send invitations to tender. The response rates are on average higher than 3.4 offers per
tender (see Figure 96). The results for Germany and United Kingdom suggest that large
customers invite few companies to tender and also obtain fewer offers than small
customers. Whilst, in the context of this inquiry, it is not appropriate to speculate about
the reasons for these facts, one possible explanation may be that large customers often
have more complex needs, for instance, they may require ancillary services, and therefore
not all suppliers are in position to make appropriate offers.
(950)Before concluding on the chapter, it must be noted that the number of offers do not in
themselves make the market more or less competitive. For example, so-called defensive
offers, where an offer is only made in order to fulfil a perceived legal obligation (antitrust
scrutiny concerning market allocation) to respond to a tender invitation, might inflate the
statistics and thus falsify the true picture. Customers must have a choice of competitive
offers that reflect real competitive effort. If such a competitive offer is made by a new
entrant, the result should be the switching of a given customer away from the
incumbent.411
411
For the statistics on switching, see: Technical Annex to the Report on Progress in Creating the Internal Gas and
Electricity Market, p.38 http://ec.europa.eu/energy/electricity/report_2005/doc/2005_report_technical_annex.pdf
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
294
I.3. Use restrictions
(951)The assessment of the standard contracts gathered in the context of the SI has also
revealed that some contracts contain so-called use restrictions. Use restrictions oblige the
buyer to use electricity only on site and/or only for their own purposes. Any further
transmission/resale to third parties, if allowed at all, requires the supplier’s written
approval. It is obvious that resale clauses undermine the possibilities of arbitrage and
therefore will enable a given supplier to price discriminate between his individual
customers.
Conclusions
The degree to which the industrial customers are tied to incumbent suppliers on a long
term basis differs significantly between Member States. In some countries, the duration of
retail contracts may have a substantial impact on the possibilities of alternative suppliers
to successfully enter the market.
The number of competitive offers that customers receive differs significantly between
Member States. In some countries characterised by a high level of concentration in
generation the number of offers is particularly unsatisfactory.
Certain standard contracts contain use restrictions which may raise competition concerns.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
295
II. Balancing in the liberalised electricity market
II.1. Introduction
(952)Maintaining a constant balance between electricity supply and demand on electricity
transmission networks is important to ensure system stability. Ensuring system balance is
a complex task because electricity -contrary to gas- cannot be stored and deviations from
supply and demand occur more regularly. This requires TSOs to constantly monitor the
network and to take corrective (balancing) measures when needed. In practice this means
that a TSO in charge of a control area must either be able to call on certain generators to
increase or decrease production at short notice. The same effect can be achieved by an
increase or decrease in consumption (upward or downward regulation).
(953)Balancing mechanisms are not only a technical issue to ensure system stability, but have
also important commercial implications and in turn implications for effective
competition. This is due to the fact that TSOs need to procure balancing services from
generators that might also have supply interests in the market concerned. Furthermore
balancing services do not come for free, they are paid for by network users. As for gas,
the provision of balancing services constitutes a “market of last resort” for network users.
The way in which this “market” functions is likely to have knock-on effects on the entire
wholesale market.
(954)For the purpose of this chapter balancing services are defined as including all activities
that TSOs engage in order to ensure system stability and accordingly all costs charged to
network users for these services.412
In a nutshell TSOs buy both balancing capacity
(MW) and balancing energy (MWh) from generators that are technically capable of
supplying reserve power or balancing energy at short notice. The TSOs then charge the
costs associated with balancing to the network users either in form of network tariffs
(most prominently for their capacity reservations in plants offering reserve power) and/or
in form of direct payments for balancing energy. The figure below schematically
illustrates this relationship.
412
In economic literature “balancing markets” are generally defined as a small element of the balancing mechanisms
described here. They are understood as merely comprising the market/platform where market participants can place
short term (e.g. day ahead) bids to the TSO to provide incremental (generate more or consume less) and decremental
(generate less or consume more) production.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
296
Figure 98
TSO
Generator 1
Generator 2
Generator 3
Generator 4
Generator n
Consumers 1
Consumers 2
Consumers 3
Traders 1
Traders 2
Traders 3
Other network users 1
Other network users 2
Other network users 3
Network users
Network
Illustration of network users
TSO
Generator 1
Generator 2
Generator 3
Generator 4
Generator n
Consumers 1
Consumers 2
Consumers 3
Traders 1
Traders 2
Traders 3
Other network users 1
Other network users 2
Other network users 3
Network users
Network
Illustration of network users
Source: Energy Sector Inquiry 2005/2006
(955)It is obvious that balancing mechanisms should be as efficient as possible and contribute
to competition in related electricity markets (e.g. supply). This chapter will demonstrate
however, based on information gathered in the Sector Inquiry, that balancing markets are
highly concentrated. Due to this concentration, TSOs, who do not own generation assets,
are often faced with few suppliers (generators) who can supply balancing capacity and
balancing power. Further, vertically integrated TSOs will often procure balancing
capacity and power from their affiliate companies i.e. intra-group. This may affect their
motivation in designing such mechanisms.
(956)There are two main concerns that may result from this. First, there is a risk that network
users are exposed to excessive imbalance charges when paying for the balancing power
(MWh) supplied by the generators via the TSO in order to restore imbalances. In
particular it may eat away the profits of supply companies with a small supply portfolio,
for which changes in the off-take by one customer are less likely to be compensated by
corresponding changes in off-take by other customers. This can constitute a barrier for
entry in the supply market. Ultimately it decreases scope for competition as it reduces the
number of supply companies that consumers can choose from. Secondly, there is a risk
that all network users are charged an excessive tariff for using the network, when TSOs
pay excessive prices for balancing capacity (MW) to generators. These costs are usually
fed into the network tariffs and in the end passed on to the end users of electricity.
Because some TSOs are vertically integrated with incumbent generators some market
participants are concerned that such TSOs may not address both two issues adequately,
resulting in a transfer of consumer welfare to producers.
(957)There is also a concern that in some Member States, more capacity is purchased by the
TSOs than is strictly necessary, because incumbent generators who are affiliated to the
TSO are the main suppliers of balancing services. This may result in under-utilisation of
generation and increase prices in wholesale markets more generally. Also, this chapter
will show that significant differences in balancing rules and designs undermine the
creation of an integrated market and cause unnecessary complexities for cross border
trade. The chapter will start with a general description what balancing markets are, how
they work and what their relevance is to electricity markets.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
297
(958)This chapter does not aim to cover all issues relevant to electricity balancing mechanisms.
The focus is to present the results of the Sector Inquiry (e.g. level of concentration) and
will for instance only touch briefly on certain market design issues (e.g. whether
imbalances are settled at a single or a dual price). In comparison with the corresponding
chapter for gas, this chapter will in particular not deal in any detail with the actual level
of imbalance prices and penalties paid by network user and/or other commercial
conditions governing the relationship between network users and the TSO. This is not
due to the fact that there might not be concerns for the functioning of the markets, but
rather that no information was gathered in the context of the inquiry for this aspect of the
balancing markets.413
II.1.1. Importance for balancing in liberalized markets
(959)Maintaining a balance at all times between electricity supply and demand is a complex
task, since electricity cannot be stored. Maintaining a constant balance is complicated
because transactions made by generators, traders, suppliers and consumers result in
complex electricity transmission within and between regions. When balancing fails, the
stability of the network is jeopardized and disturbances can occur.
(960)The total volumes that pass through balancing markets are quite small. For instance the
total upward balancing power used as a percentage of consumption (2004) was in the
United Kingdom 0.04%, in Belgium 0.3%, in Germany 0.43% and in Spain 1.3%.
Although these volumes are modest (related to the overall consumption) the design of a
balancing mechanism has an important impact on the overall performance of liberalised
electricity markets, as prices charged for balancing power send important scarcity signals
for the related (supply) market. Improper design may ultimately lead to welfare loss due
to entry barriers for (new) market participants.
(961)An inefficient and unreliable balancing market may create barriers to entry for supply
companies who do not have generation of their own or for new generators without an
existing portfolio of customers. Because retail consumption is impossible to predict with
complete certainty, a supplier without flexible production facilities often has to rely on
the balancing market. The supplier has to pay for this and this reduces the profitability for
his supply business. This is confirmed in some SI answers.
II.2. General description of a typical balancing mechanism
(962)The main task of TSOs is to provide a secure and stable high-voltage grid operation. This
includes activities to balance supply and demand in their own so-called control area and
between control areas, which contributes to ensuring the global system balance. In most
Member States a single TSO fulfils these tasks and these Member States have one single
control area. Some Member States have more than one control area (e.g. Italy, Germany
and Denmark) and each is run by a separate TSO – except for Italy who has a single
TSO. To manage commercial transactions and physical flows in a secure (balanced)
manner, TSOs employ a set of technical and administrative rules. Jointly these rules are
referred to as balancing mechanisms. Though these rules differ across Member States the
section below attempts to explain how these rules generally work and what TSOs do.
413
With the same token this chapter does not deal with the number of balancing zones (which is a major issue for the
gas sector). It should be noted that the size of the balancing zones is also a concern for the electricity sector, however
balancing zones appear to be larger when comparing electricity with gas.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
298
(963)Given the need to ensure “second by second” balance of supply and demand in the grid,
at some point trading by market participants has to cease and the system has to pass from
decentralized trading to centralised control by the TSO. That point is generally referred to
as ‘Gate Closure’414
. Prior to this moment, trade amongst market parties may take place
across a number of different timescales, for instance day ahead, month ahead and year
ahead. In these periods before Gate Closure market participants will typically aim to
cover their expected physical positions (i.e. suppliers contract to purchase electricity to
cover their customer demand, or generators contract to sell energy from their power
stations).
(964)At Gate Closure, all participants submit data to the TSO setting out: (i.) intended
consumption schedules for the next period by location (normally per control area); (ii.)
intended production schedules for the next period by location (control area) and (iii.)
commercial trading schedules. Once these data have been passed to the TSO, bilateral
trading for physical delivery at Gate Closure should cease.
(965)Normally after this phase the positions of each market party are supposed to be in
balance. In practice, however, deviations between supply and demand occur because
participants may not produce or consume the exact volume they expected. Deviations
could be caused for instance due to unforeseen generation plant failure, changes in
demand, changes in wind speed and/or changes in imports/exports. To ensure a continued
secure grid operation, the TSO must therefore have:
• sufficient reserve production available on the system
• the ability to call up plants to increase or decrease power on the system
• enough network capacity.
(966)The increase (or decrease) in generation or decrease (or increase) in consumption
required to balance supply and demand may come in various forms, each with particular
physical and economic characteristics. For example, there may be relatively few
generation plants in the system, which can respond very quickly (e.g. within few
seconds) to a shortfall or surplus in demand and the capacity available may be relatively
expensive to run. Hence, the price for such short-term flexibility may be high. There may
be more plants available, which can respond over a longer timescale – and these plants
may also be cheaper to operate. In general TSOs procure a range of different types of
reserve. In general one can distinguish between immediate reserve to allow TSOs to cope
with short-term deviations, and less immediate reserve, which can be used to replace the
more expensive fast reserve once the immediate imbalance has been addressed. For the
UCTE area (essentially the entire Continental Europe415
) these different types of reserves
are set out in Table 51.
414
Gate Closure is the point in time when market participants notify the TSO of their intended final physical position
and is for example set at one hour ahead of real time. In addition no further contract notification can be made.
415
See: http://www.ucte.org/
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
299
Table 51
Primary control Secondary control Tertiary control
Why is the control used?
To stabilize the frequency in
case of an imbalance
To bring back the frequency
and the interchange programs
to their target
To restore the secondary
control reserve, to manage
eventual congestions, and to
bring back the frequency and
the interchange programs to
their target if the secondary
control reserves is not
sufficient
How is control achieved? Manually
Where is this control
performed?
Locally
Who sends the control
signal to the source of
reserve?
Local sensor TSO
Generators, Consumers or the
TSOs (after receiving
instructions from the TSO)
When is the control
activated?
Immediately Immediately (seconds) Depends on the system
What sources of reserves
can be used?
Characteristics of the three frequency control levels in UCTE
Automatically
Centrally (TSO)
Depends on the system: partially loaded units, loads, fast/slow starting unites, changes in
exchange programs
Source: ETSO (2006).
Note: in this chapter “control” is referred to as “balancing power”.
(967)Primary power (approx. 3000 MW for all of UCTE) is only used for making very small
corrections (within seconds) and is in particular needed because small disturbances in a
particular place cannot immediately be restored by plants located thousands of kilometres
away. Primary power is not activated by TSOs, is often not bought in a separate market
nor is it tendered by each TSO and constitutes a relative small proportion of all reserve
powers. Therefore this type of power was not the focus of the Sector Inquiry and is not
further addressed in this chapter.
(968)Secondary power is activated by TSOs to replace primary power. In order to be able to
effectively supply to a TSO secondary power, a power plant needs to be directly
connected to the TSOs’ command centre and it should have a sufficiently fast respond
time to increase production.416
Only then can it be called up by the relevant TSO to make
the necessary immediate balancing corrections. This could be done upwards or
downwards in a time frame of seconds until typically 15 minutes.
(969)Tertiary power is less immediate power and can be called up by TSOs with some delay.
This type of power frees secondary control by re-scheduling power plants manually.
Plants must meet a set of technical criteria in order to qualify for the provisions of these
balancing services.
II.2.1. TSOs contract balancing capacity
(970)Because TSOs do not own generation capacities they need to undertake procurement
(capacity) with longer term (e.g. one year ahead) arrangements from generating
companies to ensure that sufficient system services of the types above will be available in
relation to specific delivery periods. This is sometimes referred to as “spinning reserves”,
which is capacity that is on line ready to be called up on by the TSO when balancing
power is needed. Hence, prior to Gate Closure the TSO will enter into contracts with
participants, under which the participants guarantee to be available to provide reserves.
416
For instance, in the Netherlands the TSO asks for a reaction speed of 30 seconds and the plant should be able to
increase output 7% per minute.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
300
This is often done by means of half-yearly or yearly tender procedures. The contracts
typically specify the technical characteristics of the service required, the required
availability (=capacity), and a price – either for energy provided only, or for both
availability (capacity) and energy.
Figure 99
Total monthly upward reserves purchased by TSOs
selected MS
8 000
9 000
10 000
11 000
12 000
13 000
14 000
15 000
16 000
Jan-03
Mar-03
May-03
Jul-03
Sep-03
Nov-03
Jan-04
Mar-04
May-04
Jul-04
Sep-04
Nov-04
Jan-05
Mar-05
May-05
MW
Source: Energy Sector Inquiry 2005/2006
(971)Figure 99 shows what the estimated aggregated level of upward (secondary and tertiary)
reserve capacity was purchased by TSOs in 12 Member States. The figure reflects the
amount of capacity in MW contracted by TSOs and reveals that the amount is subject to
significant changes. As the load that is being served in each control area changes over
time, it is certainly possible to have summer and winter patterns in the level of monthly
capacity requirements.
(972)The roughly estimated aggregated cost for this capacity is almost 120 million euro per
month. To be clear, this includes only the payments to (mostly) generators for capacity
that, if needed, can be called up by the TSO to supply upward power. In most Member
States these contract costs are fed into the tariffs paid by users of the TSO network who
will eventually factor it in as cost to the end consumers417
.
II.2.2. TSO calling of balancing energy
(973)Following Gate Closure, the TSO is in a position with its spinning reserves to ensure
secure supply by calling off secondary (automatically) and tertiary (manually) reserve
power and hence manages the system. While some reserve capacity may be contracted
long time in advance, as described above, there is typically also a mechanism by which
some participants can place shorter term (e.g. day ahead) bids to the TSO to provide
417
In addition there will be a charge on those network users causing the imbalance, which need to buy balancing energy
(see below).
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
301
incremental and decremental production. This market is usually based on energy-only
bidding. For this chapter this mechanism is defined as the balancing market, as it allows
participants to submit bids to the TSO, which assist them in balancing overall supply and
demand. In this limited form of trading the TSO is always the counterparty.
(974)The next and final step is that the services (quantities) used by the TSO have to be
metered exactly and TSOs pay for the purchased and used services to the generators in
line with the underlying contracts. This mechanism causes costs for the TSO, which are
normally covered by those market parties causing the deviations in the control area. For
that, these parties are charged with a so called “imbalance price”. This imbalance price
may be derived from the bids received in the balancing market.
(975)Depending on how a balancing market is arranged it can have a so-called dual imbalance
price or a single imbalance price. The first refers to an arrangement where a different
price is paid to positive and negative imbalance volumes in case where incremental as
well as decremental balancing power is necessary. A single imbalance pricing refers to an
arrangement where a single imbalance price is used for both positive and negative
imbalance volumes. Each of these arrangements may affect the level of liquidity in
wholesale markets however this relation will not be discussed in this chapter.
II.2.3. National balancing markets
(976)Balancing markets are generally national in scope (or smaller) because most generators
located in one Member State cannot supply reserve power (bids) across a border to an
adjacent Member States. For example, it is currently not possible for Dutch, French or
Polish generators to submit bids to a German TSO. There are however exceptions such as
in France, which allows bids from generators outside France. It is at this stage not
entirely clear why cross border balancing is not more widely used. Two factors seem to
explain this. First, it would require a new information communication platform between
TSOs to facilitate cross border balancing arrangements, as explained in the next
paragraph. Secondly, it may be that there is not sufficient interconnector capacity.
Thirdly, it would need new regulatory rules to be established at cross border level.
(977)Cross border balancing would technically be feasible if after Gate Closure all
interconnected markets would have arrangements which for a given generator made it
appear as if he was bidding to a single Balancing Market. Under such an arrangement, all
TSOs could see, and potentially use, the same bid. Once a bit was accepted in one market
it would need to be withdrawn from the other(s), since each bid can only be used once.
This would require a platform that closely co-ordinates between TSOs.418
418
Based on these principles the Nordic governments aim to develop a fully integrated Nordic balancing service. See:
http://www.norden.org/energi/el/sk/Electricity%20Market%20Group%202006.pdf
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
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II.2.4. Concentration
(978)An insufficient level of competition in the balancing market due to concentration may
result in high balancing prices. These difficulties are made worse where network users
are unable to adjust their positions close to real time. Network users that have no flexible
generation capacities at their disposal or which are not permitted to revise their
nominations, face a higher risk of being exposed to imbalancing charges. This adversely
impacts the level of competition in other segments of electricity markets (e.g. retail
market).
(979)Figures 100, as well as the figures for other Member States in Annex M, show that
balancing markets in most Member States are highly concentrated. The situation mirrors
the concentration levels in generation as described in the chapter B.b.II.1 on
concentration and market power in many wholesale markets, but concentration in
balancing is often higher. This is due to the fact that not all generators can supply
balancing power since only plants that meet a set of technical criteria qualify for the
supply of balancing power. The figures represent the volumes supplied (MWh) by
generators aggregating secondary and tertiary reserves that have been supplied during
January 2003 until May 2005. Not surprisingly a similar result appears in the market for
supply of balancing reserves (MW).
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303
Figures 100
Austria: balancing marketsvolumes suppling for increasing
production 2003 - 2005 May(include only APG)
2,1%
0,01% 4,9%
2,6%
90,4%
Undertaking A
Undertaking B
Undertaking C
Undertaking D
Undertaking E
Austria: balancing marketsvolumessuppling for decreasing
production 2003 - 2005 May(include only APG)
0,9%
0,26%2,4%
3,5%
92,9%
Undertaking A
Undertaking B
Undertaking C
Undertaking D
Undertaking E
Belgium: balancing marketsvolumessuppling for increasing
production 2003 - 2005 May
0,4%
99,6%
Undertaking A
Undertaking B
Belgium: balancing markets volumessuppling for decreasing
production 2003 - 2005 May
98%
2%
Undertaking A
Undertaking B
Czech Republic: balancing markets volumessuppling for
increasing production 2003 - 2005 May
10,1%
4,2%
0,0%1,7%
0,2%
1,1%1,1%
54,9%
15,9%
5,1%
2,9%
3,0%
Undertaking A
Undertaking B
Undertaking C
Undertaking D
Undertaking E
Undertaking F
Undertaking
G
Undertaking H
Undertaking I
Czech Republic: balancing marketsvolumessuppling for
decreasing production 2003 - 2005 May
11,8%
5,2%
3,6%
3,5%
2,7%
14,5%
54,4%
0,0%
1,4%
0,0%
2,7% 0,2%
Undertaking A
Undertaking B
Undertaking C
Undertaking D
Undertaking E
Undertaking F
Undertaking
G
Undertaking H
Undertaking I
Undertaking J
Source: Energy Sector Inquiry 2005/2006
Note: (1) The figures represent the volumes supplied (MWh) by generators aggregating secondary and
tertiary reserves that have been supplied during January 2003 until January 2005.
(2) Balancing mechanisms differ between Member States. In some Member States these mechanism
payments for services supplied to the TSOs are regulated and hence in such cases there is in fact no
market for reserves. Austria information represents only the largest TSO.
(980)The pie charts reveal that in particular in Member States such as Austria, Belgium,
France, Finland, Italy, Slovenia and Slovakia balancing markets are highly concentrated.
They also show that the level of concentration in the segment of secondary reserve is
often higher than in the tertiary reserve segment (see also Netherlands). This is likely to
be the result of the different technical qualification criteria. As has been explained
above, tertiary reserves are called up manually with some delay, while secondary
reserves are called up immediately. The technical prequalification criteria affect the
number of (potential) participants.
(981)Figure 101 shows the largest supplier of secondary reserves in a selection of Member
States. The figure reveals that in Member States such as Austria and Hungary the TSO
have no alternative for contracting secondary power. But also in Member States such as
Italy, Slovenia, Denmark, France and Germany TSOs face high concentration. Moreover,
since competition in these markets is limited and affiliated generators often provide a
significant share of balancing services the danger of cross-subsidisation exists. This is in
particular of concern in Member States where the payments for the supply of capacity are
fed in the network tariffs.
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304
Figure 101
Market share of the largest (incumbent) supplier secondary markets (2003 - 2005)
0
10
20
30
40
50
60
70
80
90
100
UK NL ES CZ IT SI DK FR DE BE AT HU
%
Source: Energy Sector Inquiry 2005/2006
Note: In Member States where more than one control area exists, an aggregation is provided of the largest
supplier in each control area. AT includes information only for the largest TSO. BE includes data
from 2004 and IT from April 2004.
(982)One would expect that in concentrated markets the payments for capacity reserves would
be higher due to market power. An assessment of this correlation has been attempted in
Figure 102. This Figure correlates the HHI, as measure of concentration, for supply of
secondary reserve capacity with the average of Euro/MW and year per TSO. Interpreting
this figure is not straightforward, because it does not take into account the fuel
technology (costs) used, the general price levels in the respective markets or the market
structure. However, the preliminary result in Figure 102 indicates that there is a
correlation between concentration on the supply side for balancing reserves and the
payments for secondary capacity reserves. At this stage further statistical assessment
could not be done.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
305
Figure 102
Average payments (Euro/MW) per control area for upward secondary reserves
versus
concentration in supply of secondary upward regulation capacity
0
2000
4000
6000
8000
10000
12000
0 2000 4000 6000 8000 10000 12000
HHI
Euro/MWpaymentsforsecondaryreserve
capacity
Source: Energy Sector Inquiry 2005/2006
Note: Information for non-UCTE Member States includes total reserves. Outliers require further
examination.
II.2.5. Benefits of lowering concentration
(983)Lower concentration levels on balancing markets would result in efficiency gains for at
least two reasons. First, lower concentration would reduce the scope for exercising
market power. Generators within national systems are able to exercise market power
either as a result of their location or their ability to provide flexibility.
(984)Secondly, by integrating balancing markets, low cost resources would be better utilised,
yielding a decrease in overall costs for balancing services. If there are separate markets,
low or medium cost resources in one Member State might remain unused, whilst
expensive resources in an adjacent Member State are used. Clearly, if two balancing
markets were linked (assuming sufficient transmission capacity between the two systems)
it would reduce the overall costs for maintaining the balance across the two systems. The
efficiency gains may be very high if the two Member States have generation systems that
differ in fuel mixes.
(985)Thirdly, as has been explained in the balancing chapter for gas, smaller balancing markets
(control areas) go along with smaller (customer) portfolios in these control areas. This
results in higher risks of being charged imbalance prices particularly for new supplier
with a low number of customers per balancing zone. However, the very high number of
balancing zones in gas seems less evident in electricity. This is because most balancing
markets are national in scope, though, for instance, Austria counts more than one control
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
306
area. Here, companies supplying customers in multiple areas would benefit from a
portfolio effect if integration of relevant control areas would materialise.
(986)The question is what measures could be taken to reduce concentration in balancing
markets without adversely impacting the design of the current systems and markets in
Member States? One important avenue, besides plant divestitures419
, would be to change
the rules in the current balancing market arrangement in order to harmonize them across
Member States in such way that it provides economic and technical opportunity for all
qualified generators to supply reserve power across borders. This could start at a regional
level.
II.2.6. Comparison of TSOs
(987)TSOs contract reserve capacities in advance and use them to balance their systems in real
time. While the existence and availability of these capacities is crucial for the functioning
of the respective system, keeping unreasonably large – i.e. going beyond security of
supply needs - reserve capacities reduces the size of the commercially available
generation park and unnecessarily increases balancing costs.
(988)Further, since the cost of the reserve capacities are often recovered through the grid
charges, network users will be charged for them. In cases where ownership unbundling
has not been implemented there is a danger of cross subsidising because TSO’s affiliated
generators often have significant shares in providing balancing power. These TSOs may
therefore lack incentives to purchase only the amount of reserve capacities that is strictly
necessary.
419
Divesture cannot be replaced by the intermediate measure of Virtual Power Plant auctions since because the VPP
buyer normally is only granted a day ahead scheduling right. Hence intra-day flexibility, needed for supply of
balancing reserves, remain with the seller.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
307
Figure 103
Average of monthly total reserves purchased as a percentage of peak load in 2004
selection of MS
0%
2%
4%
6%
8%
10%
12%
14%
16%
FI NL IT UK CZ BE AT DE HU DK East GR
Source: Energy Sector Inquiry 2005/2006
Note: Information for Germany includes an aggregate for all TSOs in that Member
State As for the TSOs operating within the UCTE system the report
concentrates on secondary and tertiary reserves while in case of the Nordel and
UK systems figures represent overall reserve capacities without qualification.
(989)Figure 103 represents overall reserve capacities (MW) that are purchased and are at the
disposal of TSOs across Member States as a percentage of the peak load. This ratio
corrects for the different sizes of control areas and results in better comparability. In other
words, a larger load requires more reserve power, since it should anticipate larger plant
failures. Though, there may be justifiable factors420
that explain the variance this figure it
is striking that Greece and East Denmark purchase almost six times more reserves than
Finland.
420
Such as the fact that reserve capacities have to cope with an unexpected outage of a generating unit. The capacity of
such a unit might be relatively large compared to the overall size of the balancing area. Some differences can also be
explained by varying market designs, i.e. the way how TSOs secure the reserve capacity they need.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
308
Figure 104
Average yearly secondary and tertiary reserves as a percentage peak load in 2004
selection of MS
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
AT NL IT CZ DE BE HU GR
peak load vs. secondary reserves (up) in % peak load vs. tertiary reserves (up) in %
Source: Energy Sector Inquiry 2005/2006
Note: Peak load for AT based on an estimation. DE includes aggregation of all TSO. FI and UK are
excluded from this figure as they are non-UCTE Member States.
(990)Figure 104 plots the average secondary and tertiary reserves capacities booked by the
respective TSOs in 2004. This figure is a break down of the information shown in Figure
103. It reveals that TSOs differ substantially in their way to buy reserves. In Austria the
TSO books almost 3.5 more secondary than tertiary reserves, whilst in Belgium the ratio
is only 0.2. In general it would seem favourable to turn to the tertiary reserves where
concentration levels are in general lower and TSOs can thus choose between more
suppliers (which should normally also have an impact on prices). However, regulatory
and security reasons may limit the freedom of choice for TSOs.
II.3. Harmonisation
(991)Some Member States have been successful in integrating their forward and spot markets
on a regional level (i.e. NordPool). Others are gradually taking action in a similar
direction (Belgium, France and the Netherlands). Far fewer efforts have been made to
integrate balancing markets. This is partially justifiable since volumes traded on forward
and day-ahead markets are much higher than those on balancing markets. As explained
above balancing markets serve mainly for corrections between supply and demand,
which involves smaller volumes. Linking balancing markets is also likely to bring about
more logistical difficulties than linking day ahead or forward markets, as they are nearer
to gate closure.
(992)However, it is clear that a harmonisation of the design of balancing markets could
improve efficiency as it would pave the way for cross border balancing services.421
At
present the design and hence the rules in Member States for their balancing differ
substantially. For instance, payments for balancing power are in some Member States
421
Also the integration of so-called intraday markets would significantly improve this situation, though these markets
fall outside the scope of this chapter.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
309
based on marginal prices. That means that those who make bids for balancing power will
all be rewarded with the price that is set by the marginal bid. Hence, in principle all have
an incentive to bid in at marginal cost. This is the case in for example the Netherlands,
Sweden, Finland, Norway, Spain and Greece. However, in the other Member States it is
the bid price that is paid by the TSO and hence participants have less incentive to bid at
marginal cost.
(993)Further, in some Member States prices for these services are not based on a market
mechanism but defined in a kind of regulatory framework based on obligations on
generators or bilateral contracts between TSOs and generators. Table 52 provides an
overview of these differences in systems. Clearly, each system has a different impact on
incentives for companies to provide balancing power.
Table 52
Market or
fixed prices
Gate closure Average TSO
sell price
Average TSO
buy price
Spread
Austria market day ahead 51 24 27
Belgium hybrid "ex-post" 56 12 44
Denmark market 1
/2 hour 36 27 9
Finland market 1
/2 hour 32 27 5
France market 6 during day 50 45 5
Germany market 3 during day 70 2 68
Greece fixed day ahead 44 44 0
Ireland hybrid day ahead 69 60 9
Italy market day ahead 102 23 79
Luxembourg fixed - - Netherlands
market 1 hour 69 28 41
Portugal fixed 2 during day 58 23 35
Spain market 2
1
/4-3
1
/4 hrs - - 0
Sweden market 1 hour 32 28 4
UK market 1
/2 hour 55 39 16
Norway market 1 hour 29 29 0
Estonia n.k. day ahead - - Latvia
n.k. 2 hours - - Lithuania
n.k. 2 hours - - Poland
market day ahead 37 24 13
Czech R market 1
1
/2 hour 51 0 51
Slovakia n.k. day ahead - - Hungary
market day ahead 40 0 40
Slovenia market day ahead - - Source:
Regulators’ data, DG TREN analysis of TSO websites.
Note: Gate Closure is the point in time when market participants notify the System Operator of their
intended final physical position. Thereafter no further contract notification can be made. “6 during
day” means that at six moments during the day adjustements can be made.
(994)As noted previously, a key difficulty for small market participants arises where there is
the risk of a large spread between the buying price from the TSO and the selling price.
This occurs in a number of Member States and is likely to be detrimental to the
development of competition. A high spread (see Table 52) may be indicative of an
insufficient level of competition in the balancing market, which may be dominated by
only one or two main generators. Such difficulties are made worse where network users
are unable to adjust their positions close to real time. Greater integration of balancing
markets would significantly improve this situation.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
310
(995)Further, the gate closure differs between Member States (see Table 52) and in addition, as
is already explained in the chapter on Market Integration (Table 31), the time frames in
which imbalances are settled in each control area differ in Member States. Harmonizing
balancing market rules would not only be a first step prior to integration, it would also
simplify trade and transparency for market participants that are active in more than one
Member State.
(996)There are already some initiatives to integrate electricity markets under way. However, it
seems questionable if these initiatives will soon yield positive results as it remains
challenging for national regulators and TSOs to seek European solutions in the context of
national legislations.
Conclusions
Balancing markets are highly concentrated. This gives scope for exercising of market power. It
can result into an entry barrier for new suppliers as they face a high risk of being exposed to
excessive imbalance prices and/or excessive network charges. This may deter entry and hence
reduce the scope for competition on the supply market. Concentration on balancing markets
could be reduced if the geographical size of control areas was enlarged.
Balancing market regimes have incompatible market designs. Harmonization of balancing
market regimes would help to reduce concentration in these markets, simplify EU trade and
hence reduce barriers to trade. Further integration remains challenging for national regulators
and TSOs when they seek European solutions in the context of national legislations (cf.
however the ERGEG Guidelines of Good Practice on Electricity Balancing Markets
Integration).
In some Member States the structural relation between TSOs and their affiliated generation
provides an incentive for the TSO to buy the reserve capacity from their affiliated generation.
Results indicate that the amount of capacity reserves bought differ substantially between TSOs.
Though it is not proven that lack of ownership unbundling is causing this, it is clear that
ownership unbundling would better guarantee that TSOs have no incentive to buy too much
capacity. In addition ownership unbundled TSOs would have (stronger) incentive to cooperate
with the aim to facilitate competition and integrate electricity (balancing) markets in the EU.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
311
III. Electricity Study – Analysis of hourly variations of concentration
(997)In the first phase of the Sector Inquiry the level of concentration in the electricity markets
was analysed for all Member States concerned by the inquiry (see chapter B.b.II.1). The
main conclusion was that many markets are characterised by a high degree of
concentration giving market operators scope to exercise market power. In the second
phase of the inquiry, a more refined analysis of market power was carried out for six
Member States. This chapter sets out the results of this analysis.
(998)In this respect it is important to note that electricity spot markets have been mainly
organised on an hourly basis422
. This stems from the varying nature of demand and
creates in particular variations of the quantity and price of each relevant market every
hour. Furthermore, capacity available to generate electricity also varies on an hourly
basis due to technical constraints, maintenance, etc. In order to fully assess competition
in such markets it is thus necessary to make an assessment on an hourly basis.
(999) Taking into account the very large amount of data to be analysed, a study423
of the hourly
variations was commissioned to external consultants. The study relates to the electricity
markets of Belgium, France, Germany, the Netherlands, Spain and the UK in the period
between 1 January 2003 and 31 December 2005. The study measured concentration
systematically on an hourly basis and the effects of a number of market characteristics
(interconnectors, long-term contracts and reserves) on concentration.
a) Traditional concentration indices
(1000) As indicated above, the situation of an electricity market varies from hour to hour. This is
well known for the load (demand) to be served, but this is also true in particular for the
capacity of generation that is available to serve the load. The effectively available
capacity (hereafter "available capacity") of each generation unit in the market during
each hour of the period depends on all the constraints that reduce availability of
generation capacity (periods of maintenance, forced outages, seasonal de-ratings, etc.424
).
The following table shows that such available capacity varies substantially between hours
in a given market:
422
In fact nominations on transmissions networks are done on an even smaller (15mn) basis, but markets have been
organised on a hourly basis, except the UK market which is settled on a half-hourly basis.
423
The study was carried out under the steering of DG Competition and at the premises of DG Competition by a
consortium led by London Economics and including Global Energy Decisions and a number of Professors acting as
consultants for the project. The study is referred to in this document as the LE-GED study.
424
These constraints were reported by the generators to the Commission for each unit for the whole period. The
calculation of effectively available capacity is first based on the effective maximum capacity at which the units can
be run in a sustainable manner. This capacity can vary between seasons, in particular between summer and winter, in
which case this was taken into account. Then available capacity was reduced or brought to nil when there was
maintenance, partial or full outages. Available capacity could also be reduced to other constraints such as restrictions
on transmission capacity from the plant to the rest of the grid.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
312
Table 53
Hourly variation of total available capacity in 2003-2005 (in MW)
Belgium France Germany Netherlands Spain UK
Average 12429 76801 74313 14341 38808 60562
Maximum 14738 92675 85228 16463 43843 71832
Minimum 9645 57011 59893 10808 32291 48193
Standard
deviation
786 7100 5152 828 1874 4294
Standard
deviation
/average
6.3% 9.2% 6.9% 5.8% 4.8% 7.1%
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
(1001) All the analysis of these markets presented hereafter has been thus been done by taking
into account the hourly available capacity of each generating unit.
i) CR2 and HHI
(1002) Concentration has been first measured on an hourly basis by looking at the sum of the
shares of the two largest firms on the market (CR2) in terms of available capacity and in
terms of production (realised generation) and by calculating the HHI index of the
market425
in terms of available capacity and effective generation. These results constitute
a detailed refinement of calculations made in chapter B.b.II.1.3 of this report.
(1003) The results show that concentration levels can vary depending on the hour, although to a
much lesser degree than total available capacity and not to a degree that would render
concentrated markets non-concentrated for certain hours. The table below shows the
value of CR2 for effectively available capacity.
425
The Herfindahl-Hirschman Index (HHI) for market shares is equal to the sum of the squares of the market shares of
the different operators. It is very low in an atomised market and equal to 10000 for monopoly. The index was
calculated on the basis of operators with an installed capacity above 250 MW in the respective markets.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
313
Table 54
Hourly variation of concentration of production (available generation)
in 2003-2005
Belgium France Germany Netherlands Spain UK
Minimum CR2 87.2% 90.9% 49.1% 50.5% 60.8% 27.9%
Maximum CR2 97.5% 94.8% 60.1% 67.4% 78.7% 40.0%
Average CR2 90.7% 92.6% 54.1% 57.7% 71.4% 32.6%
Standard
deviation
1% 1% 1.7% 3% 3% 2.2%
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
Note: In the case of Belgium and France, the figures concern CR1 (i.e. the market share of the main
operator) as the first two operators constitute virtually all of the available capacity in the market.
(1004) The study also analysed the HHI based on available capacity and actual generation. The
table hereafter presents the values of HHI in terms of realised generation. It tends to show
that the more concentrated the market is, the more HHI varies. That being said, variations
are not of such a degree that they would render concentrated markets non-concentrated
for certain hours. Rather, the variation shows that in the less concentrated markets,
concentration can reach much higher levels than average for certain hours (e.g. HHI can
almost double to reach almost 1800 in the UK).
Table 55
Hourly variation of concentration of production (actual generation) in 2003-2005
Belgium France Germany Netherlands Spain UK
Minimum HHI 7578 8298 1795 2308 2135 863
Maximum HHI 9944 9764 2665 3397 3991 1775
Average HHI 8843 9072 2143 1861 2837 1129
Standard
deviation
517 264 132 149 257 125
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
ii) Impact of long-term contracts426
and reserves
(1005) CR2 and HHI indices based on available capacity have been adjusted further by taking
into account long-term contracts and reserves. As regards long-term contracts, if an
operator has secured generation output on a long-term basis from another operator (e.g. in
the form of drawing rights), then market outcomes are influenced by the first operator
(and not the owner of the generation assets who is bound to deliver the output). The
426
For the purpose of this analysis, a long-term contract is a contract of duration longer than three years.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
314
capacity has therefore to be attributed to the first operator rather than the second.
Furthermore, if an operator is committed to supplying certain customers under long-term
contracts, it has less incentive/scope to use the corresponding capacity to affect the
market outcome: in such a case the corresponding capacity was taken out of the total
capacity of that operator for the purpose of the calculation. As regards reserves, all
capacity earmarked for reserves has also been subtracted from the available capacity of
that operator as such capacity cannot serve the wholesale market.
(1006) The following table shows the combined impact of long-term contracts and reserves on
concentration, i.e. the increase of the CR2 index due to these "constraints" on the
availability of generation capacity. As can be seen from the table, the impact is small
except for Germany (where significant amounts of generation are contracted by one of
the two main generators from other operators) and Belgium.
Table 56
Variation of concentration in available capacity due to reserves
and long-term contracts
Belgium France Germany Netherlands Spain UK
Increase of
average CR2
-4.3% +2.6% +3.1% -2.2% +0.4% -1.4%
Increase of
maximum CR2
-4% +2.7% +4.5% -1.2% +0.1% -1.8%
Increase of
minimum CR2
-6.2% +2.1% +2.4% -4.8% +0.3% -1.5%
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
Note: In the case of Belgium and France, the figures concern CR1 (i.e. the market share of the main
operator) as the first two operators constitute virtually all of the available capacity in the market.
iii) Impact of interconnectors
(1007) Finally, the impact of interconnectors on CR2 and HHI measurements based on available
capacity and actual generation was assessed. For that purpose, in addition to the hourly
adjustments for capacity mentioned in paragraph (1002), interconnector capacity has also
been adjusted on an hourly basis to what was effectively available for cross-border sales
of electricity in each and every hour. Then capacity was allocated under different
scenarios. The following table shows the impact of interconnectors on HHI in terms of
capacity. The scenario for the allocation of interconnection capacity reported in the table
is based on the assumption that all capacity is exclusively used by competitors of the
undertaking under study.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
315
Table 57
Decrease of concentration due to interconnectors
Belgium France Germany Netherlands Spain UK
Average HHI
without
interconnectors
8307 8592 1914 2332 2790 1068
Average HHI
with
interconnectors
5332 6505 1160 1151 1945 1004
Maximum HHI
without
interconnectors
9508 8987 2158 2647 3259 1246
Maximum HHI
with
interconnectors
6030 7437 1351 1283 2360 1118
Average NTC as
a proportion of
total available
capacity
25% 14% 16% 17% 6% 2%
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
(1008) These results overestimate the positive impact of interconnectors on competition, as in
practice the interconnectors are also used by operators already active on the market.
Further, these results are based on the assumption that all the available transmission
capacity would be allocated to competitors and used which is not what happens in
practice as was seen in section B.b.II.3. That being said, these results already indicate
that, in most markets, interconnectors do not reduce concentration to a level that would
allay any competition concern.
b) Electricity specific concentration indexes: pivotality and residual supply
i) The pivotal Supplier Index (PSI)
(1009) The analysis of traditional concentration indices needs to be complemented by some
sector-specific indices on market structure in the reports made by competition or
regulatory authorities427
. Given that supply and demand have to meet at every hour and
that buyers cannot postpone purchases or store the product, it is of particular interest to
assess if there is any operator which is indispensable to meet demand428
at a given
427
See for instance the approach taken by the Italian Energy Authority (Autorità per l’Energia Elettrica e il Gas,
“AEEG”) and the Italian Competition Authority (Autorità Garante della Concorrenza nel Mercato, “AGCM”) in a
Joint Report published on 9 February 2005 (the “Joint Report”). The Joint Report “Indagine consoscitiva sullo stato
della liberalizzazione del settore dell’energia elettrica” is available on the website of AEEG
http://www.autorita.energia.it/elettricita/index.htm
as well as on the website of AGCM, http://www.agcm.it/index.htm.
See also the market monitoring by the US FERC.
428
The load used for the calculations reported in this chapter is the sum of generation of all units that were reported to
the Commission: this load is not equal to the load which was recorded on the networks of the TSOs as it includes
units which are connected at DSO level.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
316
moment in time. The fact that an operator is indispensable does not mean that it can
automatically profit from the situation429
, but it gives an indication of its possible market
power.
(1010) The degree of indispensability of an operator can be first measured by the Pivotal
Supplier Index (PSI)430
, which provides the percentage of hours at which a given operator
is indispensable in the market, i.e. where the sum of the available generation capacities of
all other domestic producers (possibly including imports) is not sufficient to meet
demand of the market in the given hour. A large percentage of hours indicates that the
operator in question is indispensable (pivotal) for substantial periods of time431
, giving it
scope to exercise market power for sustained periods of time. The table shows the PSI
index for the three largest operators in each of the markets over the period 2003-2005.
This calculation of PSI indices takes into account the amount of capacity earmarked for
reserves and the capacities which are tied into long-term contracts432
. The following table
shows the same PSI index, taking into account interconnectors in the scenario most
favourable to competition433
.
429
Theoretically an operator is able to dictate prices in an hour when it is indispensable to meet demand, if it can foresee
it. This is possible because operators know rather well what capacity exists in the market and the load on the network
is usually published. For large operators in a tight market, a position of indispensability will be reached once demand
exceeds a certain level, which is usually occurring at foreseeable moments given that electricity demand mainly
varies in cycles between peak (which is usually the period 8:00-20:00 of a working day) and off-peak (other
moments). Because of this cyclical repetitive nature of the market, an indispensable operator can learn to forecast
when it becomes indispensable and adapt its behaviour accordingly. Theoretically the operator could give an infinite
price but this would attract corrective measures that could be detrimental to the operator, especially if the “infinite”
prices occur regularly. Thus, prices could probably be raised only to a finite value. Then, it will be profitable for an
indispensable operator to increase prices in the hours when it is indispensable, only to the extent that the foregone
profit of not running the whole capacity of that operator that would normally serve demand is compensated by the
additional profit gained with the higher price obtained on a smaller part of its portfolio. In other words, an operator
whose generation portfolio is to a very large extent indispensable to meet demand has a higher incentive to exercise
market power.
430
PSI is equal to one if the sum of the capacity of all other operators is lower than demand in that hour (meaning that
the operator investigated is indispensable to meet demand). PSI is equal to zero if the sum of the capacity of all other
operators is higher than demand in that hour (meaning that the operator investigated is not indispensable to meet
demand). The results reported here are the percentages of hours when PSI is equal to one.
431
This naturally corresponds to periods of higher demand, i.e. peak demand when occurs only for a part of the time.
432
As before, if capacity is supplied through a long-term contract by a given operator to another this capacity is added to
the capacity of the latter operator and subtracted from the capacity of the former. Further, if an operator is committed
to serve through long-term contracts certain customers, it cannot affect the outcome of the market on the short-term
with the capacity dedicated to serve these customers. Thus the capacity allocated to those long-term contracts is
subtracted from the total capacity of that operator and from total demand as that part of the demand is served. This
second situation does not affect the PSI but the RSI index presented thereafter.
433
Several scenarios have been studied as in section III.a.iii. The scenario most favourable to competition determines
that all interconnector capacity is used by competitors established on neighbouring markets on the basis of their
market shares there.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
317
Table 58
Degree of indispensability of the main operators disregarding interconnectors:
percentage of hours when the main operators are indispensable
PSI Belgium France Germany Netherlands Spain UK
Undertaking 1 100% 100% 11.5% 31.3% 25.7% 0%
Undertaking 2 0% 0% 49.8% 14.5% 19.8% 0%
Undertaking 3 0% 0% 0% 5% 0% 0%
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
Table 59
Degree of indispensability of the main operators taking into account interconnectors:
percentage of hours when the main operators are indispensable
PSI Belgium France Germany Netherlands Spain UK
Undertaking 1 97.2% 100% 0% 0% 8.2% 0%
Undertaking 2 0% 0% 0% 0.7% 5% 0%
Undertaking 3 0% 0% 0% 0% 0% 0%
Average NTC as
a proportion of
total available
capacity
25% 14% 16% 17% 6% 2%
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
(1011) The results show that interconnectors barely affect the indispensability of the main
operators in France and Belgium, despite the rather high level of interconnectivity of
these Member States. On the other hand, with a much lower level of interconnectivity,
interconnectors in Spain reduce the market power of the two main undertakings, albeit
not completely. And in the UK, which has by far the lowest level of interconnectivity, the
existing low level of concentration means that interconnectors are needed only to a very
small degree to mitigate potential market power. In other words, the right level of
interconnectivity needed to mitigate possible market power depends very much on the
level of concentration in the domestic generation market. This means that at certain levels
(like in Belgium and France) there is little perspective that interconnectors can mitigate
such market power. This means also that even in less concentrated markets market power
can be all the more increased by national mergers given the low levels of
interconnectivity.
(1012) Another interesting result concerns cross-border shareholdings. In the Netherlands,
interconnectors affect the indispensability of only two of the three undertakings since the
third one has substantial capacity in a neighbouring market and thus does not lose so
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
318
much potential market power through the interconnectors434
. It is thus important to take
into account cross-border shareholdings in order to assess the right level of
interconnectivity needed to mitigate possible market power. Also, it is very important to
assess the impact of cross-border mergers on the possible market power of operators
involved given the risk that such links increase their market power on both sides of the
border.
ii) The Residual Supply Index (RSI)
(1013) The study also computed the Residual Supply Index (RSI), which has been developed by
the California Independent System Operator to monitor competition and levels of market
power. RSI has shown a good correlation with Lerner indices in the Californian market
during 2000. Contrary to the PSI, which provides a binary measure of indispensability,
the RSI for a given operator in a given hour is a ratio between the sum of the available
capacity of all other operators and total demand in that hour435
. This allows a continuous
measurement of indispensability and market power. For instance, an RSI value of 0.5
indicates that the operator is indispensable to cover 50% of demand, which is a higher
degree of market power than a situation where an operator is indispensable to meet only
5% of demand (RSI=0.95). In both cases, PSI would only indicate that the operator is
indispensable. RSI also allows assessing potential market power of operators which are
not strictly indispensable but close to being so and have thus potentially some market
power.
(1014) RSI was computed for the main operators in each market. For instance, the duration curve
of the RSI of the main operator in Belgium is shown below. It demonstrates that, absent
interconnectors, the main operator was indispensable to meet 40% of total demand for all
hours in 2003 (RSI is between 0.4 and 0.6 except for very few hours on both extremes)
but started to become necessary for less of demand (RSI going up to 0.8) in 2004 and
2005. The fact that the RSI is going up over the years reflects the increase of
interconnection capacity and generation capacity of competitors in the market and its
impact on the indispensability of the incumbent operator.
434
This is mitigated partly by the fact that the rules of allocation of interconnector capacity in the Netherlands impose
that no operator can obtain more than 400MW of interconnector capacity in a given hour. However, on the southern
border of Belgium there are de facto very few operators which can export to the Netherlands.
435
When RSI is above one, then the operator is not indispensable to meet demand and PSI is equal to zero. When RSI is
below one, then the operator is indispensable to meet demand and PSI is equal to one.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
319
Figure 105
RSI Duration Curve: 0513-S-BE
0
0,2
0,4
0,6
0,8
1
1,2
0 1.000 2.000 3.000 4.000 5.000 6.000 7.000 8.000
Hours
RSIValue
2003 2004 2005 Threshold
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
(1015) As described previously, the potential market power stemming from available capacity
can be affected by several factors: reserves, long-term contracts, and interconnectors.
Calculations have thus been performed to take into account these factors separately to
assess what are the respective impacts of these factors.
(1016) First, a calculation of RSI taking into account only reserves has been made: in such a case
the capacity available to an operator is diminished by its contribution to reserves. This
makes it possible to estimate the impact of reserve requirements on the market power of
an individual operator. The table hereafter shows the variation of the percentage of hours
when the RSI of an operator was below 110% with and without reserve commitments.
Operators are presented in the decreasing order of their RSI values without reserves.
Overall variations are not significant. In the most concentrated markets (Belgium and
France), reserves do not alter market power as there is already a single operator whose
RSI is far below 110% all the time; and in Spain reserves even have no impact on market
power since the main operators provide reserves roughly in proportion of their available
capacity. However, there are exceptions. In the Netherlands and the UK, undertaking 3
provides little or no reserves (while others do) and thus increases its market power
because of reserves. In the same markets, undertakings 1 and 2 do provide reserves but
not to the same extent, so their market power is affected in the opposite direction.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
320
Table 60
How reserves affect the market power of an operator:
variation of the RSI due to reserves
(variation in percentage points)
Belgium France Germany Netherlands Spain UK
Undertaking 1 = = +11.0% -2.8% = -0.9%
Undertaking 2 -3.3% +0.1% -21.5% +2.8% = +0.3%
Undertaking 3 = +0.4% +0.5% +0.3% = +3.2%
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
Note: n.s. = non significant. It concerns situations when the percentage is equal to zero without reserves
and the result with reserves is also equal to zero.
(1017) Secondly, a calculation of RSI taking into account only long-term contracts has been
made: in such a case the available capacity of each operator is diminished by the amount
(MW) of its obligations to supply through long-term contracts and increased by its
wholesale purchases through long-term contracts (essentially drawing rights in plants of
other operators). This makes it possible to estimate the impact of long-term contracts on
the potential market power of an individual operator. The table hereafter shows the
variation of the percentage of hours when the RSI of an operator was below 110% with
and without long-term contracts. Operators are presented in the decreasing order of their
RSI values without contracts. Again the impact is not very significant for most operators
in these markets. But again there are a few exceptions. The table hereafter shows that
long-term contracts (such as drawing rights in the plants of another operator) increase
substantially the potential market power of undertaking 1 in Germany and decrease the
potential market power of undertaking 3 in the Netherlands (because it is committed to
supply a large part of its electricity on a long-term basis).
Table 61
How long-term contracts affect the market power of an operator:
variation of the RSI due to long-term contracts
(variation in percentage points)
Belgium France Germany Netherlands Spain UK
Undertaking 1 = = +31.2% +0.7% +2.1% +0.2%
Undertaking 2 +1.8% = -35.3% +1% +2.6% +0.5%
Undertaking 3 = n.s. +3.1% +0.8% +0.1% =
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
Note: n.s. = non significant. It concerns situations when the percentage is equal to zero without reserves
and the result with reserves is also equal to zero.
(1018) The third and last factor considered as a sensitivity analysis of RSI is interconnectors. The
table below shows the variation of the percentage of hours when the RSI of an operator
was below 110% with and without interconnectors. For the purpose of the calculation
with interconnectors, all interconnector capacity is allocated to operators established on
neighbouring markets on the basis of their market shares there. The results show that
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
321
interconnectors have much larger impacts than reserves and long-term contracts. That
being said, in markets with a single operator, interconnectors have no impact.
Table 62
How interconnectors affect the market power of an operator:
variation of the RSI due to interconnectors
(variation in percentage points)
RSI Belgium France Germany Netherlands Spain UK
Undertaking 1 = = -47.7% -43.8% -23.9% -0.8%
Undertaking 2 -5% -0.5% -76.9% -21.6% -21.1% -0.6%
Undertaking 3 n.s. n.s. -4.6% -22.7% -0.6% -0.6%
Source: Energy Sector Inquiry 2005/2006, study by LE-GED.
Note: n.s. = non significant. It concerns situations when the percentage is close to zero or equal to zero
without interconnectors and the result with interconnectors is equal to zero.
c) The merit curve
(1019) As explained in chapter B.b.I.3.2.4, economic theory suggests that the electricity price at
the wholesale level is very much determined by the merit curve of the overall portfolio of
plants in that market. The spot market price at the spot market is determined in general by
the marginal costs of the last plant called to meet demand. By using the cost of fuel and
other variable costs of each generation units, it is possible to construct the merit curve in
each market for every hour. The following graph shows the merit curve in the
Netherlands at the beginning of each year of the period (2003, 2004 and 2005) and at the
end of 2005 (first without factoring in CO2 and second with the value of CO2 emissions
added). The merit curves of all markets are shown in Annex N.
ENERGY SECTOR INQUIRY – SECOND PHASE (Electricity)
322
Figure 106
Merit Order Curve (incl. Carbon) - Netherlands
0
20
40
60
80
100
120
140
0 2.000 4.000 6.000 8.000 10.000 12.000 14.000 16.000
Available Installed Capacity (MW)
ReturnedCostofUnits(€/MWh)
Jan-03 Jan-04 Jan-05 Dec-05 Dec-05 (incl. Carbon)
Source: Energy Sector Inquiry 2005/2006.
(1020) This graph shows the significant impact of price increases of fuels on the curve at the end
of the period. This impact is the largest factor of modification of the curve, by shifting it
upwards. In 2005, the EU Emission Trading Scheme (ETS) is also contributing to a
significant shift of the curve upwards, although not to the same degree as created by the
increase of fuel prices. In certain markets, the evolution of the curve also shows the
evolution of the overall portfolio of plants (when some plants are added or retired).
ENERGY SECTOR INQUIRY – CONCLUSIONS
323
D. CONCLUSIONS
(1021) In order to address the malfunctioning of the market identified in the Sector Inquiry and
to significantly improve the scope of competition, it is essential to apply both competition
and regulatory-based remedies. Competition law enforcement can make a significant
contribution, but cannot by itself open markets and resolve all the shortcomings identified
by the Sector Inquiry: a number of regulatory measures are, therefore, also needed.
Competition law enforcement
(1022) Full and combined use of the Commission’s powers under antitrust rules (Articles
81, 82 and 86 EC), merger (Regulation 139/2004)436
and State aid control (Articles
87 and 88 EC) is needed to maximise the impact of the Commission’s enforcement
action. The Commission is forcefully pursuing infringements of Community competition
law (antitrust) in the sector wherever the Community interest so requires, in close
cooperation with National Competition Authorities.
- Market Concentration
(1023) Market concentration has been identified as a major concern for the success of the
liberalisation process. The market power of pre-liberalisation monopolies has not yet
been eroded. This makes the Community's action under the merger regulation essential so
as to ensure that the competitive structure in relevant markets (which currently are at
most national in scope) does not further deteriorate. In recent merger cases remedies such
as divestitures, contract and/or gas release have been applied. In addition, the impact of
long-term upstream contracts on downstream concentration has emerged as a major
theme.
(1024) Energy release programmes (i.e. electricity Virtual Power Plant auctions and gas release
programmes) are a means to develop market liquidity and increase entry opportunities.
They constitute suitable remedies to competition concerns not only in the merger area but
also under antitrust rules. In order to be fully effective they must be well-designed and
large scale. Substantial experience has been gathered with such programmes by
competition and regulatory authorities at national level (e.g. in Spain, France, Austria,
Germany) and by the European Commission (in merger cases) allowing the authorities to
avoid pitfalls and ensure their effectiveness. For gas, such release programmes have the
additional advantage that they are likely to increase hub liquidity which supports the
introduction of price signals not biased by the gas-oil-price link.
(1025) In certain circumstances applicable antitrust law also permits the application of farther
reaching structural measures as a remedy to infringements of competition rules. This is
the case where behavioural remedies would be less effective to bring the infringement to
an end, where there is a substantial risk of a lasting or repeated infringement that derives
436
Council Regulation (EC) No 139/2004 of 20 January 2005.
ENERGY SECTOR INQUIRY – CONCLUSIONS
324
from the very structure of the undertaking, or where behavioural remedies would be more
burdensome.437
- Vertical foreclosure
(1026) Wherever competition infringements are facilitated by vertical integration between
supply and generation and infrastructure businesses and insufficient unbundling,
the full force of the Commission’s powers to prevent future abuse needs to be
applied.
(1027) The Sector Inquiry has also confirmed the vertical tying of markets by long-term
downstream contracts as a priority for review of case situations under competition law
and for providing guidance where required. When such contracts, concluded by dominant
firms, foreclose the market, Article 81 or 82 EC may be infringed unless there are
countervailing efficiencies benefiting consumers.438
Similarly, power purchase
agreements in the electricity sector can have foreclosure effects.
(1028) Furthermore, the concentration of gas import contracts in the hand of a few incumbents is
one of the main reasons why competition at the subsequent level of trade does not take
off. Whilst this does not as such put into question existing and future upstream contracts,
it requires attention with respect to their effects for the downstream markets.
- Market integration
(1029) Foreclosure can also arise at other levels of the value chain, most prominently as
regards access to infrastructure (transmission and distribution networks and/or
storage facilities), particularly in cases where cross-border access is concerned,
thereby preventing market integration. Such access can be blocked through long-term
transmission contracts and through the associated risk of capacity hoarding. Action in this
field should include an analysis of the competition effects of pre-liberalisation long-term
contracts and the compatibility of such contracts with competition rules.
(1030) Additionally, lack of investment and delayed investments by transmission companies
with vertically integrated supply companies are other serious sources of concern. It is
recalled that one National Competition Authority has found that a vertically integrated
network operator deliberately stopped an investment project in order to benefit its supply
branch by depriving competitors of access to more capacity.439
(1031) Market partitioning remains one of the most serious obstacles to market integration.
The fight against collusion between incumbents remains a priority of antitrust
enforcement action, reflecting the overall priority of the Commission to fight attempts by
undertakings to coordinate rather than to compete.
437
See Article 7(1) and recital 12 of regulation 1/2003.
438
In the analysis of long-term contracts, sunk investments, if any have been made by the parties, are taken into account
- see Commission Guidelines on the application of Article 81(3) of the Treaty (OJ C 101 of 27.4.2004, page 97,
paragraph 44).
439
The Italian Competition Authority has recently taken action against the delaying tactics of an incumbent operator to
expand an important import pipeline.
ENERGY SECTOR INQUIRY – CONCLUSIONS
325
Structural issues and pro-competitive regulatory environment
(1032) The findings of the Sector Inquiry will enable the Commission to focus its enforcement
action on the most serious concerns identified in the report. They also make it easier for
the Commission to identify efficient remedies that can effectively resolve the competition
problems identified in individual cases.
(1033) However, key issues relating to market structure and the regulatory environment
will have to be addressed in parallel, in order to remedy the malfunctioning of the
markets that has been demonstrated by the inquiry.
The Sector Inquiry has identified the following main fundamental deficiencies in the
competitive structure of current electricity and gas markets:
• Structural conflicts of interest: a systemic conflict of interest caused by
insufficient unbundling of networks from the competitive parts of the sector;
• Gaps in the regulatory environment: a persistent regulatory gap particularly
for cross border issues. The regulatory systems in place have loose ends, which
do not meet;
• A chronic lack of liquidity, both in electricity and gas wholesale markets: the
lifeblood for our markets is lacking and the market power of pre-liberalisation
monopolies persists;
• A general lack of transparency in market operations in the sector.
Options for regulatory action at EC level are discussed by the Commission in its
Communication on “Prospects for the internal gas and electricity market”. The
findings of the Sector Inquiry and the resulting deficiencies identified below support
and confirm the analysis brought forward by the Commission in that Communication.
- Unbundling
(1034) The Sector Inquiry confirms the finding that it is essential to resolve the systemic
conflict of interest inherent in the vertical integration of supply and network
activities, which has resulted in a lack of investment in infrastructure and in
discrimination. It is crucial to ensure that network owners and/or operators do not have
incentives that are distorted by supply interests of affiliates. This is particularly important
at a time when Europe needs very large investments to ensure security of supply and to
create integrated and competitive markets.
(1035) To achieve this, it will be necessary to decisively reinforce the current inadequate level of
unbundling. This would, in turn, also facilitate cooperation among network operators.
(1036) Economic evidence shows that full ownership unbundling is the most effective means to
ensure choice for energy users and encourage investment. This is because separate
network companies are not influenced by overlapping supply/generation interests as
ENERGY SECTOR INQUIRY – CONCLUSIONS
326
regards investment decisions. It also avoids overly detailed and complex regulation and
disproportionate administrative burdens. The independent system operator approach
would improve the status quo but would require more detailed, prescriptive and costly
regulation and would be less effective in addressing the disincentives to invest in
networks.
(1037) Furthermore, the public consultation has not revealed any significant synergy effects
linked to vertical integration. Indeed, where ownership unbundling has been
implemented, experience shows that both the network business and the (production and)
supply business continue to thrive after separation.
- The regulatory environment
(1038) Whilst ownership unbundling would substantially contribute to reducing problems of
market power and lack of liquidity, it is clear that also other measures will be needed. As
the Sector Inquiry confirms, Europe needs a substantial strengthening of the powers
of regulators and enhanced European coordination. This goes in hand with the
findings presented by the Commission in its Communication on “Prospects for the
internal gas and electricity market”. Only a strengthened regulatory framework can
provide the transparent, stable and non-discriminatory framework that the sector needs
for competition to develop and for future investments to be made.
(1039) The main ingredients of such a strengthened framework should be:
- enhanced powers for independent national energy regulators,
- reinforced coordination between national energy regulators,
- reinforced cooperation between Transmission System Operators (TSO), and
- substantially enhanced consistency of regulation in cross-border issues.
(1040) Reinforced coordination between national energy regulators, with a stronger role
for Community oversight to ensure the Internal Market interests, particularly as
regards cross-border issues and areas most critical for market entry, will be necessary to
overcome the current regulatory cross-border gap which cannot be remedied by
application of competition rules alone. Options for regulatory measures are discussed in
the Communication on “Prospects for the internal gas and electricity market”.
- Chronic lack of liquidity
(1041) Reinforced unbundling rules and an improved regulatory environment for cross border
issues in particular should, in the medium term, substantially reduce the problems of
market power and lack of liquidity in a sustained manner, by bringing additional supplies
to concentrated national markets. However, there remain serious concerns in the short
term, as regards the lack of sufficient liquidity and sustained market power in
wholesale markets, which is leading to higher prices in retail markets just as full
liberalisation is to be implemented on 1 July 2007.
ENERGY SECTOR INQUIRY – CONCLUSIONS
327
(1042) As already indicated, competition law enforcement will be an important tool to address
any anti-competitive conduct concerning this issue. However, more may be needed. As
the levels of concentration in gas and electricity markets have remained high, often
reflecting pre-liberalisation monopolies, national energy regulators should analyse
conditions in their respective markets in co-operation with competition authorities and
make appropriate proposals. Measures taken in the past by a number of Member States
include release programmes (i.e. electricity Virtual Power Plant auctions and gas release
programmes).
(1043) It is also recalled that certain Member States have introduced under national law ceilings
on ownership of electricity generation and control over long-term upstream gas contracts
(imports and national production), as an effective measure to rapidly reduce market
power. For electricity, such measures could imply either divesture or asset swaps of
power plants on a European scale. For gas, it could mean contract release, contract swaps
and/or divesture of domestic production, as have been applied in recent merger cases.
Widening of small TSO areas and introducing more open and flexible tendering
procedures for balancing energy could reduce the current high levels of concentration in
balancing markets and remove obstacles to entry, with a positive knock-on effect in
wholesale markets.
(1044) Furthermore, the Sector Inquiry has highlighted the importance of enhancing the scope
for entry through investment in new generation and gas import infrastructure as well as
strict application of use-it-or-lose-it provisions for infrastructure and suitable generation
sites.
- Lack of transparency in market operations
(1045) There is general recognition that access to market information should be further
enhanced. All relevant market information should be published on a rolling basis in a
timely manner. Any exceptions should be very strictly limited to what is required to
reduce the risk of collusion. Guidelines as well as monitoring and eventually adaptation
of existing regulation should serve to further enhance transparency in the gas and
electricity sector. Intended proposals are outlined in the Communication on “Prospects
for the internal gas and electricity market”.
- Other important issues
(1046) In addition to these four fundamental areas, other issues of pro-competitive market
environment need consideration. On these issues, specific suggestions for regulatory
action at EC level are made by the Commission in its Communication on “Prospects for
the internal gas and electricity market”.
(1047) Regulated retail tariffs can have highly distortive effects and in certain cases pre-empt
the creation of liberalised markets. It is of crucial importance to assess the impact of
remaining regulated supply tariffs on the development of competition, and remove
distortions.440
440
For the household market segment, there is a need to strike the right balance between competition and universal
public service obligations.
ENERGY SECTOR INQUIRY – CONCLUSIONS
328
(1048) In order to achieve that access to new infrastructure is not unduly restricted, the
Commission should continue to ensure that exemptions from access provisions are not
detrimental to the development of competition. It is important that projects continue to
be scrutinized on a case by case basis with strict application of competition principles
striking a proper balance between incentives for ex-ante investment and ex-post
competition, and that the exemption procedures are streamlined.
(1049) In order to achieve a single European network from the perspective of the network user,
there is a need for appropriate harmonisation of market design, especially regarding
methods having an effect on cross border trade. Action is needed, wherever current
capacity is insufficient, to develop interconnector capacity as a necessary condition for
the development of competition and the integration of markets. These aims can only be
achieved through increased cooperation between national regulators inducing increased
cooperation among TSOs across national borders within a well-defined procedural
framework.
(1050) In order to put more gas transmission capacity on the market, it will be important to
clarify the legal position of pre-liberalisation long-term gas transmission contracts under
the Second Gas Directive, which are already now subject to strict use-it-or-lose-it rules
and to the rules of competition law.
(1051) Further changes are needed regarding the method for allocating limited interconnector
capacity. For electricity, implicit day-ahead auctions or equivalent measures should be
promoted as much as possible to ensure that interconnectors are used to their maximum
extent. TSOs should also have incentives to maximise the amount of cross border
capacity made available to the market.441
(1052) In order to provide sufficient guarantees for effective access, third party access for gas
storage should be reviewed so as to strike the right balance between the need for
effective access and maintaining incentives for new storage developments.
(1053) A monitoring system for trading on wholesale markets (e.g. power exchanges) would
increase market participants’ confidence in the market and limit the risk of market
manipulation. Regulators should be empowered to collect and exchange relevant
information in this respect. They should have the power to make recommendations for
enforcement action or have the power to carry out such enforcement action themselves.
The Sector Inquiry has identified a number of serious shortcomings which prevent European
energy users and consumers from reaping the full benefit of the liberalisation process. The
findings support the conclusions of the Communication on “Prospects for the internal gas and
electricity market”, which has been carried out by the Commission in the follow up to the
Green Paper and in the course of the preparation of the Strategic EU Energy Review. These
initiatives bring forward the Commission's intentions as to proposals for regulatory reform,
aiming at an Internal Market for energy that contributes to sustainability, competitiveness and
security of supply. In addition, and in parallel, the Final Report also draws conclusions with
regard to enforcement action under EC competition law. Both these documents aim at
identifying and remedying obstacles to creating a single European energy market, in which
consumers fully benefit from the opening of markets to competition.
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e.g. Scarce capacity that is kept in reserves by some TSOs for emergency situations may be offered to the market as
interruptible capacity, and can be bought back when required, using for instance cross border congestion rents