A target model for the European gas market: Impact on ...€¦ · This discussion paper has been prepared within the framework of a CERRE Executive ... 120711_CERRE_CES_GTM_DiscussionPaper_GC

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A target model for the European gas

market:

Impact on trading and investments

Discussion paper

Guido Cervigni (Research Fellow, CERRE,

and Research Director, IEFE – Bocconi)

12 July 2012

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Table of content

About CERRE ................................................................................................................. 3

About the author .............................................................................................................. 4

Executive summary ......................................................................................................... 5

Introduction ..................................................................................................................... 8

1. Trading in the “new market environment” ............................................................... 11

2. The game-changers: a global gas market and retail liberalisation in Europe .......... 13

3. What is the future of the oil-linked long term supply contracts? .............................. 18

4. Will the new market environment lead to higher gas prices? .................................. 22

5. Will shorter term markets stifle investments? ......................................................... 24

6. Network infrastructure development in the target-model environment .................... 25

7. Issues for the discussion ........................................................................................ 28


About CERRE

Providing top quality studies, training and dissemination activities, the Centre on

Regulation in Europe (CERRE) promotes robust and consistent regulation in Europe’s

network industries. CERRE’s members are regulatory authorities and operators in those

industries as well as universities. CERRE’s management team is led by Dr Bruno

Liebhaberg, Professor at the Solvay Brussels School of Economics and Management,

Université Libre de Bruxelles.

CERRE’s added value is based on:

its original, multidisciplinary and cross sector approach;

the widely acknowledged academic credentials and policy experience of its team

and associated staff members;

its scientific independence and impartiality.

CERRE's activities include contributions to the development of norms, standards and

policy recommendations related to the regulation of service providers, to the specification

of market rules and to improvements in the management of infrastructure in a changing

political, economic, technological and social environment. CERRE’s work also aims at

clarifying the respective roles of market operators, governments and regulatory

authorities, as well as at strengthening the expertise of the latter, since in many member

states, regulators are part of a relatively recent profession.

This discussion paper has been prepared within the framework of a CERRE Executive

Seminar which has received the financial support of a number of stakeholders in the gas

industry including CERRE members. As provided for in the association's by-laws, it has

been prepared in complete academic independence. Its contents and the opinions

expressed in the document reflect only the author's views and in no way bind either the

CERRE Executive Seminar sponsors or any member of CERRE (www.cerre.eu).

http://www.cerre.eu/


About the author

Dr Guido Cervigni is a Research Fellow at CERRE and a Research Director at IEFE-

Bocconi. He is also an advisor to businesses and governments across Europe on a wide

range of competition policy and regulation issues related to energy markets, ranging

from market design to tariff regulation, contracts and asset evaluation.

Dr Cervigni was previously the head of economic analysis and regulatory relations in the

Regulatory Affairs Department at Enel S.p.A, and, before that, head of business

development in an energy trading company. Guido started his career with the Italian

energy regulatory authority (AEEG), where he was a senior economist in the Tariff

Division and later Head of the Competition and Markets Division. In that capacity, he

represented the Authority in several working groups of the Council of European

Electricity Regulators.

Guido holds a PhD in economics from Bocconi University, Milan, where he is currently a

lecturer in Economics of Regulation in addition to its abovementioned research

directorship at IEFE.


Executive summary

The 3rd Package has given new impetus to the establishment of a single European gas

market by introducing a new institutional framework to govern the process of

harmonisation of regulatory arrangements in the Member States.

Although many important issues related to the future gas market design are still being

discussed[1], the broad policy objectives are clear. The cornerstones of the European gas

market project are the liberalisation of gas retailing and the development of an open gas

transmission system allowing gas from the widest possible set of sources to be delivered

anywhere within Europe.

Thinking beyond full implementation of the 3rd Package may mean thinking what could

happen by the end of the current decade or in the early 2020s, when the European

supply/demand picture could look very different from what is being assumed for the next

few years. Anticipating the dynamics of the European gas industry over that time horizon

is, however, crucial to major business decisions which are currently being taken or will

be so in the coming years.

CERRE’s seminar on “A target model for the European gas market” will gather together

high level industry experts drawn from most stakeholders involved to discuss the

foreseeable dynamics of that market once the main European policy objectives for a

single market will have been achieved, i.e. once:

a) physical and contractual network congestions within Europe are virtually absent,

as a consequence of network upgrades and new regulation on network capacity

allocation and access charging;

[1]

The discussion on the implementation of the gas target model is extensive. See for example: Frontier Economics, 2011. Target Model for the European Natural Gas Market; Moselle, B., White, M., 2011. Market design for natural gas: the Target Model for the Internal Market. LECG Report for the Office of Gas and Electricity Market; Glanchant, J.M., 2011. A vision for the EU gas target model: the MECO-S model; CEER public consultations on the EU Gas Target Model, available at: http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20 PUBLIC%20CONSULTATIONS/GAS/Gas_Target_Model

http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20%20PUBLIC%20CONSULTATIONS/GAS/Gas_Target_Model



b) gas retailing in Europe be effectively liberalised.

The seminar will explore how wholesale trading will look in that new market environment

and who will be the winners and losers. Alongside market issues, the seminar will also

address topics and questions related to the development of gas infrastructure. This

paper covers those topics with a view of providing a background and focus for the

seminar discussions.

With regard to wholesale trading arrangements, it is argued that both the traditional

approach to long term contracts, based on oil indexation, and the more recent attempts

to review the indexation bases are being challenged and, as such, are unlikely to remain

or become the main feature of the future European gas market. A possible alternative

scenario can be characterised in these terms:

- spot markets’ liquidity and integration will increase;

- spot gas prices will not necessarily reflect oil-prices, but the fundamentals of the gas

market;

- the average duration of long-term contracts for delivery in Europe will be reduced;

prices in those contracts will reflect market participants’ highly speculative

expectations concerning future spot prices;

- final consumers of gas, in particular the smaller ones, will not need to be exposed to

more price volatility over the time horizon of the typical retail contracts, since their

suppliers will provide the necessary hedge.

It remains to be seen whether the move to a new market environment will change the

relative bargaining power of the European buyers and the main gas suppliers, possibly

to the detriment of European consumers. A further open issue is related to the

expanding role of short term transactions. How will the latter impact investments? Will a

more marked boom-and-burst pattern result?


With regard to network investments, the relationship between merchant and planned

infrastructures in the 3rd Package reflects a fundamental lack of clarity on following

strategic question: what role should merchant investments play in the European

infrastructure development? Going forward, the economic interactions between centrally

planned and merchant investments might provide a solution to the ambiguity of the

European approach on infrastructure development. According to the 3rd package, system

operators and regulators are required to target a level of transmission capacity that

ensures security of supply and promotion of competition. Those objectives call for a

structural excess of import capacity into Europe, compared to the demand for

transmission services expressed by the market in normal conditions. In a situation of

structural excess capacity, one can expect that the role of merchant investment will be

modest and that most of the infrastructures providing access to the European market will

be planned by system operators, approved by regulators and paid for by consumers.

Finally, the governance structure of the planning system designed in the 3rd Package still

needs to be tested. In particular it remains to be seen how difficult it will be for European

system operators and regulators to agree on the opportunity to make multi-country

network investments, to reach a common assessment of the benefits provided by those

investments to each country and to split their costs accordingly.


Introduction The 3rd Package has given new impetus to the establishment of the single European gas

market by introducing a new institutional framework to govern the process of

harmonisation of the regulatory arrangements in the Member States.

Although many important issues related to the future gas market design are still being

discussed1, the broad policy objectives are clear. The cornerstones of the European gas

market project are the liberalisation of gas retailing and the development of an open gas

transmission system allowing gas from the widest possible set of sources to be delivered

anywhere within Europe. Gas retailing is now fully liberalised: since 2007 all gas end-

consumers can be served by competitive retailers, even though in some countries the

arrangements for supplier switching still need to be improved.

The CAM-CM proposed network codes2, when implemented, will dramatically change

the way gas transmission capacity in Europe is defined and allocated. In particular the

delivery points for gas will be moved from borders to hubs. Meanwhile, measures to

coordinate the allocation of cross-border transmission between couple of countries are

being introduced.3

In addition, the measures set out in Regulation No 994/20104 to ensure security of gas

supply will greatly expand the flexibility, and possibly the capacity, of the European

transmission system. In particular, the requirement that by the end of 2013 the existing

cross-border interconnectors be able to handle physical reverse flows will make it

1 The discussion on the implementation of the gas target model is extensive. See for example: Frontier Economics,

2011. Target Model for the European Natural Gas Market; Moselle, B., White, M., 2011. Market design for natural gas: the Target Model for the Internal Market. LECG Report for the Office of Gas and Electricity Market; Glanchant, J.M., 2011. A vision for the EU gas target model: the MECO-S model; CEER public consultations on the EU Gas Target Model, available at: http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20 PUBLIC%20CONSULTATIONS/GAS/Gas_Target_Model 2 http://www.entsog.eu/publications/camnetworkcode.html .

3 For example the degree of convergence of spot gas prices at the Italian PSV and the Austrian Baumgarten hub has

greatly increased since the introduction of new short term interruptible capacity allocation mechanism since March 2011. 4 Regulation No. 994/2010 of the European Parliament and of the Council of 20 October 2010 concerning measures to

safeguard security of gas supply and repealing Council Directive 2004/67/EC.



http://www.entsog.eu/publications/camnetworkcode.html


possible to move gas from virtually any entry point to any exit point in the European

network. The “N-1” infrastructure security standard 5 may lead to levels of available

transmission capacity structurally in excess of demand.

The CERRE Executive Seminar of 13 September 2012 should address and discuss the

foreseeable dynamics of the European gas market once the main objectives of the

European policy for a single market have been achieved. Seminar panellists will

therefore be invited to characterize their expected future market scenarios under the

optimistic, but not unrealistic, assumptions that:

a) physical and contractual network congestions within Europe be virtually absent,

as a consequence of network upgrades and of the new regulation of network

capacity allocation and access charging6;

b) gas retailing in Europe be effectively liberalised7.

The seminar should also investigate how wholesale trading will look in this “new market

environment” where the pre-conditions for the development of a single European gas

market are satisfied; and who will be the winners and losers.

Alongside market issues, those related to the development of gas infrastructure should

also be explored. The extent to which the allocation of risk between consumers and

investors in transmission assets will be materially different from the past and, also, what

the role of the system operators will be are two sets of questions which will be

particularly investigated.

Thinking beyond full implementation of the 3rd Package may mean thinking about the

end of the decade or the early 2020s, a time when the European supply/demand picture

5 In the event of a disruption of the single largest gas infrastructure, the capacity of the remaining infrastructure

needs to able to satisfy total gas demand of the calculated area during a day of exceptionally high gas demand. 6 A scenario where effective “use it or lose it provisions” are implemented - discouraging capacity hoarding -, where

capacity is generally not rationed and a coordinated approach to transmission charges removes (or at least significantly limits) pancaking. 7

Effective retail liberalisation requires that all retailers have non-discriminatory access to the flexibility instruments available in the system and that reasonably efficient load profiling, switching and metering arrangements are in place.


may look very different compared to the next few years. However, anticipating the

dynamics of the European gas industry over that time horizon is crucial to major

business decisions which should be taken now or in the next coming years.

This paper covers the above topics with a view of providing a background and focus for

the CERRE Executive Seminar’s discussions.


1. Trading in the “new market environment”

The traditional setting: downstream monopolies and long-term oil-indexed contracts

In the traditional organisation of the European gas sector, national de facto monopolists

would source gas from the producers through long-term agreements, with duration up

to thirty years. The allocation of risk between buyers and sellers implemented by those

long term contracts is consistent with the broad objectives of:

i) Increasing the penetration of gas in the retail market served by monopoly

national utilities, by substituting gas for oil and coal. In this respect, oil

indexation of contract prices is meant to ensure that gas remains competitive

compared to alternative fuels in the buyer’s market, and;

ii) Protecting the seller’s investment in production and transmission against the

risk of hold-up by the buyer, since the seller has no access to the consumers

at the end of the pipeline.

The buyer’s return depends on his bargaining power when the contract is negotiated.

The buyer’s return is to some extent guaranteed by clauses that provide that the price

must allow to “economically” market the gas in the destination market. The seller is the

residual claimant of the value of the gas in the destination market, but the contract

generally does not guarantee any return8 to the seller.

The long term contracts feature some elements of flexibility. First, take-or-pay clauses

identify a minimum and a maximum volume between which the cost of withdrawing gas

is equal to the contract price. Buyers are charged irrespective of withdrawal for volume

under the minimum (even though withdrawal can to same extent be postponed).

8 Lapuerta, 2011, Gas Markets, Presented to Florence School of Regulation, 22 March 2011.


Second, central European contracts include periodic price reviews which – typically

every three years – allow resetting the contract price if changes in economic

circumstances have significantly modified the relative value of the contract for the buyer

and the seller. If the parties cannot agree on a new price, each of them can trigger an

arbitration procedure, whose outcome is binding for both.

At the time that contract structure was developed buyers were de facto national

monopolists in gas retailing9. That allowed them to commit buying large quantities at a

price that needed to be competitive only against the price of the alternative fuels used

by the end consumers. Destination clauses, preventing the buyer to sell in other

countries the gas purchased under each contract, add a further level of protection of the

national monopolies, while allowing the producers to price-discriminate across

countries. Finally, thanks to their monopoly in gas retailing, incumbents could price-

discriminate their end-consumers, by charging prices consistent with the different

possibilities of fuel substitution available to each type of consumer.

9 Or, which is equivalent, in the gas import activity.


2. The game-changers: a global gas market and retail liberalisation in Europe

Two main developments appear to make the traditional long-term oil-indexed contract

structure untenable in Europe.

First, the evolving global market for gas is becoming increasingly liquid and is now

featuring its own price dynamic, not always connected to oil. Demand and supply shocks

witnessed in the past three years provide plenty of evidence of this change. Shocks on

the demand-side, including the global economic crisis and the increase of the Japanese

gas demand for electricity generation after the Fukushima accident have had a strong

impact on prices. In the longer term European gas prices might also be impacted by the

changes in gas demand resulting from the renewable electricity generation and energy

conservation policies. However, Asian demand for gas remains the largest potential

source of volatility of global gas demand. By 2017, China is expected to account for a

quarter of new gas demand and so will the Middle East and other Asian countries

together10.

On the supply-side, the fast development of non-conventional gas production in North

America has resulted in significant price drops. The resulting excess supply has been

absorbed by Europe, and to a larger extent by Asia, through a massive diversion of LNG

cargoes away from the US11. A similar market mechanism may also operate through the

international coal market: lower gas prices in the US could trigger substitution of gas for

coal in electricity generation and induce coal exports from the US, which could then

reduce the demand for gas in the coal-importing countries.

10

International Energy Administration, 2012. Medium-Term Gas Market Report 2012. 11

LNG gasification capacity in 2010 operated with a load factor around 10%.


Whilst the global gas markets are becoming increasingly integrated and gas prices

reflect demand and supply dynamics for gas (rather than for other fuels) to a much

greater extent, European gas prices still appear linked to some extent to oil prices. This

is because a significant portion of the European gas supply – largely for historical

reasons – has been sold on long term contracts with oil-linked prices. The price of the

large base of oil-indexed long-term contracts in Europe acts as a floor or a ceiling to the

spot prices when those contracts are marginal. The following figure illustrates the

aggregate wholesale supply of gas sources under take-or-pay contracts (Top); Q-Top-min

is the sum of the Top volumes, which must be paid for by the buyer irrespective of

whether they are drawn – typically 85-90% of the reference contract volumes; Q-Top-

max is the sum of the maximum volumes that can be drawn at the contract price -

typically 110-120% of the reference contract volumes. The figure also reports two

realizations of the residual demand of gas, i.e. the market demand for gas net of the

volumes supplied, at each price, from sources other than the take-or pay contracts.

As Figure 1 shows, when the residual demand crosses the top supply between the

minimum and maximum take-or-pay volumes (Resid Dem -1), the market clearing price

is set by the Top contracts. When the residual demand is smaller (Resid Dem -2) the Top

volumes are infra-marginal; they can be sold at a price determined on the residual

demand12. The same happens if the residual demand crosses the Top supply at Q-Top-

max (Resid Dem -3).

12

In case demand falls shorter than the aggregate minimum off-take quantity, the Top contracts become marginal again and the market clearing price equals the avoidable cost of withdrawing the minimum Top quantity. Notice that the option to with-draw the defaulted volumes at a later time may add a non-negligible opportunity cost component to the price in the first step of the Top supply function.


Figure 1: Aggregate wholesale supply of gas sources under take-or-pay contracts.

However, linked prices do not mean linked fundamentals. The link between gas and oil

prices resulting from the stock of existing long term contracts does not signal, by itself, a

link between the oil and gas market fundamentals. In fact, a link between the oil and gas

market fundamentals would show in the spot markets, independently of the long term

contracts; but that is precisely what is not happening.

The stock of oil-linked Top contracts could indeed adjust in time way such that the Top

prices keep setting the market clearing price. In terms of the Figure 1, that would be

represented by an expansion or contraction of the total minimum off-take volume such

that the (residual) demand crosses the flexible segment of the Top supply. However,

one would read that outcome, other things equal, as a symptom of market power,

rather than as a sign that the fundaments of the oil and gas markets are getting aligned.

Q-Top-min Q-Top-max

Top-SupplyResidDem - 1

ResidDem - 2

Q

P

Top-pricesResidDem - 3


Large and systematic deviations of the spot prices from the oil-based prices have

occurred since the end of 2008, as a comparison between the Oil-Indexed Contract and

the NBP spot price shows in Figure 2.

Figure 2: International gas prices, 2007-2011.

Source: Heather, P., 201213

.

The second game-changer in the European gas market is retail liberalisation. The

European former monopolists are finding it increasingly difficult to pass through to their

no longer “captive” consumers the long-term contract prices when those prices are

higher than the spot market prices. This is because large consumers have the incentives

and the ability to take advantage of competing offers. The impact is already evident,

13

Heather, P., 2012. The recent development of European gas hubs: Can they provide a true reference point? Available at: http://www.florence-school.eu/portal/page/portal/FSR_HOME/ENERGY/Training/Specialized_training/Presentatio ns/1.%20P.%20HEATHER%20-%2027.03.2012.pdf


even though limited by the various frictions in the switching process which still limit

retail competition for small consumers.

More dynamic wholesale and retail markets are putting the traditional arrangements

under stress. Stern and Rogers (2011)14 note that the number of long-term contract

price reviews settled through arbitrations has dramatically increased since 2005.

14

Stern, J., and Rogers, H., 2011. The Transition to Hub-Based Gas Pricing in Continental Europe. The Oxford Institute for Energy Studies.


3. What is the future of the oil-linked long term supply contracts?

The long-term take-or-pay oil-indexed contracts served two main purposes. They

guaranteed access to gas to European utilities at a price that allowed marketing natural

gas as a cheaper alternative to the fuels which it was replacing in the final market. They

also ensured a revenue stream for producers which replicated the dynamics of oil prices.

This contributed to the capability for gas upstream infrastructure to be financed, since it

was bringing their risk structure closer to that of oil investment, an industry which

capital markets have been familiar with for a long time.

In the new environment, the first objective pursued by the long-term contracts, i.e. gas

availability is becoming less relevant as a global spot market provides, to an increasing

number of countries, access to a diversity of sources. On the price side, oil indexed

contracts cannot guarantee a consistent revenue stream to the producers as they are no

longer sustainable by buyers: firstly, oil-related prices are not the competitive

benchmark at the retail level; secondly the former downstream monopolists have no

longer a captive customer base they can pass their procurement costs through,

irrespective of spot market conditions.

Further, the experience with the recent wave of disputed price reviews suggests that

arbitration proceedings are very expensive and their outcome highly uncertain.

Therefore, while being an effective tool to address exceptional circumstances,

arbitration does not appear to provide a suitable mechanism to set on a regular basis

the prices in long-term gas contracts.

Market participants are therefore exploring alternative indexation mechanisms for long

term gas contracts: E.ON is known to have proposed full indexation to spot prices in


2011 to Gazprom; in the same year a Statoil Poweo contract is reported to have

introduced indexation to coal and electricity prices15.

The economic rationale for that is not obvious if the spot market is liquid. With liquid

spot markets, long term contracts are used to hedge against volatile spot prices and to

(re)allocate risk between the counterparties. Indexation to the spot price removes the

hedging features of the long term contract, making it equivalent to a series of deals that

both the buyer and the seller can carry-out in the spot market. In other terms, full

indexation to spot price is to remove from the parties to the contract any long term

price commitment. So, with liquid spot markets, indexation to spot prices of long term

contracts has no obvious purpose.

With spot-price indexation, a long term contract effectively becomes a mere

commitment for the parties to enter spot-market transactions in the future. That may

suggest that moving to spot-price indexation, as opposed to terminating the long term

contract, is a way to address the expected lack of liquidity of the spot market. In other

terms the parties expect that they might not be able to buy or sell gas in the spot

market at the price prevailing in that market. For that reason a buyer and a seller would

find it useful committing to each other, far in advance, to exchanging gas at the price

clearing at each time the spot market. In other terms, in case of illiquid spot market,

long term contracts are valuable in a security of supply perspective, provided they

maintain on the supplier the obligation to physical deliver16. In case high spot market

prices were not sufficient to attract gas into Europe, the obligation to deliver embedded

in the long term contracts would surrogate the market mechanism in securing the

availability of gas. In that perspective spot-price indexation of long term contract might

15

That contract never operated because Poweo went bankrupt. 16

That does not hold for long term contracts that can be cash settled, which would allow the seller to pay the spot price instead of delivering gas.


be an effective transitory measure to guarantee security of supply until a fully functional

spot market develops.

However, in case of illiquid spot market the spot price cannot be expected to be

representative of the supply and demand conditions17. In particular, the prices of an

illiquid spot market might not be a good proxy of the retail prices. In that case, long

term contracts indexed to spot prices would not serve their primary role (besides

ensuring gas availability): hedging the buyers against the volatility of the retail prices.

In conclusion, indexing long term contracts to the spot price is of little use if the spot

market is liquid. If the spot market is not liquid long term contracts may contribute to

security of supply, but spot-price indexation may turn out an unwise hedging choice18.

Both the traditional approach to long term contracts and the more recent attempts to

review the indexation bases seem therefore to present challenges and are unlikely to

remain or become the main feature of the future European gas market. A possible

alternative scenario could be characterized as follows:

- the spot markets’ liquidity and integration will increase, which will make spot prices

more reflective of the demand and supply conditions and less vulnerable to

manipulations; liquid spot markets will also provide the main source of flexibility,

replacing the take-or-pay clauses in this role;

- spot gas prices will no longer reflect oil-prices, but the fundamentals of the gas

market; 17

Further, the price of gas in an illiquid market is possibly vulnerable to manipulations. 18

A similar assessment appears to hold for the indexation of the long term gas contracts to coal and electricity prices. That mechanism results in the seller bearing some of the electricity and coal price risk. However, gas sellers may not be the best placed party to take that risk on. For example, gas buyers firing gas to produce electricity may in fact more effectively hedge their risk by buying the unbundled gas, coal and electricity forward products which are typically available in the market.


- the average duration of long-term contracts for delivery in Europe will reduce19; the

prices in those contracts will reflect the market participants’ expectations of the

future spot prices, which will be highly speculative;

- the final, and in particular the smaller, consumers of gas will not need to be

exposed to more price volatility over the time horizon of the typical retail contracts,

since their suppliers will provide the necessary hedge.

19

As reported by Ofgem (Liquidity in the GB wholesale energy markets, Discussion paper, June 2009) the liquidity of contracts further than 4 years into the future is very poor. In addition, Hartley and others (Hartley, Peter R., and Brito, D.L., 2001. New Energy Technologies in the Natural Gas Sectors. Houston, Texas) find that the length of long-term LNG contracts is likely to fall as investment and transport costs fall and the number of players in the international gas market increases. Masten and Crocker (S.E., 1988. Mitigating Contractual Hazards: Unilateral Options and Contract Length. RAND Journal of Economics, Vol.19, No.3, 327-343) showed that, ceteris paribus, in the US there is an inverse relationship between the degree of competition in the market and the duration of long-term contracts.


4. Will the new market environment lead to higher gas prices?

A crucial question is whether the move to the new market environment will change the

relative bargaining power of the European buyers and of the main gas suppliers. After

the retail market liberalisation European utilities will no longer be in the position to

leverage on their downstream monopoly to improve their bargaining position against

gas producers. It is debatable, though, whether that advantage would have been

maintained in the context of an expansion and increasing integration of the global gas

market. In particular, the fast expanding demand for gas in Asia may compete for gas

supplies against Europe, allowing producers, other things equal, to capture an increasing

share of the surplus.

A related issue is whether the new market environment, centred on spot prices, might

ease or, on the contrary, make price coordination among the main gas suppliers more

difficult. The departure from long-term (oil-indexed) gas contracts raises concerns with

respect to the possible establishment of a gas-OPEC aiming to control global gas prices.

A thorough assessment of the future level of competition in the global gas market is

beyond the scope of this paper. However, one can conjecture that the traditional

market, characterized by a limited number of large long-term transactions, could be

more difficult to coordinate than a market where most of the transactions take place on

a short term basis. That might explain why all attempts to develop a collusive strategy

within the framework of the Gas Exporting Countries’ Forum (GECF) have failed so far.

The liberalisation of gas retail will make discriminating consumers according to their

availability to pay more difficult. As a consequence, other things equal, the average price

for gas will fall to the level of the marginal consumer’s availability to pay.


Contrary to what would happen in the scenario outlined above for Europe, the Asian

countries, where there are no immediate prospects for retail liberalisation, will maintain

their ability to offer very long term hedging opportunities to gas producers. That may

result in a segmentation of the global gas market into one where the buyers will be

willing to commit to 20-30 year purchases and another where buyers will be keen to

commit to shorter time-horizons only. It remains to be seen, however, whether the

buyers committing to very long term contracts will enjoy a material price advantage

over the others.


5. Will shorter term markets stifle investments?

In the first decade of this century, significant un-hedged investments in production and

in LNG infrastructures took place20. However, there are concerns over the ability of the

new market environment to deliver investments. In particular, with less long term

hedging opportunities available, investments might follow a more marked boom-and-

burst pattern. That would lead to greater price volatility, as (longer) periods of excess

and of tight supply would alternate. This is typical of liberalised markets where scarcity

leads to higher prices, which in turns attract investments. That tendency has been

observed in the British and in the US gas markets; oil exploration and production

investments also appear to follow such pattern.

Perhaps, the single most important objective of the gas liberalisation policy – as for

electricity generation in the 90s – is therefore moving the investment risk from

consumers to market investors, under the assumption that this will lead to more

efficient investment decisions and ultimately to lower costs. As such, boom and burst

cycles are a fundamental feature of liberalised markets where investment is primarily

driven by price signals.

20

These include the Qatargas II project (http://www.qatargas.com/PressReleases.aspx?id=842&tmp=88&folderID =122), started in 2005, the Ormen Lange pipeline, built in 2003 to transport Norwegian gas to UK on the basis of the NBP prices and the LNG Gate Terminal in the Netherlands, completed in 2011.

http://www.qatargas.com/PressReleases.aspx?id=842&tmp=88&folderID%20=122

http://www.qatargas.com/PressReleases.aspx?id=842&tmp=88&folderID%20=122


6. Network infrastructure development in the target-model environment

The relationship between merchant and planned infrastructures in the 3rd package is

rather complex.

The default investment development regime in Europe is centralized planning21. A

national 10 year network development plan is prepared by the system operator and

approved by the national regulator. Once an investment is included in the development

plan, the system operator must execute it. The cost of the investment is then covered

through the transmission tariff.

Consistently, the default access regime is third party access (TPA), whilst merchant

infrastructure is treated as an exception subject to strict requirements set out in

legislation. In practice, significant merchant investments have been allowed, particularly

for certain type of infrastructures, such as LNG and storage facilities.

The mismatch between rules and practice shows a fundamental lack of clarity on the

strategic question as to what role merchant investments should have in the European

infrastructure development. This lack of clarity is reflected in ambiguous conditions for

granting exemption from the TPA requirements. For example, one of those conditions is

that “the level of risk attached to the investment is such that the investment would not

take place unless an exemption was granted”22 That condition could be interpreted as

granting the regulator a “right of first call” on the project applying for the TPA

exemption. In this perspective the risk condition would be met if the regulator would not

21

Directive No. 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas and repealing Directive 2003/55/EC, Art. 22 and 41, 3, (c) and (d). 22

Directive No. 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas and repealing Directive 2003/55/EC, Art. 22 and Art. 36, 1, (b).


allow for the investment within the regulated framework23, as it would place excessive

risks on consumers.

Alternatively, the risk condition could be read from the developer’s perspective. In this

interpretation the exemption would be granted in case the developer did not find the

investment worth making in the TPA regime. Under this interpretation, the regulator has

no right of first call on the project and the TPA-exemption becomes a “price to pay”, by

the regulator, in order to make the investment happens. This approach leads the way to

negotiation between the regulator and the developer, where the TPA-exemption is

traded against surplus transfers to the consumers. That does not appear to be the

intention of the Directive, but in one case where such negotiations presumably did not

take place, the exemption for the Britned cable (a DC power interconnector between the

UK and the Netherlands), the European Commission intervened at the end of the

process to require such a “surplus transfer” (in the form of a ceiling on the rate of

return).

Going forward the economic interactions between the centrally planned and the

merchant investments might provide a solution to the ambiguity of the European

approach on infrastructure development.

The profitability of the merchant projects will crucially depend on the level of

transmission capacity planned by the system operators and approved by regulators in

the revenue/tariff setting process. According to the 3rd package, system operators and

regulators are required to target a level of transmission capacity that ensures security of

supply and promotion of competition. Those objectives call for a structural excess of

23

The underlying assumption here is that if the project is undertaken on a regulated basis, its return will be guaranteed by the regulator.


import capacity into Europe, compared to the demand of transmission services

expressed by the market in normal conditions.

In a situation of excess capacity, though, the expected returns for a merchant

investment will generally be negative, as the total level of interconnection pursed by the

system operators will be such that the market participants never perceive any scarcity of

transmission capacity. If that scenario materializes, one can expect that the role of

merchant investment will be modest and that most of the infrastructures providing

access to the European market will be planned by the system operators, approved by

the regulators and paid for by the consumers.

In addition, as returns on centrally planned investments are guaranteed, gas consumers

bear the risk that the corresponding transmission capacity remain underutilized and the

system operator bears no negative consequences for overinvestment (in fact is more

affected by security of supply failures). As a consequence, system operators may have

an incentive to over scale their system, which would further discourage the merchant

investments.

Finally, the governance structure of the planning system designed in the 3rd package still

needs to be tested. In particular it remains to be seen how difficult it will be for the

European system operators and regulators to:

- agree on the opportunity to make multi-country network investments;

- reach a common assessment of the benefits provided by network investment to

each country and split its cost accordingly;

- induce foot-dragging countries to plan positive net valued investments and to

timely implement them.


7. Issues for the discussion

The main drivers for the evolution of the European gas industry – unconstrained gas

trading within Europe and retail market opening – are now well established policy

objectives, actively pursued by the European and national institutions. Nonetheless the

impact of those changes on the functioning of the European wholesale gas market and

on the relationship with the suppliers of gas to Europe is still undetermined. Any

judgment is highly contentious at this stage.

This paper suggests a possible scenario with a view of providing food for thought and

stimulating debate. With the same objectives in mind, panellists and participants are

hereby invited to consider the following questions, which could be topical for the

discussions at the CERRE Executive Seminar of 13 September.

On gas trading:

How will the opening up of down-stream markets impact incumbents’ risk

hedging strategy?

Will greater vertical integration of production and retail replace the traditional

organisation based on long term wholesale supply contracts?

What is (and might become in the future) the rationale for oil-indexed gas

contracts?

What is the competitive landscape for the international gas market? What are

the chances that effective competition will develop at the production level?

Could upstream investments be affected by the development of wholesale spot

gas markets? Are there any specific differences, in this respect, between the gas

and the oil industry?


Will those countries which retain downstream monopolies enjoy an advantage

compared to Europe in terms of negotiating power vis-à-vis gas suppliers?

On infrastructure development:

How will the gas target model develop?

Is a mixed merchant/planning regime for network development decision making

(and risk taking) desirable and sustainable in the European context?

Is a demand-driven approach to infrastructure development - where shippers

take legally-binding commitments to pay for most of or the entire cost of new

infrastructure, whether or not it is fully utilised – viable in the European context?

In case a demand-driven approach turns out to be not workable, should

transmission system operators bear the risk of possible underutilisation of new

infrastructure? Are transmission system operators the most suitable party to

bear such a risk?

How system operators will factor in the impact of network investments on

security of supply and on competition in assessing the merit of new

infrastructure?

How will the cost of network investments be split among European customers?

On options for policy and regulatory interventions:

Is there a need for further policy & regulatory measures in Europe to ensure that

the necessary preconditions for network investments be met, in particular in

terms of stability, predictability and incentives for system operators?

Does the current regulatory framework provide adequate indications on cost

sharing of network investments benefitting several European countries?

Are there measures that could be taken at the Union level to reduce the risk

that, even only for a transitory period, the main gas suppliers to Europe could be


able to exercise (too much) market power, to the detriment of European

consumers?

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A target model for the European gas market: Impact on ...€¦ · This discussion paper has been prepared within the framework of a CERRE Executive ... 120711_CERRE_CES_GTM_DiscussionPaper_GC