EUGAS Prospects of Gas Supplies to the Europ

� Corresponding author. Tel.: +49-2211-7

E-mail address: [email protected] Formerly at the Institute of Energy

Cologne, Germany.2 IEA (2003a: p. III.6).3 IEA (2002a: p. 110).

0957-1787/$ - see front matter # 2004 Else

doi:10.1016/j.jup.2004.04.014

091-816.

.de (A. Seeliger).

Economics, University of

vier Ltd. All rights reserved.

Utilities Policy 12 (2004) 291–302
www.elsevier.com/locate/jup
Prospects of gas supplies to the European market until 2030—resultsfrom the simulation model EUGAS

J. Perner a,1, A. Seeliger b,�

a RWE AG, Essen, Germanyb Institute of Energy Economics, University of Cologne, Albertus-Magnus-Platz, 50923 Cologne, Germany

Received 25 October 2003; received in revised form 9 March 2004; accepted 5 April 2004

Abstract

Natural gas is the fossil energy fuel estimated to have the highest demand growth rates in Europe during the first three decadesin the 21st century. Hence, substantial new gas supplies are needed for the European energy markets in the coming years. In thisarticle, future European gas supplies are quantitatively projected by using the long-term optimisation model EUGAS, developedat the Institute of Energy Economics at the University of Cologne in year 2000. The model simulations show no discernible physi-cal gas scarcity at least for the next 20–30 years in Europe, but significant investments in new production and transportationfacilities will be necessary during this time period. Diversification of supplies and political considerations will have significantimpacts on the development of new gas resources and on investments needed. Nevertheless, the unit costs of supplies are moder-ate, and only minor cost driven price increases have to be expected during the coming decades—at least as long as future gasdemand growth does not significantly exceed current projections.# 2004 Elsevier Ltd. All rights reserved.

JEL classification: C61; L95; Q41; Q48

Keywords: Gas resources; Security of supply; Transportation infrastructure

1. Introduction

Natural gas is expected to gain rising market shares

in the primary energy market in Europe during the first

three decades of the 21st century. Today, natural gas

has a share in the primary energy market of approxi-

mately 23% in western Europe (OECD Europe) and of

22% in Germany.2 According to the IEA, global gas

consumption will increase by more than 95% until year

2030, and gas demand will exceed that of coal by year

2010. The share of natural gas in the global primary

energy market is estimated to increase by 5%, reaching

28% in 2030.3 The reasons for the increase in natural

gas consumption can be found in the high resourceavailability, low specific carbon dioxide emissions com-pared to other primary energy fuels, and the expectedsubstantial installation of gas-fired power generationcapacity, especially of modern combined cycle gas tur-bine (CCGT) plants and combined heat and power(CHP) plants.The massive increase in natural gas demand in

Europe implies that new gas sources have to bedeveloped for the European market. But where is theneeded gas expected to come from in the future? In anumber of European countries, current natural gasproduction stagnates or decreases. Therefore, the devel-opment of new sources inside and outside Europeseems to be indispensable. The main questions thathave to be raised in this context are: upon which gasproducing regions and gas sources will European sup-plies depend on in the long-term future? To whatextent is Europe able to contribute to European sup-plies? How much gas will have to be imported from

292 J. Perner, A. Seeliger / Utilities Policy 12 (2004) 291–302

outside Europe and from which time? By which trans-portation routes will the gas flow to the European mar-kets, and where or when might bottlenecks within thetrans-European transportation network appear? Whichpolitical measures have to be taken in order to securethe reliability of gas supplies even if political, technicalor financial obstacles threaten gas deliveries from oneor several producing countries, e.g. because gas trans-ports through transit countries are interrupted?This article aims at answering some of the questions

raised above by running the long-term simulationmodel EUGAS (European Gas Supply Model). In thefollowing section, the structure of EUGAS is described.Section 3 provides a summary about the main numeri-cal assumptions of the simulations. Section 4 highlightsthe most important results of the model runs concern-ing gas production and transportation, whereas Section5 discusses investments and marginal supply costs.Comprehensive political implications can be found inSection 6.

2. Structure of the model EUGAS4

The model EUGAS is a simulation tool in order toanalyse the future European natural gas supply quanti-tatively. It is structured as a long-term, dynamic, inter-regional optimisation model. The objective and therestrictions of the model are linear (linear program).EUGAS provides forecasts until the period 2030 (years2030–2034).5 The time periods are extended to fiveyears in order to reduce the complexity of the model.6

The model optimises future European natural gassupplies provided that European gas demand is satis-fied at minimum costs (objective of the optimisation).The logic of the model algorithm is that of a perfectlyinformed central decision taker who optimises overallsocial welfare. By applying this approach, the marketresults of perfect competition are reproduced. Thoughthe European gas market is currently dominated by anoligopoly of some major gas producers, the market canbe expected to become more competitive in the comingyears because of the European gas market liberalis-ation and the emergence of new supplies from upcom-ing gas producing countries (e.g. Nigeria, Egypt, etc.).

4 For further details see Perner (2002).5 The optimisation runs from 2005 to 2064. The extension of the

optimisation period until 2060 is necessary in order to avoid the so-

called end effect. The technical and economic lifecycle of production

and transport assets comprise 25 years and more. The optimisation

period has to be extended in the same range in order to avoid the dis-

tortion of investment decisions at the end of the forecast period.6 The term ‘period’ always refers to the first year of a five-year

period (model period 2005 covers the years 2005–2009, period 2010

the years 2010–2014, etc.).

The main parameters, which have impacts on themodel results, are European gas demand, supply costsand gas reserves. Further on, existing production andtransportation capacities predetermine some of the gasflows especially during the first time periods (until year2010), since past investments in gas facilities are irre-versible and, therefore, regarded as sunk costs.In EUGAS, the disaggregated gas demand of all

national states in Europe is given to the model (seeFig. 1). Gas demand of non-European countries istaken into account if this demand reduces the gasreserves available for European consumption (e.g. inAlgeria). The annual gas consumption is split season-ally into three different load periods—summer, winterand a bipartite transitional period. In order to smooththe seasonality of the load, existing storage capacitiesand publicly known storage extensions are included inthe input data.European gas demand is satisfied by both, intra-Eur-

opean production and gas sources from outside Eur-ope. Gas production comprises exploration,production, storage and processing close to the gasfields. The model optimises the extension and decom-missioning of production capacities as well as annualproduction quantities in the most important producingcountries. In EUGAS, the main intra-European gasproducing countries compriseDenmark, theNetherlands,Norway and the UK. Main non-European producingcountries are some states of the former Soviet Union(Russia, Azerbaijan, Kazakhstan and Turkmenistan),Algeria and some other African states (Angola, Libya,Egypt and Nigeria), and the Middle East (Iran, Iraq,Qatar, Oman, United Arab Emirates and Yemen). TheCaribbean states Trinidad and Tobago and Venezuelaare taken into account, too. In some cases, essentialproducing countries are further sub-divided into sub-regions, e.g. Russia, Algeria and Norway (see Fig. 1).Natural gas production is limited by the availability

of gas resources in the producing countries: extractedgas volumes have to be lower than the resources avail-able at a certain point of time. In the model, thedecline of resources is reduced by the discovery of newdeposits (exogenously given in the model). Availablegas resources and costs of production are differentiatedby the average size of the fields, the reservoir depth, thegas flows per well and (in case of offshore production)the water depth. Existing production capacities areintegrated into the optimisation.Natural gas production of less important European

gas producing countries (e.g. Germany, Italy, Romania)is exogenously given to the model. These are countrieswith relatively low gas resources having only localimpacts on gas supplies. In these cases, gas output issubtracted from domestic demand.The produced gas has to be transported from the

production regions to the European markets. The gas

J. Perner, A. Seeliger / Utilities Policy 12 (2004) 291–302 293

is transported by pipelines or as LNG to Europe. Fur-

ther on, long-distance trans-European transports

(within Europe) are simulated. The model optimises the

extension of pipeline capacities, the extension and

decommissioning of liquefaction and regasification

plants as well as current gas flows.In EUGAS, the transportation network is modelled

as a system of interlinked nodes or ‘hubs and spokes’,

which are connected by pipelines and LNG (Fig. 2).

The model includes both, existing and potential con-

nections between the regions. Pipeline capacities

between two countries may be interpreted as single or a

bundle of pipelines. Accordingly, LNG capacities rep-

resent both real single plants and a bundle of plants.The gas supply costs comprise capacity and operat-

ing costs of gas production and transportation. The

costs of LNG tankers and, optionally, transit fees are

taken into account separately. Costs are discounted by

using interest rates. Different discount rates for pro-

duction and transport can be applied, e.g. because of

different risk exposures for production and transport.

In this paper, a discount rate of 10% is applied for

both, production and transport.Apart from costs, long-term supply contracts and

risk diversification can have major impacts on future

European gas supplies. Existing long-term supply con-

tracts can optionally be integrated into the model. In

this case, contracted gas quantities fixed in long-term

import contracts are minimum supply volumes to the

corresponding consumption regions. If the sum of con-tracted gas volumes of a country is higher than its con-sumption, the import contracts are shortened accordingto their proportion in the supply portfolio of thedemand region (pro rata).The diversification of the gas purchase portfolio of a

gas-importing country is often aimed at minimizing therisks of potential supply interruptions. Optionally,security of supply provisions can be integrated into themodel by limiting the market share of a producer or aproducing country in the national gas market.

3. Main numeric assumptions of the model

3.1. Natural gas demand

Gas consumption is exogenously given to the model.In the simulations, a rather moderate increase in gasdemand is assumed. The main driver of the consump-tion growth, at least in western Europe, is the expectedconstruction of new gas-fired power generationcapacity. Additionally, in eastern Europe, high econ-omic growth rates induce additional industrial gasdemand. In some southern European countries (e.g.Spain, Portugal, Greece) the market share of gas is ingeneral still low. In these countries, gas consumptionis expected to grow in all market segments (powergeneration, industrial, commercial and householdsector). Table 1 provides a synopsis of the estimated

Fig. 1. Regional coverage of EUGAS.


development of annual gas demand in Europe differ-

entiated by geographic area.7

3.2. Availability of resources

The availability of resources is given to the model

exogenously. In order to take the dynamics of gas

deposit discoveries into account, EUGAS differentiates

between known (proven) reserves and unknown (not

proven) resources. While known reserves are available

by year 2005, unknown resources are exogenously

added to the reserve base in the following time periods.

Total unknown gas resources are discovered until

model period 2060. Table 2 shows the resources avail-

able by period 2005.8

7 Own calculations based on EIA (2003), EU (1999), IEA (2002b),

Cedigaz (2000), UN (1999) and Razavi et al. (1996).8 See BGR (2003), BP (2003), Cedigaz (2003), ENI (2003), Exxon-

Mobil (2003) and IEA (2003a).

3.3. Production and transport capacities

EUGAS optimises the construction of additionalproduction and transportation capacities as well as thegas quantities being produced and transported by usingthese facilities. Existing production and transportationcapacities, that means existing pipeline capacities aswell as LNG liquefaction and regasification terminals,are given to the model. Further on, facilities currentlyunder construction are taken into account until year2005. Table 3 shows the existing capacities of LNGliquefaction plants in gas producing countries relevantfor the European market. In parts, the existingliquefaction capacity of these countries is not takeninto account in EUGAS, since this capacity share isdedicated to markets outside Europe. For example,LNG from Trinidad and Tobago is not only deliveredto Europe, but also to the US.9 This means that someof the LNG liquefaction capacity of T&T has to bereserved for the US market.

3.4. Production costs

Gas production costs comprise investment costsand—to a much lower extent—operating costs. In themodel, investment costs (calculated as annual capital

Table 1

Natural gas demand (in BCM/a)

2
005 2010 2 015 2020 2 025 2 030
OECD Europe
531 604 672 725 771 801
Other Europe
35 44 49 54 56 56
CIS
561 603 638 663 677 693
Others
147 176 197 211 218 219
Total 1
274 1426 1 555 1653 1 722 1 768
Fig. 2. Transportation system of EUGAS.

9 For detailed information on LNG terminals see Drewry (2002),

Clarkson (2002), GM (2001), Roe (2001), Drewry (1999) and Cedigaz

(1999).


costs) comprise drilling costs, investments in pro-

duction facilities at the wellhead, pipelines near the gas

fields, processing plants, metering and communication

infrastructure, etc. Additionally, in EUGAS, invest-

ments in production capacities include the costs of

natural gas exploration. The internal rate of return of

gas production is assumed to be 10%.As mentioned above, gas reservoirs and production

are assigned to one or several different ‘resource clas-

ses’ in the model in order to reflect the main cost dri-

vers of gas production. Resources are classified

according to selected criteria like reservoir depth, the

size of deposits, the gas flow rate or the water depth

(offshore fields).10 Additionally, production costs differ

depending on the production region. Table 4 shows the

range of production costs for some major gas produc-

ing regions.11

10 For a detailed description see Perner (2002: pp. 110–127).11 Calculations are based on Perner (2002), NPD (2003), IEA

(1995), OME (1995), Pauwels (1994) and Masseron (1990).

3.5. Transport costs

Construction costs of pipelines are calculated byusing the diameter of the pipes. Costs are derived fromdata on pipeline costs in the USA and Canada pub-lished annually in the Oil and Gas Journal.12 Onshore,the specific investment costs are estimated at US$1200/(km�mm). For more difficult terrain, e.g. moun-tainous areas, higher cost levels are taken into account.Offshore, investment costs are 50% above those ofonshore pipelines due to their more expensive layingtechnique. The economic lifetime of pipelines is esti-mated at 30 years, and the internal rate of return oncapital is 10%. Costs for compressors are included sep-arately.Investment costs of LNG facilities refer to moderate

cost estimates. Regarding new liquefaction capacity,investment costs of about US$ 240/(t/a) are applied.Costs of regasification plants are estimated at US$ 80/(1000 m3/a). In the model, new built LNG tankers arepriced at US$ 175 million per tanker. Tankers are saidto have a standard transport capacity of 135,000 m3 ofliquefied natural gas. The economic lifetime of all LNGfacilities is 20 years, and the internal rate of return oncapital is 10%.Optionally, for some transportation routes transit

fees can be taken into account in the model, e.g. forpipeline transport via the Ukraine. Similarly, tankerspassing through the Suez canal have to pay a fee.

3.6. Technological progress

During the last decades, the petroleum industrydeveloped a wide range of new technologies for drill-ing, oil and gas extraction, treatment, etc. The R&Dactivities were, at least temporarily, accelerated by amassive downward pressure on oil and gas prices. Fur-thermore, petroleum companies had to apply new tech-nologies in order to develop new technically demandingoil and gas fields (e.g. high pressure, high temperaturefields in the North Sea, deep water fields, small fields),

Table 2

Resources in main supply countries (in BCM)

R
esources 2005
Russia 4
7,600
Iran 2
6,000
Middle East 1
8,810
Trinidad/Venezuela
4760
Algeria
4523
Iraq
3100
Nigeria
2940
Norway
2861
Turkmenistan
2860
Netherlands
1650
Egypt
1560
Libya
1314
UK
1140
Kazakhstan
1050
Azerbaijan
1000
Angola
370
Denmark
160
Table 3

Capacities of LNG facilities (in BCM/a; 2005)

Liquefaction plants
Regasification plants
Algeria 3
0 Belgium 8
Angola
0 France 2 3
Caribbean 1
0 Germany 0
Egypt
6 Greece 4
Iran
0 Italy 4
Libya
4 Portugal 3
Middle East 1
2 Spain 2 1
Nigeria 1
4 Turkey 6
Norway
3 UK 4
Russia
0
Table 4

Cost range in main producing areas (in US$/MBTU)

L

12 See True (1999), Mohitpo

owest cost

level

H

l

ur et al. (2001) and

ighest cost

evel

Algeria, Hassi R’Mel 0
.3 0 .9
Egypt, Nile delta 0
.5 0 .9
Libya, Wafa/NC 41 0
.6 0 .9
Netherlands, Groningen 0
.2 1 .0
Norway, Barents Sea 1
.0 1 .5
Russia, Western Siberia 0
.4 1 .3
UK, North Sea 0
.9 1 .5
True (2003).


and fields in petroleum provinces facing very harsh cli-matic conditions (deserts, arctic waters, permafrostregions, etc.).Future cost cuttings due to technological progress

are hard to predict. In EUGAS, costs of natural gasproduction are estimated to decrease by 1–1.5% peryear because of technological improvements. Furtheron, it is assumed that the investment costs of transportfacilities decrease by 0.5–1.5% per year. Nevertheless,while an industry becomes more mature, the speed ofaccumulation of technological knowledge slows down.Therefore, the annual cost reductions are diminishedby 3% per year in the model.

4. Net exports and transport routes

In the reference scenario, the simulation refers topure long-term supply cost minimisation. Risk diversi-fication, political constraints for gas production, long-term supply contracts and other ‘strategic’ considera-tions are not taken into account. Nevertheless, transitfees apply.

4.1. Net exports

Table 5 provides a summary about the developmentof net exports to European markets for the mostimportant gas producing countries.13

Gas producing countries inside the European Unionare loosing substantial shares in the European gas mar-ket in the coming years. Due to limited gas reserves,the UK, the Netherlands and Denmark, which todaydeliver significant gas volumes to foreign Europeanmarkets, will become net-importing countries. Net gasimports to the UK start in model period 2005, but onlyto a minor extent of 1 BCM per year. In the followingyears, net-imports will increase dramatically reaching25 BCM per year in 2010 and approximately 50 BCMper year in 2020. Additional gas will be imported to theUK by pipeline and LNG. In Denmark and theNetherlands, import needs are much lower. Both coun-tries start net-importing in model period 2025.Norway is the only western European country,

which can raise its gas production significantly.Norway increases its gas exports from 75 BCM in 2005to about 120 BCM in 2030. Nevertheless, the highergas output from Norway is not sufficient to compen-sate for the decreasing output of the UK and theNetherlands. Furthermore, the Norwegian gas pro-duction is more and more dislocated from fields in thesouthern North Sea to unfavourable fields in northern

13 Net exports are defined as gas production minus domestic

demand and exogenous given exports to regions outside Europe, e.g.

gas deliveries from Algeria to Tunisia or from Egypt to Jordan.

regions, e.g. the Norwegian Sea and the Barents Sea.Production costs in these regions are typically higherthan in the southern North Sea. Further, transport dis-tances and costs are higher. For example, gas producedin the Barents Sea is exported by LNG to theEuropean markets and not by short distance pipelineslike from the North Sea.Decreasing intra-European gas production has to be

replaced by imports from outside Europe. Moreover,the additional European gas demand has to be satisfiedby importation. According to the model simulations,the most important future gas supplies to Europe willcome from gas fields in non-European parts of Russia.Though Russia loses market shares in the first modelperiods, it can later raise exports to Europe consider-ably. The decrease of exports during the first years iscaused by a decline of gas production of western Siberianfields, which have to be replaced by new fields in yetundeveloped gas provinces—especially on the Yamalpeninsula and in the Barents Sea. In the reference scen-ario, gas fields in these provinces will not come on-stream with substantial quantities of gas before 2015 inYamal and 2020 in the Barents Sea, respectively. Aftercommissioning, production capacities will reach morethan 150 BCM/a in Yamal and about 100 BCM/a inthe Barents Sea in 2025. In both regions, the construc-tion of entirely new production and pipeline infrastruc-ture is necessary. Due to harsh climatic conditions,essential investments are needed in order to developthese provinces. As a consequence, Russian productioncosts (disregarding transportation costs to Europeanmarkets) will increase notably when these regions aredeveloped.Algeria, which traditionally exports substantial gas

volumes to Europe, is also able to raise its gas pro-duction considerably. Gas exports to Europe peak dur-ing the model periods 2015–2025. Like Russia andNorway, Algeria has to develop new gas provinces,especially the In Salah region (Sahara dessert). Invest-ments in new production and transport infrastructureare needed by 2010 and 2015, e.g. in pipelines from InSalah to Hassi R’Mel and further to southern Europe.Nevertheless, the increase of production costs of newgas sources (disregarding transportation) is lower inAlgeria (up to approximately US$ 0.90/MBTU) thanin Norway (up to US$ 1.20/MBTU) and Russia (up toUS$ 1.00/MBTU).Other African gas exporting countries will also

increase their gas deliveries to European markets.Libya will export larger quantities of gas to Europe viathe new built Libya–Italy pipeline (the so-called ‘greenstream’ pipeline). While the pipeline capacity fromLibya to Europe is expected to be expanded from 8BCM in 2005 to more than 25 BCM in 2030, no exten-sion of the liquefaction capacity at the Marsa el BregaLNG terminal will be realised. Gas from Egypt will be


delivered to Turkey by an extension of the planned

Egypt–Jordan pipeline by 2015. Additional Egyptian

exports will be transported to Europe by LNG pro-

duced in the Nile delta (up to 15 BCM/a). Nigeria will

export its gas exclusively by LNG to European mar-

kets, since the projected trans-Sahara pipeline is esti-

mated to be extremely costly, and, additionally, transit

fees would have to be paid to Algeria.In the model, Iran has a higher growth of gas

exports than all other gas producing countries. In year

2000, Iran was not at all a gas exporting country.

Nevertheless, according to the model results, it will be

one of the biggest gas suppliers to Europe in year 2030.

Due to large reservoir sizes, production costs are low in

Iran (about US$ 0.50/MBTU). Further more, some

existing pipelines can be used for exports, if additional

compressor capacity was installed, and pipeline costs

can in some cases be shared with other suppliers loca-

ted in this region, mainly Turkmenistan and Azerbaijan.

As a consequence, costs of Iranian gas are in some

cases lower than costs of Russian or Norwegian gas

(especially from new developments in remote areas)—

not only in southeast but also in western Europe.Gas from Iran is transported to the European mar-

kets by using both, LNG and pipelines facilities. In the

reference scenario, pipelines run from Iran to Turkey

and then further to Europe by using two different

routes: (a) to Greece and southern Italy and (b)

through Bulgaria across the Balkan to central and

western Europe. The Balkan route will start operation

by 2010 with an initial capacity of 6 BCM/a and later

extensions up to more than 70 BCM/a until 2030. The

Italy route does not come on stream before year 2030,

in the model.

Other gas producing countries of the Middle East,Qatar, Oman and the United Arabic Emirates, exportincreasing gas volumes to Europe, too, but to a minorextent. The gas is transported by LNG especially to theFrench, Greek and Italian market. Trinidad & Tobagowill also gain a share in the European gas market(especially in France, Portugal, Spain and the UK).Contrarily, from Venezuela, only minor gas volumeswill be delivered to Europe, at least until 2030.

4.2. Gas transport

In the model, three main gas flow directions of pipe-line transport can be distinguished:

. East–West: From the Yamal peninsula, westernSiberia, the Caspian region and Iran to easternEurope and then further to central and western Eur-ope.

. North–South: From the Norwegian, British andDutch gas fields located in the North Sea to westernEurope.

. South–North: From North Africa to southernEurope.

Fig. 3 provides a summary of the most importantexisting and potential pipeline routes and LNG flowsfrom production to consumption regions.Especially on the East–West transport route,

additional gas flows need substantial investments innew pipeline capacity, e.g. investments in the extensionof the Yamal–Europe pipeline via Belarus (period2010) or in the projected pipeline from the RussianBarents Sea to Germany and Sweden across Finland(period 2020). Additionally, the refurbishment of old

Table 5

Net exports of main supply countries (in BCM/a)

2
005 2 010 2 015 2020 2 025 2030
Algeria
80 106 1 23 122 1 22 98
Angola
0 0 0 0 0 9
Azerbaijan �
1 5 14 18 18 23
Caribbean
8 10 15 24 24 24
Denmark
6 4 2 0 �2 �7 Egypt 6 13 32 40 40 38
Iran
10 10 10 13 57 94
Iraq
0 0 0 6 11 12
Kazakhstan �
1 8 27 30 24 34
Libya
12 16 29 42 40 41
Middle East
2 10 18 25 34 40
Netherlands
30 27 21 19 �5 �32 Nigeria 14 20 20 20 27 30
Norway
75 85 95 108 1 17 123
Russia 1
96 203 1 88 217 2 45 293
Turkmenistan
32 60 55 71 80 71
UK �
1 � 25 � 17 �50 � 69 �94


pipeline infrastructure is in some cases necessary, e.g.

some of the pipelines built in the former Soviet Union

(pipelines from Turkmenistan to the Volga–Ural region

and some transit pipelines through the Ukraine). In

Table 6, the capacity extensions of some major pipeline

routes are summarised.14

European LNG trade will grow significantly, from

about 60 BCM/year in period 2005 to approximately

150 BCM/year in 2030. Therefore, substantial addi-

tions to liquefaction and regasification capacities are

needed. Table 7 provides a synopsis of the development

of the LNG regasification capacities in Europe. As is

to be expected, the UK will have its comeback as an

LNG importing country in model period 2005, almost

30 years after the decommissioning of Britain’s first

LNG regasification plant on Canvey Island. Belgium,

France and Italy will also increase their regasification

capacities significantly. Portugal joins the group of

LNG importing countries in period 2005, and

Germany follows in 2020.The extension of transport infrastructure calculated

by the model is, at least in the first time periods, lower

than the sum of all pipeline and LNG capacities cur-

rently planned and projected. Therefore, if all projects

14 For 2000 data see Perner (2002), EGM (2001), Cedigaz (2000),

Zhao (2000) and EU (2000).

currently discussed were realised, the European gasmarket could face the threat of gas oversupplies in thefirst decade of this century, at least in some regions ofEurope. Taking this potential supply/demand imbal-ance into account, it seems to be questionable if allprojected pipeline and LNG projects will be realisedaccording to the announced time schedules.

5. Investments and marginal costs

As mentioned above, large investments in both pro-duction and transport facilities have to be realised dur-ing the forecast horizon. As a consequence, long-termmarginal costs of gas supplies are estimated to increasefor all European demand regions. Though today’s pri-ces of imported gas are linked to oil prices on theEuropean continent, marginal gas supply costs areexpected to become an important factor for futureprice arrangements on the wholesale level in a moreand more competitive market.

5.1. Investment costs

Fig. 4 summarises the forecasted investments in pro-duction and transport capacities required in the modelperiods 2005–2030. Aggregated investments accountfor more than US$ 900 billion until 2030, of which

Fig. 3. Export routes to Europe.


more than 60% is dedicated to the production sector.15

Investments in gas distribution and storage are nottaken into account in the model.Investments in production facilities include replace-

ment of decommissioned infrastructure in developedareas as well as new projects. The sharpest increase inproduction investments has to be noticed in period2010, followed by a peak of approximately US$ 140billion in period 2015. The most important investmentdriver is the development of new gas provinces likeYamal and In Salah. Additionally, gas producers haveto switch to more costly fields in regions yet developed.For example smaller fields in western Siberia have tocompensate the declining production of super-giantfields. Larger capacity investments are also necessary inTurkmenistan and Kazakhstan. A second increase ininvestments in production facilities has to be expectedat the end of the forecast period (2025–2030) because

15 IEA estimates the required investments at about US$ 1500 bil-

lion between 2001 and 2030 for the considered regions. The share of

investments in production facilities is approximately 70%. The differ-

ence between EUGAS and IEA estimates can be explained by a

longer time period considered by IEA (2001–2030 instead of 2005–

2030). Further, IEA figures include some upstream investments,

which are dedicated to non-European markets (e.g. Russian invest-

ments for Sakhalin) (see IEA, 2003b).

huge capacity additions especially in Iran, the Russianand Norwegian Barents Sea and on the Yamal penin-sula are needed.According to the model results, investments in trans-

portation facilities are lower than those in productioncapacities, at least during the first years. Several rea-sons can be found for this outcome: at first, new builtproduction capacities can often be connected to exist-ing pipelines and LNG facilities. For example, mostRussian export pipelines carry currently almost exclus-ively western Siberian gas. Nevertheless, only minorinvestments are necessary in order to link these exporttrunk lines to gas reserves in Yamal, Turkmenistan andKazakhstan. The same applies for British pipelines,which can be used to transport Norwegian gas to theUK. Contrarily, using existing infrastructure is not anoption for Iran and the Barents Sea. Consequently,total investments in transportation capacities willincrease in the last forecast periods when these pro-duction regions become important for European gassupplies.Further, heavy investments in transportation infra-

structure have been made in the past, especially in themost recent years 1995–1999 (e.g. new LNG terminalsin Trinidad, Nigeria and the Middle East, Europipe IIand Norfra from Norway to Europe or Blue Streamand Yamal 1 from Russia). These investments are notincluded in the figures given above.

5.2. Long-term marginal costs

No physical shortage of natural gas will occur inEurope. Nevertheless, the impact of the required devel-opment of new gas sources on European supply costsand cross-border prices has to be taken into account.According to the model results, an increase in long-term marginal supply costs from US$ 2.60/MBTU in2005 to US$ 3.20/MBTU in 2030 can be expected inOECD Europe. This means that supply costs rise byapproximately 25% during this time period.

Table 6

Capacities of some major gas transport projects (in BCM/a)

2
000 2010 2 020 2030
Algeria–Spain (Maghreb-Europe, Medgaz) 1
2 25 4 3 43
Azerbaijan–Turkey
0 5 1 8 23
Egypt–Turkey (with branch to Cyprus)
0 4 2 8 28
Iran–Turkey
0 10 1 0 73
Kazahkstan–Russia
6 8 3 4 43
Libya–Italy
0 12 3 9 42
Norway–UK (Frigg, Marathon)
7 30 4 8 106
North Trans Gas (Barents Sea–Finland–Germany, Sweden via Baltic Sea)
0 0 7 97
Turkey–Bulgaria
0 6 2 0 64
Yamal–Europe (Poland–Germany) 1
6 38 3 8 43
Table 7

Development of regasification capacities (in BCM/a)

2
010 2020 2 030
Belgium
8 16 1 6
France 2
7 36 4 7
Germany
0 6 1 6
Greece
5 6 6
Italy
8 8 1 6
Portugal
3 3 3
Spain 1
5 15 2 6
Turkey 1
0 10 4
UK
4 20 3 2


Table 8 highlights the gas cost development for selec-

ted OECD member countries. The cost increases differ

significantly from country to country. Higher rises in

costs occur in countries

. which are net-exporters of gas in the first years andswitch to importing in later time periods (e.g. the

Netherlands, the UK) or,. which rely heavily on one low cost gas source in the

beginning and diversify their portfolio in the follow-

ing years by importing more costly gas from other

sources (e.g. Spain).

Marginal supply cost will have a significant impact

on European cross-border gas prices, if the current oil

price linkage of wholesale gas prices will be overridden

because of European market liberalisation and increas-

ing competition on the upstream (production) and mid-

stream (importation and long-distance transportation)

level. In this case, gas prices should reflect costs of sup-

plies. Because long-run marginal supply costs are

expected to rise slightly, cost reflective prices should

develop accordingly in the mid and long term. Never-

theless, since profit margins along the value chain ofthe gas business and probably transit fees can be expec-ted to shrink smoothly, price increases can be lowerthan cost increases during a certain period of time.The model results concerning the development of

supply costs are robust in respect of essential para-meter variations. For example, if European gasdemand is 20% higher than assumed, supply costs forOECD Europe will still not exceed US$ 3.20/MBTU inthe long run, but the timing of the realisation of someof the major gas projects is altered. The reason for themoderate cost effect is a relatively flat long run gas sup-ply curve for Europe during the considered time per-iod: The costs of a number of new major gas projectsare in a similar range at the margin.

6. Political implications

According to the model results, sufficient natural gasis physically available for the European market in theforeseeable future. Huge gas reserves are availableinside and outside Europe. If all major gas projectscurrently discussed are realised, even a temporary over-supply situation might occur in Europe, especially insome countries like Turkey, where current consump-tion remains broad behind the forecasted volumes, orin the UK, where a large number of new import pro-jects is announced.Nevertheless, very significant investments in new

production and transport infrastructure are required inthe coming years in order to bring the needed gasvolumes to European markets. Much private capitalhas to be attracted by the gas business in the comingyears in order to satisfy growing demand and securesupplies. It is a major political challenge to set an

Table 8

Long range marginal costs for some OECD countries (in US$/

MBTU)

2
010 2020 2 030
France 1
.71 2.18 2 .86
Germany 2
.53 2.81 3 .13
Italy 2
.16 2.66 3 .18
Netherlands 0
.24 1.37 2 .95
Poland 1
.41 2.50 2 .83
Spain 1
.32 2.33 2 .57
Turkey 2
.67 2.71 2 .64
UK 1
.54 2.18 2 .35
Fig. 4. Investments in billion dollars per five-year period.


adequate general framework for private investmentsinside Europe as well as in non-European gas export-ing countries without distorting the markets.Above all, the political framework of the gas busi-

ness has to be stable and long lasting because of thevery long economical and technical lifetimes of gasassets. Erratic political action and ad hoc decisions arenot suitable to acquire the required private capital forinvestments. The regulation and reorganisation of thetransportation, distribution and storage businesseshave to be structured in a cautious way in order to givesufficient incentives for investments. The second EUdirective on the electricity and gas market liberalisationof the internal European market adopted in June200316 incorporates some major provisions on therestructuring of the gas business (e.g. unbundling ofactivities), regulation (e.g. mandatory implementationof national regulatory authorities) and enhanced mar-ket eligibility of gas customers. Further, according tothe new directive, new major gas infrastructure projects(interconnecting pipelines, LNG facilities) can partiallybe exempted from third party access provisions inorder to attract investments. Obviously, the EU com-mission is prepared to accept lower short term gas-to-gas competition if necessary in order to enhance thelong-term security of gas supplies.17

According to the model, gas imports and transits areessential for future European supplies. It has to beassured that political considerations do not have nega-tive impacts on transit flows. International agreementsand cooperation like the Energy Charter Treaty canhelp to solve disputes between importing, exportingand transit countries.Further diversification of gas supplies should be part

of the future European gas import strategy. Forexample Finland, the Baltic States and some countriesin East and Central Europe buy their imported gastoday still exclusively from Russia. Spain and Portugaldepend heavily on supplies from Algeria, but bothmake great efforts to reduce this dependency. LNGseems to be the most reasonable and effective option toincrease supply diversification for these countries. Forlandlocked states, an extension of pipeline connectionsto neighbouring countries is an adequate strategy.State subsidies granted to selected gas projects (inter-

connecting pipelines, LNG facilities, etc.) should be theexemption and well justified even if the security ofenergy supply is enhanced. For example, in southernEurope, some new gas infrastructure projects were byapproximately 60% financed by the state and the EU.

16 See EU (2003).17 For the first time, the EU commission investigated security of

energy supply items in its Green Book published in year 2000 (see

EU, 2000).

If the economics of these projects prove to be very

poor, the improvements regarding security of supply

turn out to be very expensive for the public. Further,

the optimal allocation of capital is distorted especially

if subsidised gas projects compete with alternative non-

subsidised projects. For example, public subsidies for

the proposed Baltic Sea Pipeline from Russia to

Germany would indirectly diminish returns of existing

transit pipelines in eastern Europe as long as the new

pipeline is used as a bypass. Therefore, the subsidis-

ation of selected gas projects can increase the financial

risks of other projects and discourage private non-sub-

sidised investments in gas assets in the mid and long

term.

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Documents

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