2.4 the economics of natural gas - treccani...2.4.1 introduction over recent decades, natural gas...

2.4.1 Introduction

Over recent decades, natural gas consumption hasincreased in almost all parts of the world at asignificantly higher rate than the consumption ofprimary energy as a whole (Table 1). In the periodbetween 1974 and 2004, consumption grewworldwide by an annual average of 2.7%,compared to 1.9% for primary energy, with itsshare of total primary consumption increasingfrom 19% to 24%.

In some countries and world regions, however,the disparity between growth rates was far greater.The rapid growth which occurred in Africa andAsia, with average annual increases of nearly 10%

throughout the thirty-year period, is particularlystriking. However, this growth was paralleled bylarge increases in primary energy consumption as awhole in these regions. Natural gas consumptiongrew as rapidly in Japan and Oceania; but the morelimited increase in total primary consumption ledto a five-fold increase in the share of natural gasduring the period under consideration. Europe, too,was characterized by a rise in gas consumption fargreater than that of primary energy (2.9%compared to 0.7%), with gas almost doubling itsshare during this period. Russia and the otherformer Soviet countries represent a case apart;here, the 35% drop in total energy consumptionfollowing the collapse of the USSR was reflected

107VOLUME IV / HYDROCARBONS: ECONOMICS, POLICIES AND LEGISLATION

2.4

The economics of natural gas

* Excluding non-commercial primary energy.

Table 1. Contribution of natural gas to meeting primary energy needs in the world regionsbetween 1974 and 2004 (BP, 2005)

World regions

Average annual growth (%) Share of total primary consumption (%)

Naturalgas

Primaryenergy*

Ratio 1974 1984 1994 2004

United States and Canada 0.4 1.1 0.4 30.4 25.8 26.5 25.1

Japan and Oceania 7.1 1.5 4.6 2.8 10.5 12.8 13.8

Europe 2.9 0.7 4.0 12.5 16.0 18.6 23.8

Russia and other former Soviet countries 2.9 0.2 16.0 23.4 35.3 48.5 52.9

Asia 9.3 5.4 1.7 3.1 5.1 7.1 9.5

Middle East 8.3 5.4 1.5 18.8 22.9 32.9 41.9

Africa 9.9 4.1 2.4 3.9 13.1 16.0 19.8

Latin America 5.2 3.4 1.5 14.2 18.5 17.6 23.8

World 2.7 1.9 1.4 18.8 20.8 22.6 23.7

in a drop of only 15% in natural gas consumption.Moreover, after 1997 natural gas consumption inthis region recovered significantly faster than thatof other fuels, and gas now meets over 50% ofprimary energy needs.

Significant increases in the share of natural gasover the past three decades were recorded in allregions and practically all the countries in theworld with the exception of the United States andCanada; here levels of penetration were alreadyhigh (30%) at the beginning of the period underconsideration. This extraordinary growth can beattributed mainly to the ease and versatility of useof natural gas and to its greater environmentalcompatibility which have significantly favouredthis source over solid and liquid fossil fuels.Moreover, it was made possible by the rapidgrowth in proven natural gas reserves and theconstruction of adequate transport, storage anddistribution systems.

This chapter starts by examining the main usesof natural gas and the substitution processes whichhave led this fuel to dominate in many sectors andcountries over recent decades. In this context, someissues will be analysed in depth, such as themarkedly seasonal nature of consumption and thelimited sensitivity to prices which to some extentdifferentiate natural gas from its majorcompetitors. The chapter goes on to examine thesize of the resource base, to describe the naturalgas cycle and discuss major supply-side issues,which mainly concern the uneven geographicaldistribution and exploitation of the resources andthe relatively higher costs of transportation, storageand distribution. The chapter concludes with anexamination of international gas trade and adetailed analysis of the liquefied natural gasindustry, the most dynamic sector for futuresupplies.

2.4.2 The demand for natural gas

Worldwide, the consumption of natural gas isconcentrated in the end-use sectors, which accountedfor 50% of total consumption in 2002, the most recentyear for which homogeneous data on consumption bysector is available for all world regions.1 This wasfollowed by the power generation sector with just over32%, while the remaining 18% went to the otherenergy sector uses. Final consumption was sharedalmost equally between the residential, commercialand public sector and the industrial sector, with 52%and 48% respectively, while a mere 0.3% was used forpassenger and freight transport.

108 ENCYCLOPAEDIA OF HYDROCARBONS

BASIC ECONOMICS OF THE HYDROCARBONS INDUSTRY

1 The reference framework for statistics on the demand,supply and prices of natural gas (and other energy sources)is that of the IEA (International Energy Agency). Thesestatistics have been partially integrated with the datapublished annually by CEDIGAZ (Centre Internationald’Information sur le Gaz naturel et tous HydrocarburesGazeux, 1997-2004) and BP (British Petroleum, 2005) andwith the data available from the databases of the EIA(Energy Information Administration). The IEA data are fromofficial government sources; CEDIGAZ and BP data areprevalently of industrial origin. In practice, all these sourcesrefer to one another, and differences mainly result from theuse of different conventions. The same sources are also citedby the World Energy Council (2001).

2 The unit of measurement used for natural gas in thischapter is the cubic metre measured at 15°C and 760 mm ofHg with a higher calorific value of 9,150 kcal/m3. This valuerepresents the world average in recent years. Notoriously, theenergy content of natural gas varies significantly from fieldto field, with differences as great as 1-2% compared to theworld average. The energy content has also changed overtime; averaged out on a world level, the higher calorificvalue at consumption has increased from 9,008 kcal/m3 in1978 to 9,161 in 2001. It also varies significantly betweenproduction and consumption; for example, worldwide, thehigher calorific value at the wellhead in 2001 was 9,252kcal/m3.

Table 2. Worldwide consumption of natural gasin the major use sectors in 2002 (based on IEA data,

Natural gas information, 2004)

Use sectors Consumption (Gm3)

Electricity generation 854.8in power stations 542.2in cogeneration plants 312.6

Other energy sector uses 458.0production of hydrocarbons 234.0district heating 108.0pipeline transportation 67.5final distribution 26.0others 22.5

End-uses 1,321.7Industry and agriculture 628.5

chemical and petrochemical 261.7other heavy industry* 208.7light industry** 133.1other industrial activities*** 25.0

Civil uses 689.2commercial and services 184.8residential 504.4

Transportation 4.0

Total 2,634.5

* Includes ferrous and non-ferrous metals, non-metallic minerals,paper and cardboard. ** Includes food, textiles, the mechanical andvehicle industries, wood and furniture, etc. *** Includes agriculture,construction and mining.

End-use functions and substitutionprocesses

Overview of end-uses and penetration of finalconsumption

A more detailed examination of worldwideconsumption by sector (Table 2)2 highlights theimportance of cogeneration (combined generation ofelectricity and heat), which accounted for 37% of thegas consumed in the generation of electricity in 2002.Other energy sector uses were dominated by oil andgas production; this, together with consumption bycompressor stations for pipeline transport and finaldistribution of gas, accounted for over 70% ofconsumption in this sector.

Final consumption was dominated by the residentialsector with 38% of the total, reflecting the convenienceof natural gas for cooking and space heating, despitethe high costs of local distribution. In this context, it isworth noting the greater importance of gasconsumption in the chemical industry and other heavymanufacturing sectors compared to light industry,which is penalised by higher distribution costsassociated with the greater geographical distribution ofthe food, textile and mechanical products industries andtheir lower unit energy requirements.

An examination of the contribution made bynatural gas to meeting the energy needs of each sectoris provided in Table 3 with reference to the eight largeworld regions introduced in Table 1. The choice ofworld regions is based mainly on the availability oforganized statistical data, but nonetheless seemsappropriate for the purposes of the present analysis

since it identifies areas where the main substitutionfactors in energy supply and demand are relativelyhomogeneous.3 A more detailed breakdown for eachindividual country would certainly provide a moreaccurate and tangible view of the development ofnatural gas in different local contexts. However, giventhe multiplicity of different situations, the resultingpicture would be fragmentary and partial and wouldgreatly complicate this overview. The chosensubdivision is also well suited to the examination ofsupply and of the other components of the natural gassystem dealt with later in this chapter.

Table 3 shows a degree of penetration worldwideincreasing from a minimum of barely 0.2% for


THE ECONOMICS OF NATURAL GAS

3 For reasons of economic, energetic, historical andcultural homogeneity, the definition of world regions usedhere does not correspond fully to that of the IEA, which, inaddition to geographical contiguity or proximity, privilegesinstitutional, political and commercial affinities. Thesedifferences essentially concern South Korea, Mexico andTurkey, which in this chapter are incorporated into Asia,Latin America and the Middle East respectively. In the IEA’ssubdivision, by contrast, South Korea is included in theAsia-Pacific region alongside Japan, Australia and NewZealand; Mexico in North America, alongside the UnitedStates and Canada; Turkey in Europe. This analysis alsorequired the reclassification (where possible) of the Balticcountries, which in the original historical series of the IEAwere included in the former Soviet region, whereas in thischapter they are part of Europe. The other republics areincluded in the region of Russia and the other former Sovietcountries. Only the definition of Africa is identical to that ofthe IEA. In any case, the differences between the twoclassification systems are relatively small, and do not modifythe description of the characteristics of the natural gas sector.

Table 3. Share of natural gas in energy consumption in the major sectors and world regions in 2002(based on IEA data, Natural gas information, 2004)

World regions

Electricitygeneration andcogeneration

(%)

Other energysector uses

(%)

End-uses (%)Total

(%)Industryand agriculture

Transportationof peopleand goods

Civil andother uses

Total



Europe 12.3 31.3 36.7 0.1 51.1 28.0 21.4

Russia and other formerSoviet countries

40.1 62.8 52.2 0.2 70.6 49.3 48.1

Asia 9.0 12.8 10.0 0.1 3.5 5.2 7.2

Middle East 46.0 68.4 37.6 0.0 42.2 28.0 37.6

Africa 23.7 17.5 17.8 0.0 2.9 5.3 10.6

Latin America 14.7 48.9 25.2 1.4 12.7 13.1 17.5

World 17.3 37.5 27.4 0.2 28.8 19.5 20.3

passenger and freight transport to 17% for electricitygeneration,4 27% in industry and 29% in residential,commercial and public sector, reaching a maximumof 38% in the other energy sector uses. The datareported show that the degree of penetration indifferent sectors varies significantly from region toregion, at times by more than an order of magnitudecompared to the world average. This significantvariability can be traced to differences infundamental factors related to: a) the level ofeconomic, demographic and urban development; b) the availability and exploitation of oil and gasresources; c) the relative convenience of alternativeenergy sources; d ) the existence of gas transport anddistribution networks; e) climatic conditions;f ) energy and environmental policies.

It is not surprising, for example, that penetration ishigh in all sectors in relatively developed regions, withample reserves and net exporters of natural gas(Russia and the other former Soviet countries, MiddleEast). A high degree of penetration of natural gas isalso found in net importing regions with relativelyscarce or decreasing resources but enjoying high levelsof economic and urban development and with decadesold transport and distribution systems (United Statesand Canada, Europe). In these regions, however,penetration in the power generation sector is lower dueto competition from other sources, notably coal andnuclear power.

By contrast, the share of gas is fairly low, even inthe residential, commercial and public sector and inindustry, in regions characterized by strongeconomic and urban development but high supplycosts (Japan and Oceania, represented on thedemand side mainly by Japan). Penetration isparticularly low in regions with lower orintermediate levels of economic developmentlacking logistic transport and distribution systems,especially when they do not possess ample naturalgas resources (Asia). Even in regions withsubstantial resources, the share of natural gas maybe relatively low due to insufficiently developedtransport and distribution infrastructures, as well asto competition from other primary sources such ascoal and hydropower (Africa and Latin America).

Historical trendsThe distribution of natural gas among end-use

sectors has changed considerably over the course ofrecent decades, as shown in Table 4. Worldwide, thesignificant increase in the share of electricitygeneration is reflected in a decrease in the share ofindustrial end-uses, while the residential, commercialand public sector and other energy sector uses havemaintained an almost constant share. At the beginning

of the period, industrial uses accounted for 35% oftotal gas consumption, compared to 22% for electricitygeneration, 27% for the residential, commercial andpublic sector and 16% for other energy sector uses. By2002, these shares had essentially been reversed, withelectricity generation accounting for 36%, buildingsfor 26% and industry for 23%.

However, the global pattern compensates andmasks fairly divergent patterns in individualgeographical regions, largely reflecting developmentsin the major consuming areas: the United States andCanada, Europe, Russia and other former Sovietcountries, which together accounted for 94% of worldgas consumption in 1971 and for 74% in 2002.

Nevertheless, the historical decline in the share ofindustrial uses and the strong increase in electricitygeneration is common, to a greater or lesser extent, toall eight regions except Africa. The obviousexplanation is the high cost of power generation fromnatural gas compared to oil until the early 1970s; towhich should be added the political decision in manycountries, particularly in Europe, to save the lesspolluting gas (compared to oil and coal), for more‘noble’ purposes in industry, such as chemicalfeedstock and the residential and commercial sectors.The use of gas took priority in the industrial sector,given the greater geographical concentration ofconsumption and the consequent lower cost of supply.Large industrial plants could usually be reached withrelatively short connections to regional and nationaltransport networks,5 whereas supply to the residentialand commercial sector required the construction ofextensive distribution networks under towns andsuburbs.

By contrast, the pattern of consumption in theresidential, commercial and public sector variesmarkedly with the region. This sector’s share of totalnatural gas consumption has remained essentiallyunchanged, albeit with minor oscillations, in the UnitedStates and Canada, and Latin America, and has fallenonly slightly in Japan and Oceania. In other regions ithas risen more or less sharply, especially in the less



4 As far as generation from thermonuclear,hydroelectric, geothermal and other non-combustiblerenewable sources (unless otherwise specified) is concerned,the convention which attributes to these a performanceidentical to the mean of the thermoelectric generationreplaced is adopted. As such, the data reported on electricitygeneration from non-fossil fuels differ significantly fromthose supplied by IEA statistics, which assume aperformance of 100% for hydroelectric power, 33% fornuclear energy, 10% for geothermal energy; in calorie terms860, 2,600 and 8,600 kcal/kWh respectively.

5 In many countries, the early transport networks wereusually planned to supply large concentrations of demand inthe industrial sector.



Table 4. Distribution of worldwide natural gas consumption by use sector during the period 1971-2002(based on IEA data, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

World regions and yearsTotal

consumption(Gm3)

Distribution among uses (%)

Electricitygeneration andcogeneration

Other energysector uses

Industryand

agriculture

Civiland other

usesTotal

United States and Canada1971 666 17.4 16.7 32.1 33.8 100.01981 615 17.0 13.7 33.5 35.7 100.01991 625 20.1 16.4 26.6 37.0 100.02002 741 25.4 12.8 27.1 34.7 100.0

Japan and Oceania1971 6 31.3 0.6 47.4 20.7 100.01981 39 59.7 2.9 20.4 17.1 100.01991 78 61.3 3.6 18.0 17.1 100.02002 115 58.9 3.9 20.0 17.2 100.0

Europe1971 147 19.2 10.1 43.0 27.7 100.01981 314 15.0 11.3 39.5 34.1 100.01991 399 16.6 16.8 30.5 36.0 100.02002 526 25.1 11.0 27.0 37.0 100.0

Russia and other former Soviet countries1971 233 36.5 16.5 36.2 10.8 100.01981 402 36.7 13.3 36.4 13.7 100.01991 709 52.4 7.9 26.2 13.5 100.02002 586 52.8 12.0 13.8 21.4 100.0

Asia1971 10 18.9 32.1 44.7 4.3 100.01981 31 13.9 29.9 49.0 7.2 100.01991 98 28.3 29.9 33.5 8.4 100.02002 239 41.2 19.4 27.1 12.3 100.0

Middle East1971 21 6.3 25.5 61.1 7.1 100.01981 41 38.9 23.4 29.8 7.9 100.01991 114 28.2 32.9 24.7 14.2 100.02002 233 36.4 19.1 22.6 22.0 100.0

Africa1971 3 15.5 66.1 15.0 3.4 100.01981 18 33.2 43.8 20.2 2.8 100.01991 43 31.1 43.2 21.4 4.3 100.02002 73 45.8 22.9 19.6 11.7 100.0

Latin America1971 28 25.5 24.9 41.0 8.6 100.01981 64 20.5 23.3 49.6 6.6 100.01991 91 24.2 25.6 41.4 8.8 100.02002 151 29.9 32.2 29.1 8.8 100.0

World1971 1,114 21.7 16.3 35.3 26.6 100.01981 1,524 23.7 14.2 35.9 26.1 100.01991 2,157 32.7 15.6 27.6 24.0 100.02002 2,664 36.0 14.4 23.4 26.2 100.0

developed Africa, Asia and the Middle East where,starting from extremely low values, it has practicallytripled in the last thirty years. However, only in theUnited States and Canada, and in Europe, is the degreeof penetration greater than 35%, while in the otherregions it has remained in the 10 and 20% bracket.

Other energy uses show stability or decline inalmost all regions, due to the decreasing importance ofoil and gas production and transport compared to otheruses. The high share of gas consumed in this sector inAfrica in 1971 (66%) reflects the production ofAlgerian and Libyan gas almost exclusively for exportduring this early period. On the other hand, adecidedly upward trend is seen for Japan and Oceania,and for Latin America, linked to the development ofnatural gas resources in Australia, Argentina, Bolivia,Mexico and more recently in Trinidad and Tobago.

Factors of substitutionOver recent decades, natural gas has found ample

room for new applications, especially in regions withless developed economies, driven in part by theincrease in energy requirements and constraints on thepotential of traditional sources (oil and coal).

The faster growth of gas compared to mostalternative sources of energy has led to a significantand often vigorous penetration which can beinterpreted as form of substitution for other sources.The following overview of the historical dynamics ofnatural gas penetration in the different world regionsin the major end-use sectors (electricity generation,industry and buildings)6 is useful for a betterunderstanding of the factors of substitution favouringthe growth of this source over most others.

Penetration in industrial usesHistorically, industry was the sector in which

natural gas first gained importance in practically allcountries of the world. It is in large plants consuminggreat amounts of energy located in areas close toproduction fields that natural gas is most convenient; apipeline extension is quite suitable without any needfor an extensive distribution network. As shown inTable 5, by the early 1980s natural gas already metover 20% of industrial final consumption in all themost industrialized regions, except Japan and Oceania,and in two of the four less developed regions (MiddleEast and Latin America).

Before the development of large internationaltransport systems, conditions favouring thedevelopment of natural gas, differed considerablywithin the large regions into which the world has beendivided for the purposes of this analysis. In Europe inthe early 1980s, natural gas accounted for 40% of finalindustrial consumption in the Netherlands and 25% in

Italy, but less than 10% in Switzerland and Sweden.Similarly, the relatively high penetration of natural gasin the industrial sector in Latin America mainlyreflects the availability of this resource in Argentina,Mexico and Venezuela.

Asia, with the exception of Indonesia and a fewother South-East Asian countries, does not possesslarge natural gas resources, and the substitution of coaland oil is a much more recent phenomenon. A similarsituation exists in Japan and Oceania, a region withsignificant gas resources only in Australia butdominated by the energy requirements of Japan, acountry which was accessible by sea usingtechnologies which had only recently been developedin the early 1980s.7 The African continent comprisescountries (Algeria and Nigeria) with large natural gasresources, others (South Africa and Zimbabwe) withhuge coal deposits, and yet others which, lackingsignificant resources, utilise local biomass fuels insmall and medium-sized factories, and oil products inlarger plants.

The enormous convenience of natural gas in theindustrial sector, even in countries without significantresources or distant from the world’s largest fields, isevident from the significant degree of penetrationwitnessed in Japan and Oceania and in Asia from 1980onwards. By contrast, the strong increase in Africamainly reflects the process of industrialization,especially in some North African countries and inNigeria. Following the oil crises of the 1970s and theincreasing sensitivity to the environment, almost allEuropean countries have adopted energy policiesencouraging the development of natural gas for mostuses.

However, in a number of regions and in somecountries natural gas consumption in industry hasundergone some back substitution in the 1980s infavour of competing energy sources. In the MiddleEast, in the absence of suitable transport anddistribution infrastructure, natural gas has notmanaged to keep pace with the high growth in energyrequirements over the past decade and has lost ground



6 Consumption of natural gas in the other energy usessector is correlated mainly with the production of oil andgas, and is not significantly affected by substitution withother sources; as such, it is not considered in this context.Similarly, there is no detailed examination of the uses ofnatural gas in passenger and freight transport, since this isnegligible almost everywhere, and depends entirely on thesupport policies adopted by individual countries whileawaiting technological advances, e.g. in the field of fuelcells.

7 The transportation of liquefied natural gas began in1964 and accounted for 15% of international gas trade in1980.

to oil products. The reduction in the United States andCanada which occured in the 1970s and 1980s reflectsthe decline of the natural gas industry in the UnitedStates until reforms in this sector took effect in theearly 1990s.8

The decline seen in Russia and other former Sovietcountries is more difficult to interpret, given thedisruptions accompanying the collapse of the Sovieteconomy. The decrease in the share of natural gas inthe industrial sector was accompanied by a recovery in

the share of coal (almost unique in the world) and asignificant growth in renewable sources, which in thisregion almost exclusively consist of the heat producedin cogeneration and district heating plants. The overalleffect of this decline is that, worldwide, natural gas usein industry has appeared to lose ground to oil productsover the past decade and especially to electricity,



8 Deregulation of production during the 1980s and oftransport and distribution between 1985 and 1992.

Table 5. Penetration of natural gas in industrial end-uses between 1980 and 2002(based on IEA data, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)


consumption(Mtoe)

Distribution among sources (%)

Coal andderivatives

Oilproducts

Naturalgas

Renewables Electricity Total

United States and Canada1980 500 10.5 29.9 34.1 10.3 15.2 100.01990 437 10.9 23.5 32.9 12.3 20.4 100.02002 432 6.4 25.1 36.3 9.7 22.4 100.0

Japan and Oceania1980 132 17.9 48.8 5.2 4.2 24.0 100.01990 148 16.2 45.2 8.0 4.4 26.1 100.02002 164 15.1 41.5 12.2 3.6 27.6 100.0

Europe1980 476 17.7 34.2 23.2 8.2 16.8 100.01990 422 17.6 26.1 26.4 8.0 21.9 100.02002 392 9.2 28.4 29.8 7.0 25.6 100.0

Russia and other former Soviet countries1980 446 13.5 19.4 28.8 25.9 12.5 100.01990 455 8.6 15.9 39.4 21.2 15.0 100.02002 212 11.9 10.8 31.4 28.2 17.7 100.0

Asia1980 292 58.3 21.3 4.6 5.7 10.0 100.01990 453 54.6 19.9 6.3 6.9 12.2 100.02002 647 36.2 26.9 8.4 9.5 19.0 100.0

Middle East1980 42 7.9 61.5 23.7 0.3 6.6 100.01990 63 7.7 44.7 38.6 0.4 8.6 100.02002 117 6.8 46.2 37.1 0.3 9.7 100.0

Africa1980 62 27.0 20.3 4.8 34.2 13.6 100.01990 76 21.3 18.8 10.8 33.5 15.6 100.02002 82 17.7 18.2 15.4 28.7 20.1 100.0

Latin America1980 116 5.1 34.3 20.7 28.1 11.8 100.01990 149 5.6 28.4 20.8 30.6 14.7 100.02002 167 6.1 29.8 21.8 22.0 20.2 100.0

World1980 2,066 20.2 29.2 22.6 13.6 14.4 100.01990 2,203 21.0 23.9 24.4 13.3 17.4 100.02002 2,213 17.2 27.3 22.9 11.6 21.0 100.0

whose penetration in industrial sector uses is in anycase considerably more vigorous than that of naturalgas, albeit at lower levels.

Penetration in the residential, commercial andpublic sector uses

Natural gas use in the residential, commercialand public sector developed with a significant delaycompared to the industrial sector, mainly due to thehigh costs and protracted development of

distribution networks required to send gas from theproduction fields and long distance transportnetworks to end-users (houses, shops, publicbuildings, etc.). In fact, only in the United States andCanada did the share of natural gas in theresidential, commercial and public sector exceed20% in 1980 (Table 6). Europe, Russia and the otherformer Soviet countries exceeded this share in theearly 1980s, while the high penetration of gas (above40%) attained in the United States and Canada was



Table 6. Penetration of natural gas in residential, commercial and public end-uses between 1980 and 2002(based on IEA data, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)


consumption(Mtoe)


Coal andderivatives

Oilproducts

Naturalgas

Renewables Electricity Total

United States and Canada1980 433 1.9 23.5 43.3 2.6 28.8 100.01990 450 2.1 16.4 40.9 2.0 38.6 100.02002 515 0.5 12.0 40.9 1.5 45.1 100.0


Europe1980 453 15.5 38.3 19.9 9.4 17.0 100.01990 461 11.0 25.3 26.0 14.4 23.3 100.02002 480 2.7 22.4 33.4 13.4 28.0 100.0


Asia1980 579 16.1 6.7 0.3 74.5 2.4 100.01990 742 18.6 8.5 0.9 67.1 4.9 100.02002 866 8.8 14.2 3.1 62.4 11.5 100.0

Middle East1980 31 5.9 55.9 9.2 12.0 17.0 100.01990 79 3.8 52.3 17.0 8.2 18.7 100.02002 133 1.0 36.2 31.7 6.3 24.8 100.0

Africa1980 146 1.9 7.8 0.3 86.6 3.4 100.01990 196 1.5 8.1 0.7 84.6 5.1 100.02002 260 1.1 9.8 2.7 80.4 6.0 100.0

Latin America1980 91 0.2 33.9 4.2 48.4 13.3 100.01990 101 0.2 34.6 7.1 37.1 21.0 100.02002 122 0.1 32.8 9.1 29.8 28.3 100.0

World 1980 2,070 11.8 23.4 16.8 34.5 13.5 100.01990 2,468 10.5 18.8 17.7 35.3 17.6 100.02002 2,791 3.8 17.7 20.8 34.8 22.9 100.0

destined to fall in later years, under pressure fromthe faster growing electricity.

With the exception of this region, where naturalgas uses in the residential, commercial and publicsector seem close to saturation, consumption of thisfuel has grown at an impressive rate at the expense ofall other sources, with the exception of electricity. TheMiddle East, where the share of gas has risen from10% to 30% in only two decades, is a striking case.However, even the other less developed regions in theworld (Africa, Latin America and Asia) promise anextremely high rate of penetration as urbandistribution networks are developed.

In the more developed regions, ongoingpenetration trends are reflected in the decline in theuse of oil products, the main competing sources in theresidential, commercial and public sector, and arematched only by the faster growth of electricity. In theless developed regions of Asia, Africa and LatinAmerica, the main declining fuel in the residential,commercial and public sector is biomass, since oilproducts retain an important edge over natural gasoutside urban areas not yet reached by distributionnetworks. In these areas of the world, gas consumptionin the buildings sector is more strongly correlated withthe typically high population growth and urbanmigration, since gas distribution networks are builtmainly in capital cities and larger towns, whereas linksto smaller towns are developed much more graduallyunless they happen to be close to transport lines.

The Japan and Oceania region is an unusual case;here the degree of penetration of natural gas in theresidential, commercial and public sector has remainedstable at around 12% over the past two decades. In thisregion, the high costs of natural gas supply in Japan,which dominates consumption in this region, hasreduced its convenience compared to alternative oilproducts, and utilisation in the residential, commercialand public sector are concentrated almost exclusivelyin the vicinity of gas-fired power stations, in turnlocated close to regasification terminals.

In the United States and Canada, Japan andOceania and in Europe, consumption in buildings areconcentrated in the residential sector (70%, 69% and83% respectively). The data available for other worldregions show a higher concentration (on average about40-50%) in the commercial and public sectors, due tothe warmer climate and reduced space heating needs(in most of Asia, the Middle East, Africa and in manycountries of Latin America) or to the widespread useof district heating (Russia and the other former Sovietcountries). In these countries, residential sectorconsumption is concentrated in cooking uses, usuallytoo low to justify the construction of extensivedistribution networks.

Penetration in electricity generation Electricity generation is the sector with the highest

rate of natural gas penetration over the past twodecades (Table 7). Worldwide, its share in terms ofprimary energy input to power generation has risenfrom less than 12% to over 17%. Although thisphenomenon is universal, the degree and dynamics ofpenetration vary considerably between countries,depending on the relative convenience of alternativeresources and the energy policies adopted.

Historically, strong recourse to natural gas forelectricity generation is found only in the Middle Eastand in Russia and the other former Soviet countries,the regions which have the largest resources of thisfuel. In Russia and most other former Soviet countries,natural gas has rapidly replaced oil and even coal, andnow dominates the electricity generation sector with40% of total inputs. In the Middle East, natural gasovertook oil in the mid-1990s, and would probablyhave reached 60% of total input today were it not forthe contribution of coal towards electricity generationin Turkey and Israel.9

At the beginning of the 1980s, aside from thesetwo regions, only the United States and Canada andJapan and Oceania had a the share of natural gasgreater than 10%. In the United States, gas-firedgeneration was important only in those states withsignificant reserves compared to coal (Texas,Louisiana, etc.); the decline in share during the 1980sreflected the drop in gas production, which lasted untilreforms in the sector. Since the second half of the1970s, Japan has adopted a diversification policyaimed at excluding oil to the benefit of all othersources, including coal. Electricity generation in Japanand Oceania, as a whole, nevertheless continues to bedominated by this source due to the contribution ofAustralia, where coal accounts for almost 80% of totalinput to electricity generation; the share of natural gasis similar to that of nuclear energy (produced only inJapan).

In Africa gas utilisation in power generation isinfluenced by the markedly different endowment ofgas and coal resources in the northern and southernparts of the continent. The relative robustness ofcoal reflects the importance of the South Africaneconomy in the African region as a whole, while thevigorous penetration of natural gas reflects thestrong growth of the North African, Nigerian and afew other economies. In this region, oil-firedgeneration continues to be important (at least in theshort term) due to its greater convenience comparedto power transmission to small and widely scattered



9 In the case of Israel, due to political circumstancesrather than to economic convenience.

towns in rural areas. Similar conditions prevail inAsia, with some countries richly endowed with coalresources (China and India) and others with oil andgas (Indonesia, Malaysia, Thailand). Aside fromJapan and Oceania, this is the only regioncharacterized by an increasing share of coal-basedgeneration, which now accounts for over 60% oftotal input. By contrast, despite its rapid penetration,natural gas currently accounts for less than 10% ofthe total.

Trends in Europe reflect the impact of energypolicy choices in individual countries more thaneconomic convenience. In this context, the role playedby nuclear power is all important; during the twodecades under consideration, this resource tripled itsshare of primary input into generation. Substitution bythis fuel has taken place not only at the expense of oil,which was in any case of minor importance by 1980,but also of coal and has certainly slowed the growth ofnatural gas, which had the next to lowest share with



Table 7. Penetration of natural gas in electricity generation between 1980 and 2002(based on IEA data, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)


consumption(Gm3)


Coal OilNatural

gasNuclear Renewables Total

United States and Canada1980 656 46.8 9.7 13.3 11.0 19.2 100.01990 879 46.4 3.5 10.4 18.9 20.8 100.02002 1,177 44.5 3.0 14.0 19.7 18.8 100.0


Europe1980 585 44.2 15.6 6.2 10.4 23.5 100.01990 760 35.7 7.6 7.0 26.9 22.8 100.02002 828 29.4 4.9 12.3 29.0 24.5 100.0


Asia1980 205 46.1 25.4 1.5 2.3 24.8 100.01990 410 55.3 11.7 4.5 6.6 21.9 100.02002 878 61.9 6.0 9.0 6.6 16.5 100.0

Middle East1980 26 0.0 61.6 28.2 0.0 10.2 100.01990 53 4.5 47.8 41.4 0.0 6.3 100.02002 152 11.2 36.9 46.0 0.0 6.0 100.0

Africa1980 52 51.8 14.5 7.8 0.0 25.8 100.01990 77 51.1 14.6 14.5 2.7 17.2 100.02002 117 44.8 10.4 23.7 2.5 18.6 100.0

Latin America1980 114 2.1 25.0 9.2 0.7 63.1 100.01990 170 3.4 17.2 9.9 2.1 67.4 100.02002 255 4.5 16.1 14.7 3.0 61.7 100.0

World1980 2,224 38.6 19.2 11.8 8.2 22.2 100.01990 3,154 36.5 10.1 15.2 16.4 21.8 100.02002 4,132 38.5 6.8 17.3 16.5 21.0 100.0

barely 12% of the total in 2002. In this context, it isworth remembering the position of the EuropeanCommission, which in the late 1980s was stilldiscouraging the use of natural gas for electricitygeneration, in favour of the buildings sector andindustrial uses.

Latin America is the only region where electricitygeneration is dominated by renewable energy(essentially hydropower). The lack of gastransportation infrastructure has restricted the use ofthis source for electricity generation in those countrieswhich possess the largest resources (Argentina,Bolivia and Venezuela), while hydropower iswell-distributed throughout the region. It is alsosignificant that Colombia, a coal-exporting country,generates most of its electricity from natural gas andnot from coal. Like other less developed regions, theuse of oil for electricity generation continues to beimportant since it allows for the reaching of rural areaswith small-scale plants without building largeelectricity transmission networks.

The seasonality of consumption

Energy demand is by its very nature seasonal. Itvaries with the season and month of the year as afunction of climatic, economic and social factorsprevailing in each country. Different forms of energyare often characterised by an even greater degree ofseasonality, depending on the availability of resourcesand the technical constraints affecting their productionand transport.10 Natural gas stands out from otherfossil fuels due to the more marked seasonal variationof demand, related to the particular combination ofend-uses, and the higher cost of managing seasonalitycompared to alternative sources such as oil derivatives.As these two aspects are inseparable, they will be dealtwith together.

Seasonality and sectoral requirementsThe seasonal pattern of natural gas consumption

varies markedly from country to country as a functionof sectoral uses, especially the production of heat forspace heating, power generation and oil and gasproduction. It also varies over time depending on thedifferent sectoral growth in consumption. In thefollowing analysis seasonality is examined withreference to the excursion in consumption, defined asthe ratio of maximum to minimum monthlyconsumption observed over the course of a period oftime. Consumption patterns in the intervening monthsmay be important for the technical management ofsupply; however, this is not the subject of thischapter.11 Table 8 compares the average excursionduring the period 2001-04 for all the countries

belonging to the IEA,12 in decreasing order, togetherwith the sectoral distribution of gas consumptionduring the period 2001-02, the last years for whichdata are uniformly available.

The excursion tends to increase in proportion tothe share of consumption in the residential,commercial and public sector and district heating,which is in any case linked mainly to the space heatingneeds of buildings. Indeed, the only difference is thatspace heating in buildings entails combustion inindividual boilers installed on end-user premises,while district heating employs large centralized plantswith distribution of the heat produced, sometimes withthe cogeneration of electricity. Consumption forindustrial uses also contributes to the excursion,especially when this is concentrated in light industry(mechanical, textile, food industries) where spaceheating in working areas often accounts for a verysignificant portion of final consumption.

By contrast, consumption for power generation andenergy sector uses (mainly the production andtransport of oil and gas) are generally more evenlydistributed over the course of the year and tend toflatten the seasonal consumption cycle. The variationis also reduced by the consumption of gas in heavyindustry, where requirements largely reflect processuses, which tend to be relatively stable over the courseof the year. The table shows the breakdown of OECD(Organization for Economic Cooperation andDevelopment) countries into three classes ofseasonality in relation to the distribution of gasconsumption among major sectors,13 distinguishing



10 Hydropower and other renewable sources areemblematic in that their availability depends on climaticconditions. In some sectors, particularly electricitygeneration, the changing availability of renewable sourcesduring the year can determine a significant seasonal patternin the use of fossil fuels and other non-renewable resources.

11 For example, the management of storage facilitiesmay be critical if cold winter weather lasts longer thanexpected.

12 With the exception of the Republic of Slovakia, forwhich IEA data are available only from the second half of2004. Organized monthly consumption data are not availablefor countries outside the IEA. However, the patterns areconsistently replicated except in countries with weakclimatic changes, where gas consumption is relatively stableover the course of the year.

13 The only exception is Norway (not reported in Table8), which has an average variation of 8.5 but a share ofseasonal consumption of only 0.4%. This country’s naturalgas consumption is concentrated in the production of oil andgas (86%) and almost all its natural gas production (99%,excluding consumption for production) is exported. Thehigh average variation is linked to the production regime,which tends to closely track the requirements of importingcountries, characterised by generally high seasonality.



* Mean value of the ratio of maximum to minimum monthly consumption observed during the years 2001-04. ** Referring to consumption in the energy, electricity generation and heavy industry sectors. *** Referring to consumption in the district heating, light industry and civilsectors. **** In the case of cogeneration plants, gas consumption has been shared between electricity generation and district heatingproportionally to the production of electricity and heat.

Table 8. Seasonality as a function of sectoral consumption in OECD countries during the years 2001-04(based on IEA data, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

CountriesAverage

variation*

Share (%) Share of gas consumption by sector (%)

Stableconsumption**

Seasonalconsumption***

Energysector

Electricitygeneration****

Districtheating****

Heavyindustry

Lightindustry

Civiluses

Total

Countries with marked seasonality

France 4.9 28.6 71.4 1.0 2.0 5.9 25.6 13.8 51.6 100.0

Czech Republic 4.8 27.0 73.0 1.4 2.1 16.3 23.5 9.5 47.2 100.0

Switzerland 4.3 23.7 76.3 0.0 1.8 5.9 22.0 8.8 61.6 100.0

Sweden 4.2 29.1 70.9 0.2 0.4 37.3 28.6 15.1 18.4 100.0

Hungary 4.1 25.5 74.5 1.8 13.4 15.0 10.3 7.3 52.2 100.0

Countries with intermediate seasonality

Germany 3.2 38.3 61.7 1.5 15.2 5.0 21.7 7.4 49.3 100.0

Austria 3.2 48.6 51.4 7.7 17.0 16.8 23.8 5.4 29.3 100.0

Denmark 2.9 36.1 63.9 13.1 16.6 33.4 6.5 10.6 19.9 100.0

South Korea 2.8 35.9 64.1 0.0 25.5 10.8 10.4 6.6 46.7 100.0

Italy 2.7 41.9 58.1 0.5 21.7 10.1 19.7 10.9 37.1 100.0

Netherlands 2.4 31.7 68.3 4.1 20.6 10.9 6.9 14.3 43.1 100.0

Luxembourg 2.4 37.4 62.6 0.0 19.4 4.7 18.0 30.5 27.5 100.0

United Kingdom 2.3 46.3 53.7 8.3 26.7 4.2 11.4 5.6 43.9 100.0

Poland 2.3 41.6 58.4 8.5 0.8 7.5 32.3 6.0 45.0 100.0

Finland 2.3 44.8 55.2 6.9 14.6 50.6 23.3 2.7 1.9 100.0

Belgium 2.2 49.3 50.7 0.4 13.2 9.4 35.7 2.7 38.6 100.0

Countries with weak seasonality

Canada 1.9 50.4 49.6 20.2 10.0 1.4 20.2 11.5 36.8 100.0

Greece 1.8 92.3 7.7 1.8 74.4 1.2 16.1 5.2 1.3 100.0

United States 1.8 51.3 48.7 8.5 21.8 6.2 21.0 6.5 35.9 100.0

Turkey 1.7 62.2 37.8 0.5 51.4 13.9 10.3 2.1 21.8 100.0

Australia 1.6 73.4 26.6 15.1 24.9 3.4 33.4 4.6 18.5 100.0

Portugal 1.6 73.1 26.9 0.0 46.8 8.0 26.4 9.5 9.4 100.0

Spain 1.6 55.5 44.5 0.1 10.5 10.2 45.0 16.0 18.3 100.0

Ireland 1.5 71.1 28.9 0.0 53.0 1.8 18.2 5.3 21.8 100.0

New Zealand 1.4 81.5 18.5 2.5 40.1 1.7 38.9 9.0 7.8 100.0

Japan 1.3 75.9 24.1 0.5 66.8 0.3 8.7 5.0 18.7 100.0

Mexico 1.2 95.6 4.4 35.5 39.1 0.0 21.0 2.2 2.2 100.0

between countries where the share of consumptionlinked to space heating (buildings, district heating andlight industry) is indicatively: over 70% withexcursion greater than 4; between 50 and 70% withexcursion between 2 and 4; less than 50% withexcursion lower than 2.

Fig. 1 aggregates the data for all the countriesfalling into the three categories. Overall, countrieswith marked seasonal excursion show a 6-fold increasefrom minimum to maximum monthly consumption,countries with intermediate excursion a 3-fold increaseand countries with weak excursion an increase of justover 30%. The figure also shows the significantlygreater importance at world level of countries withweak and intermediate excursion compared to thosewith marked excursion: the average annualconsumption of the country groupings during theperiod 2001-04 was 74, 339 and 898 billion m3

respectively.

Managing seasonalityOnly in the case of electricity are storage costs (in

batteries, pumping plants, etc.) so high that productionat any given moment in time is almost identical todemand. For other energy sources, these costs tend tobe far lower, and production may precede consumptionby several weeks or even months. The discrepanciesbetween production and consumption are managed byappropriately exploiting the various buffers14 in the

production cycle (intermediate processes and storage)which effectively regulate flows from production tofinal consumption. In the case of oil, these are:pipeline or oil tanker transport, crude oil storagefacilities at ports, railway stations and refineries, therefining process itself and product storage facilitiesboth at the refinery and at land and sea transport hubsand finally storage located at end-user premises.

For both oil and natural gas, geology and theporosity of geological strata limit the potential foradapting production profiles to demand to cases whereproduction can be distributed over numerousreservoirs; moreover, the production of associated gasis often determined by that of oil, unless reinjection isadopted, which entails increased costs, or the excessgas is flared into the atmosphere, leading to pollutionand a waste of resources. After extraction from thereservoir, natural gas does not require refining, butonly purification and drying, continuous processeswhich do not interrupt the flow of gas.

Transport and local distribution phases also do notallow significant flexibility, since there are no genuinebuffers. It is not usually economic to sizetransportation infrastructure downstream of productionon the basis of the peak capacities required for only a



natu

ral g

as c

onsu

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3 )

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14

countries withmarked excursion

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-03

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nuar

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-02

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ary-

03

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-03

Janu

ary-

04

July

-04

0

20

60

40

80

100

120

Fig. 1. Monthly consumption trends of natural gas in OECD countries grouped according to seasonal variation (2001-04).

14 Buffers are devices allowing decoupling ofconsecutive processes with differing dynamic properties.

few months of the year. In the case of pipelinetransport and local distribution, the potential for realtime adaptation of supply to demand is limited by thepower of compressor stations and the size, length andcritical pressures of the pipelines.15 Using liquefactionand regasification terminals for storage depends on theinterval between two loads (typically a few weeks) andgenerally only allows for the management of dailypeaks in the importing country. The natural gas intransit in methane tankers represents less than 1 billion

m3 worldwide at any given moment. Finally, becauseof the low energy density of gas, storage in municipal



15 The gas contained at any given moment in a typicalinternational gas pipeline (length 1,000 km, diameter 40inches, pressure 100 bar) is in the order of 60-100 millionm3, measured under standard temperature and pressureconditions. Variations in the gas pressure of a fewatmospheres allow for a degree of flexibility (line-pack);however, this is only available for short periods, generallyless than a day, and is limited to about ten million m3.

*The capacity to modulate supply is calculated as the fraction of the months in which the difference between consumption and supply is lessthan 10%.

Table 9. Modulation of supply and storage capacity in OECD countries during the years 2001-04(based on IEA data, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

Countries Average variation Capacity to modulate supply*(%)

Working gas/ annualconsumption (%)

Mexico 1.2 100.0 0.0

Japan 1.3 100.0 0.0

New Zealand 1.4 100.0 0.0

Ireland 1.5 100.0 0.0

Portugal 1.6 100.0 0.0

Australia 1.6 100.0 5.8

Turkey 1.7 100.0 9.2

Greece 1.8 100.0 0.0

Finland 2.3 100.0 0.0

Luxembourg 2.4 100.0 0.0

Netherlands 2.4 100.0 4.9

Sweden 4.2 100.0 0.0

Switzerland 4.3 100.0 0.0

Norway 8.5 100.0 0.0

United Kingdom 2.3 100.0 3.6

Spain 1.6 91.7 9.1

South Korea 2.8 66.7 0.0

Belgium 2.2 58.3 4.2

Denmark 2.9 58.3 13.7

Canada 1.9 58.3 19.4

Poland 2.3 33.3 11.5

United States 1.8 33.3 19.5

Italy 2.7 25.0 16.6

Austria 3.2 16.7 35.2

Germany 3.2 16.7 19.7

Hungary 4.1 16.7 23.3

France 4.9 16.7 22.4

Czech Republic 4.8 8.3 21.9

storage facilities has an extremely high cost per unit ofenergy; the costs of storage on end-user premises areprohibitive.16

The potential for managing the seasonality ofrequirements by adapting supply on a monthly basisdecreases drastically with increasing annual excursionin demand, as shown in Table 9. In fact, the onlycountries where the ratio of supply (production+netimports) to consumption is close or equal to 1 in allmonths of the year are those with: small variations inrequirements (countries where consumption isconcentrated in electricity generation or in the energysector); withdrawals that have a minimal impact on thethroughput of large international transport networkseven during periods of maximum demand (Finland,Luxembourg, Sweden, Switzerland);17 numerousnatural gas production fields whose exploitation as awhole is flexible to variations in demand (Norway,United Kingdom, Netherlands).

Other countries must resort to gathering gas instorage reservoirs (working gas) during months whenrequirements are low, in sufficient quantities to meetdemand during months of high consumption whichcannot be covered by withdrawals from transportnetworks or production fields. Fig. 2 shows a clearinverse relation between the availability of storage andthe degree to which requirements are met exclusivelyby supplies.

Short and long-term elasticity

Natural gas systems are characterized byinfrastructures which are fixed or almost impossible tomodify in the short term, leading to heavy restrictionson the adaptability of consumption to variations inexogenous conditions. The high investment costs and

long time required to build transport and distributionnetworks limit the potential for significant increases inconsumption following reductions in natural gasprices; significant price increases lead to a concurrentdrop in consumption only when plants fuelled byalternative lower priced energy sources are alreadyinstalled or readily installable, or by foregoing a partof the energy service. However, the sensitivity ofdemand to price variations differs substantiallybetween electricity generation, industrial uses and theresidential, commercial and public sector.

In the electricity generation sector, gasconsumption tends to be relatively elastic to price.Generally speaking, power companies generateelectricity from an assortment of plants using differentenergy sources with the objective of minimizing costs(or maximizing profits) depending on the demand forenergy, its hourly profile, generating cost and sellingprices. At the national level (and at the company level,if it owns sufficiently diversified plants) a significantincrease in relative gas prices generally results in asignificant drop in consumption in favour ofalternative fuels.18 Similarly, if sufficient gas-basedgenerating capacity is available, falling prices lead toincreased consumption. Variations in gas prices arealso reflected in power generating costs and in theprice of electricity, with further impacts onconsumption in the short term; this is more evident incountries with electricity exchanges.

In the industrial sector, short-term switchingbetween energy sources is generally less pronounced.Unlike the power sector, there are generally no valideconomic reasons for maintaining parallel plants basedon alternative sources within a single industrial unit.Given the high costs, companies install multiple plantsonly when continuity of supply is absolutely criticalfor the integrity of machinery and industrial processes.Most companies do not respond in the short term toprice increases, when these can be passed on to theirproducts, or adjust to them by improving the plantefficiency or limiting consumption when this does not



16 Oil products in the liquid state have a calorific contentper unit volume about 1,000 times greater than that ofnatural gas in the gaseous state under standard temperatureand pressure conditions. Gas oil, for example, has a lowercalorific value of around 8.7 Gcal/m3 compared to 8.25Mcal/m3 for methane.

17 The maximum monthly variation in Swiss gasrequirements during the period 2001-04 (about 340 millionm3) corresponds, for example, to a variation of only 0.2% inthe average overall flow rate of the gas trans-nationalpipelines carrying gas to the country.

18 There are obviously repercussions on other sources ofgeneration as well (hydroelectric, nuclear, etc.), but themarket segments are largely distinct, and the main effect isconcentrated in the thermoelectric fossil fuel-based sector.

wor

king

gas

/an

nual

con

sum

ptio

n (%

)

0

5

10

15

20

25

30

months with consumption equal to supply (%)

15 25 33 60 92 100

Fig. 2. Modulation of natural gas supply and storage capacity in OECD countries (2001-04).Countries are grouped by month shares with monthly consumption equal or close to monthly supply (production+supply).

significantly affect the industrial process; for example,by saving on space heating or reducing the processtemperature within the tolerance limits. Conversely, adrop in prices may lead to greater carelessness in theuse of gas, wastage and increased consumption.

In the residential, commercial and public sector,sensitivity to variations in the price of natural gas iseven lower, especially in the case of residential uses,partly due to the low or inexistent diffusion ofappliances fuelled by alternative sources and in part tothe consumers’ limited perception of prices changes.Unlike industrial companies, which closely track theprice of energy day by day, especially in the case ofenergy-intensive manufacturing processes, in theresidential and small business sectors, variations inprice usually become apparent with the billings afterseveral months’ delay. Moreover, in many areasregulatory mechanisms tend to attenuate pricevariations, distributing them over relatively longperiods, and thus altering the consumer’sresponsiveness. Over periods longer than a year, theresidential, commercial and public sector doeshowever tend to react to persistent higher prices bydecreasing less essential energy uses, for example byreducing heat losses and the indoor temperatures.

Econometric analysis confirms the reducedimportance of short term price variations in determininggas demand compared to variations in infrastructurelinked variables which reflect the longer termdevelopment of energy systems. Tables 10 and 11 reportthe statistical results obtained with simple logarithmicspecifications, relating consumption to prices and percapita GDP (used as an indicator of the infrastructuredevelopment) in the United States, Japan and theEuropean Union and OECD member countries(EU-15). For these countries, the IEA publishes uniform

and comparable annual data, covering a quarter of acentury (1978-2002), a sufficiently long period of timeto allow for a statistically meaningful comparison.19

The following concentrates on an examination ofthe elasticity of consumption in the three sectors underconsideration (residential, commercial and public;industry; power generation) and in the three areas(United States, EU-15, Japan) with respect to threevariables: the absolute price of gas referred to the baseyear 1978; the relative price compared to alternativefossil fuels; the rate of growth of per capita GDP. Thefirst two variables can be considered short-term, sinceprices change year by year over a time-frame too shortfor infrastructures to adjust significantly. The thirdvariable changes slowly over time and is clearlylong-term. The alternative energy sources used forcomparison obviously vary depending on the sector. Inthe residential, commercial and public sector,electricity and gas oil were considered; in theindustrial sector gas oil, fuel oil and coal; in the powergeneration sector fuel oil and coal. To avoidunnecessarily cumbersome analysis, the tables reportonly the arithmetical averages of the values relating tothe sectors (or countries) included in the sample.

The results reported in Table 10 referring to theaverages by sector obtained by aggregating across allthe countries, indicate significant price elasticities andconfirm lower values in residential, commercial andpublic uses compared to industry and power



19 For an evaluation of the significance of the resultsreported in the tables, reference should be made to a normaldistribution, 22 degrees of freedom (24 yearly observationsminus two regression variables) and a degree of significanceof 5%, for which the critical values of the F and T statisticsare 8.65 and 2.07, respectively.

Table 10. Elasticity by use sector during the period 1978-2002(based on IEA data, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

Variable and sector Elasticity Multiple R R squared F statistic T statistic

Absolute priceCivil uses �0.542 0.813 0.687 37.961 �4.155Industry �0.689 0.742 0.610 45.899 �5.046Power generation �0.610 0.684 0.535 20.024 �4.302

Relative priceCivil uses �0.231 0.850 0.734 45.641 �1.672Industry �0.295 0.871 0.776 188.107 �3.651Power generation �0.363 0.652 0.445 11.351 �2.380

Per capita GDPCivil uses 1.241 0.847 0.738 75.701 7.368Industry 1.095 0.812 0.699 67.529 7.420Power generation 1.278 0.822 0.693 43.496 6.035

generation. Industry shows the highest elasticity withrespect to absolute prices, and, predictably, powergeneration the highest elasticity with respect torelative prices. All three sectors show a greatersensitivity to changes in absolute gas prices comparedto relative prices; this would substantiate the relativelyscarce propensity to maintain multiple plants usingdifferent fossil fuels. However, the ratio of the twoelasticities is appreciably greater for the powergeneration sector (0.59 as opposed to 0.42). Theelasticity of consumption to per capita GDP isconsiderably above 1 in all three sectors. The lowerelasticity in the case of industry probably reflects thegenerally more widespread use in this sector, and alower degree of dependence on the development ofdistribution networks.

Table 11, presenting the results obtained byaggregating over all sectors in each of the three areas,reveals considerable differences between the UnitedStates, EU-15 and Japan which can be explained interms of the different degree of maturity in natural gasuses. The lower price elasticity of the United States,particularly in relative terms,20 reflects advanceddiffusion in most uses and decade-long habits. InJapan, the high elasticity, especially to absolute prices,reflects the historically very high cost of natural gasimported as LNG (Liquefied Natural Gas) and usedmainly for electricity generation. As might beexpected, the European Union has an intermediateposition with respect to variations in absolute price,while the higher elasticity with respect to relativeprices is a consequence of greater substitutability inthe power generation sector compared to Japan. In theUnited States, the extremely low long-term elasticity(with respect to per capita GDP) reflects thepractically ubiquitous diffusion of distribution

infrastructure; at the other extreme, the very highelasticity shown for Japan reflects the very lowdiffusion of gas in industrial and especially residential,commercial and public uses (see above). Thelong-term elasticity is also relatively high for theEuropean Union, though lower than in Japan, due tothe relatively scarce or intermediate diffusion of gasuse in many EU member states.

2.4.3 Natural gas supply

The gas chain

Since the 1980s, the regulation of the natural gassector has led to profound changes in the structure,organization and regulation of the industry, with theunbundling of monopoly activities from competitiveconcerns and the emergence of a completely newwholesale business.21

Although these changes have modified theoperating practice of companies, they have notsignificantly altered the organization and technicalcharacteristics of the gas chain, which can still beconveniently discussed with reference to four mainphases: production; international transport; storage;



20 However, it should be noted that in the case of relativeprices, the degree of significance of the T statistic is belowthe critical value.

21 This revolution first made a sporadic appearance in afew countries (the United States, the United Kingdom,Australia, New Zealand, Argentina and Chile) but thenspread rapidly to a multitude of other areas (the EuropeanUnion, Turkey, Japan and various Asian countries) and isalso starting to take root in Russia and some Africancountries (Algeria, the Republic of South Africa, etc.).

Table 11. Elasticity by geographical area during the period 1978-2002(based on IEA data, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

Variable and area Elasticity Multiple R R squared F statistic T statistic

Absolute priceUnited States �0.289 0.687 0.501 12.179 �2.947OECD Europe �0.600 0.864 0.754 46.734 �6.369Japan �0.928 0.824 0.707 50.174 �5.242

Relative priceUnited States �0.073 0.686 0.493 14.852 �0.829OECD Europe �0.469 0.863 0.754 88.805 �3.526Japan �0.463 0.849 0.743 48.835 �5.448

Per capita GDPUnited States 0.147 0.699 0.519 13.377 2.443OECD Europe 1.416 0.897 0.811 72.714 8.510Japan 1.806 0.874 0.789 94.834 8.978

inland transport and final distribution. This sectionfocuses on the technicalities of the industry, on theinfrastructures, the operating companies and thelinkages between the various components of thesystem.

ProductionNatural gas production employed about 700,000

people worldwide in 2004. This is a rough estimateobtained by subdividing employment in the oil and gassector on the basis of the energy content of the oil andgas produced since, as is well-known, exploration andproduction activities are largely shared up to extractionof the raw fuels from the underground reservoir andbefore entry into the transport network feeding into endmarkets. The estimate refers to upstream activities.22

The estimated number of producers worldwideruns into several thousands, but only a few hundredare involved in the whole cycle from exploration anddevelopment all the way to the exploitation of wells. Infact, most companies produce less than 100 millionm3, and the largest group in numerical terms consistsof tiny enterprises often run on a family basis.23

Nevertheless, the sector is fairly concentrated, in linewith the high capital investments which characterize it.The 15 largest companies, with an annual productionof over 30 billion m3, accounted for 47% of worldproduction in 2004; together with the following 50medium-large companies, with a production of over 3billion m3, they account for 64% of world production.The same 65 companies accounted for almost 70% ofthe world’s proven natural gas reserves.

Alongside these operators are several hundredservice companies involved in activities ranging fromgeophysical and seismic surveys and assessments todrilling onshore wells and operating offshoreplatforms. Over the past two decades, to improveefficiency and lower costs, most multinationals andmany state companies have adopted managementmodels based on outsourcing the more specializedactivities limiting in-house responsibilities as much aspossible to general administration and strategicplanning.

A typical example are companies which supplydrilling services and hire platforms for offshoreoperations, around 50 companies worldwide. This isan activity which varies significantly over time, being



22 The main upstream activities are: contract negotiation,geological and geophysical studies and research, fieldanalysis based on seismic surveys, data processing andreservoir evaluation, drilling of exploration wells withassessment of the subsurface geology, drilling ofdevelopment wells, management of subcontracts,preparation of production wells, reservoir exploitation,related commercial and administrative activities.

23 Most of these very small producers are found in theUnited States, where they exploit the residual resourcesremaining in stripper wells. These are wells transferred fromcompanies to private individuals when they reach very lowproduction levels (generally below 1,700 m3/d). Accordingto the IOGCC (Interstate Oil & Gas Compact Commission,2005) there are 272,000 wells of this type in the UnitedStates. With an average production of about 440 m3/d ofnatural gas, they supplied a total of about 44 billion m3/yr or7% of the United States’ total production in 2004.

Table 12. Weekly average number of drilling rigs operating in 2004(based on statistics by Baker Hughes, 2005)

World regionsUse by type Use by source

Total rigsOnshore Offshore Oil wells Gas wells Mixed wells

United States and Canada 1,456 101 256 1,300 2 1,557

Japan and Oceania 14 7 9 7 6 22

Europe 29 41 49 18 3 70

Russia and other former Soviet countries 328 5 228 106 0 334

Asia 96 79 126 47 2 176

Middle East 196 34 183 47 0 230

Africa 34 14 46 2 1 48

Latin America 225 66 216 68 6 290

World 2,378 347 1,113 1,595 20 2,727

highly sensitive to oil prices, which it tracks with aroughly one year time lag. Investment costs are in theorder of 10 million dollars for an onshore drilling rigand between 50 and 500 million dollars for an offshoreplatform.24 The cost of the service is about 10,000 and60,000 dollars per day, respectively, during peakperiods. Outsourcing of these activities is obviouslybenefitted by the fact that service companies can counton better exploitation of assets, and there arepractically no companies on the market which carryout drilling with their own equipment.

During 2004, there were on average 2,730operating rigs worldwide, almost 60% of which in theUnited States and Canada alone (Table 12). Again on aglobal level, 87% of the rigs operated onshore and58% on gas wells. Utilisation of rigs variesconsiderably according to region, reflecting the extentand location of resources. In the United States andCanada 6% of rigs were used offshore, as opposed to21% in the rest of the world. Similarly, the distributionbetween oil and gas is very different; in the UnitedStates and Canada, 83% of wells were drilled in gasreservoirs, compared to only 25% in the rest of theworld. Using the data for 2004, it is possible toestimate an average productivity of 1.5 wells permonth per drilling rig, equivalent to about 20 daysbetween successive drillings (including the timeneeded for transportation and set-up). However,productivity varies significantly with prevailingconditions. In 2004, high oil prices led to a strongincrease in development wells (92% of the total) whichtake longer to drill than exploration wells.

After extraction, the gas is generally dehydratedand treated to remove impurities and separate out

liquid and solid hydrocarbons. Of particularimportance is the recovery of non-methanehydrocarbons, which in 2004 contributed about 10%of the energy content of the raw gas producedworldwide, and significantly more in some parts of theworld, especially in the Middle East and in the Japanand Oceania region (Table 13). The chemically pureproducts which accompany methane are mainlyethane, propane and butane, but over half of thenon-methane extract consists of naphtha used inchemical synthesis, natural gasoline and other blends.

Over 50% of worldwide natural gas liquidextraction capacity is found in the United States andCanada, but over the past decade installed capacityin the Middle East has increased rapidly.Additionally, with stagnating production, theextraction of liquids in the United States has fallento 38% of the world total. The percentage of gastreated to recover higher molecular weighthydrocarbons varies considerably depending onquantity and the market value of the productsextracted, as well as on environmental regulationsand the standards of downstream markets.

A final aspect of the production phase regards theconversion of gas into liquids by chemical synthesis,undertaken close to the well head to reduce transportcosts. Both producing and consuming countries have avested interest in developing Gas-To-Liquids (GTLs)technologies: producing countries without marketoutlets for their gas, in order to reduce environmental



24 The figure of 500 million dollars refers to thePetronius platform, the world’s largest, measuring 640 m inheight and weighing 43,000 t.

Table 13. Extraction of the liquid fractions of natural gas in 2004 (Worldwide […], 2005)

World regionsNumber

of plantsCapacity(Gm3/d)

Averagecapacity(Gm3/d)

Quantitytreated(Gm3/d)

Fractiontreated

(%)

Productionof liquids

(Ml/d)

Energycontent

(% of raw gas)

United States and Canada 1,501 3,477 2.3 2,119 85.8 397 14.5

Japan and Oceania 8 151 18.9 106 87.8 45 33.7

Europe 51 690 13.5 278 26.7 37 3.2

Russia and other former Soviet countries 32 79 2.5 40 1.8 38 1.6

Asia 50 508 10.2 429 48.1 57 5.7

Middle East 72 824 11.4 582 51.2 283 22.4

Africa 22 489 22.2 273 32.7 64 6.9

Latin America 81 528 6.5 386 51.9 106 12.9

World 1,817 6,746 3.7 4,213 44.5 1,027 9.8

pollution resulting from flaring or venting ofassociated gas into the atmosphere (the case ofNigeria), or as a solution for depleting oil resources(the case of Qatar); importing countries, in order todiversify energy supplies away from traditional MiddleEastern suppliers.

Technologies for converting natural gas intoliquids are still in the development stage. Theprocess is classic steam reforming with theproduction of hydrogen and carbon monoxide(Syngas), followed by catalytic (Fischer-Tropsch)synthesis. The main products are: mostly gas oil(50-80% of the total, practically free of sulphur andpolynuclear aromatics); liquefied gases, naphtha,lubricants and waxes of various types (0-30%).Currently there is one operating pilot plant (inMalaysia) and two plants are under construction (inQatar and Nigeria). About 50 projects are in theresearch phase, with a total conversion capacity ofabout 130 billion m3/yr.25

International transportMost of the gas produced worldwide is

consumed in the country of origin. In 2004, justover a quarter of net natural gas production wassent to areas of consumption outside nationalborders.26 However, this share has increased veryrapidly from almost negligible levels in the 1960s,as can be seen from Table 14, which alsodistinguishes between the role of pipeline andtanker transport. Both these forms of transport canbe described as essential infrastructures and are

characterized by strong elements of monopolycontrol, though only marginally affected by anyform of regulation.27 International transport isgenerally undertaken by state owned companiesand/or private multinationals with upstreamactivities, or by national transport companies with along standing supply role in their own country.28

Pipeline transport After the Second World War, enormous advances

in pipeline transport technologies in terms ofresistance of materials to high pressures and extremetemperatures and the capacity of compressors, led toincreased efficiency and lower costs. At least until themid-1960s, the growth in exports was linked to theconstruction of international gas pipelines; at the sametime, as transport distances within large countries werealso increasing. Worldwide, the average transportdistance tripled from about 300 km in 1950 to almost1,000 km in 1970.



25 The main companies involved in the development ofGTL are Sasol, Shell, ExxonMobil, BP and ChevronTexaco.

26 The corresponding shares in the oil sector were about50% for crude and intermediates and 35% for refinedproducts.

27 In relation to new investments, for example, Europeandirectives impose third party access for a fraction of theimport capacity and for a limited number of years.

28 In terms of ownership of import infrastructure inEuropean countries, the most important companies areGasunie, Gazprom, Eni, E.On Ruhrgas, ExxonMobil,NNPC, OMV, Shell International, Sonatrach.

Exports refer to the producing country. However, the data reported do not include trade within the former Soviet Union area. The gas producedis net of reinjection and other losses during the extraction phase.

Table 14. International gas trade between 1965 and 2004 (CEDIGAZ, 1997-2004)

Year

Gas exported (Gm3) Totalmarketed gas

(Gm3)

Shareof exports

(%)By pipelineBy methane

tankerTotal

Share oftankers (%)

1965 22.5 0.7 23.2 3.0 750 3.1

1970 42.9 2.7 45.6 5.9 1,040 4.4

1975 112.3 13.1 125.4 10.4 1,264 9.9

1980 169.6 31.3 201.0 15.6 1,519 13.2

1985 178.0 50.9 228.9 22.2 1,742 13.1

1990 235.3 72.1 307.4 23.5 2,068 14.9

1995 304.5 93.4 397.9 23.5 2,204 18.1

2000 400.9 139.3 540.2 25.8 2,490 21.7

2004 502.1 178.0 680.0 26.2 2,763 24.6

The growth in pipeline transport during this periodwas linked essentially to Canadian gas exports to theUnited States and the transmission of Russian gaswithin the Soviet Union. Dutch29 gas and Russian gaswere first exported to Europe in the 1970s, while LatinAmerica saw its first Bolivian gas export initiatives.30

However, it was in the 1980s that the largestinternational transportation networks were built, linkedinitially to the exploitation of North Sea resources andthe export of Algerian and Mexican gas. From the1990s, there have also been numerous projects forpipeline export from countries of Asia and LatinAmerica and, in recent years, from the Middle East aswell.

In 2004, there were 52 operating pipelines forinternational gas transport with a total capacity ofalmost 700 billion m3/yr, 72% of which was utilised inthat year (Table 15). The characteristics ofinternational pipelines vary considerably. The averagelength is 860 km, but this ranges from a minimum of120 km (the HAG gas pipeline between Hungary andAustria) to a maximum of 3,750 km for Russianpipelines, corresponding altogether to a sum total ofabout 45,000 km. The average capacity is 13.1 billionm3/yr, but this ranges from less than 1 billion m3/yr toalmost 80 billion. The average diameter also variessignificantly depending on pipeline capacity, lengthand compressor power; from a minimum of 20 inchesto a maximum of 56 inches, in the case of the newpipeline to transport Russian gas from the Yamalpeninsula.

Employment in the operating phase depends mainlyon the number of compressors, which require constantmaintenance and are generally installed 150-200 kmapart. For all the international gas pipelines, directemployment is estimated at a total of 3,000 technicians,working essentially on operation and maintenance.

Tanker transportA significant boost to the development of

international trade came from cryogenic transporttechnology, which allowed the overcoming of technicaland economic obstacles posed by long sea voyageswhile reducing the risk inherent in fixed connectionsand helping to promote competition. Liquefied natural gas transport is generally competitivecompared to pipeline transport over distances greaterthan 3-4,000 km; however, these figures are highlysensitive to the type of route.31 Introduced in the1960s, LNG rapidly conquered an important marketshare, especially during the 1980s, increasing its shareof international gas transport from 4% in 1970 to 15%in 1990 (Table 14).



29 Dutch gas exports fell sharply after 1980, when theDutch government adopted a policy of saving its resourcesfor future use.

30 Through the Yabog gas pipeline (Yacuiba, RioGrande), of rather limited capacity, originally built to exportBolivian gas to Argentina. The flow of gas has now beenreversed.

31 Especially in the case of subsea gas pipelines.

* Average age weighted with capacity. ** Pipeline lengths are related to world regions depending on the exporting country. Distances aremeasured from the reservoir in the producing country to the border of the importing country.

Table 15. Characteristics of international pipeline transportation systems operating in 2004(CEDIGAZ, 2004)

Producing areaNumber

of pipelinesAverage age* (yr)

Length**(km)

Capacity(Gm3/yr)

Average capacity(Gm3/yr)

Exports(Gm3)

United States and Canada 9 28.3 11,854 129.3 14.4 121.8

Japan and Oceania 0 – 0 0.0 0.0 0.0

Europe 17 12.1 8,381 223.4 13.1 154.2

Russia and other former Soviet countries

10 22.2 9,188 183.3 18.3 153.6

Asia 3 13.0 1,515 15.3 5.1 15.3

Middle East 1 5.2 1,300 17.0 17.0 4.8

Africa 4 10.9 6,436 43.0 10.8 36.7

Latin America 8 11.5 6,157 71.9 9.0 15.7

World 52 17.6 44,831 683.2 13.1 502.1

LNG technology opened up a Japanese market andother markets of the Far East with rapidly growingconsumption; at the same time it allowed for theexploitation of vast resources in countries which hadno other outlet for their gas, and where the potentialfor local consumption was limited in the short term(Algeria, Indonesia, Qatar) or held back bycompetition from other sources (Australia). In 1980,almost 60% of LNG exports were of Asian origin(Brunei and Indonesia) and destined for the Japanesemarket. Exports from Africa (Algeria and Libya) wereaimed essentially at the European and Americanmarkets. This period also witnessed the rapid growthof LNG exports from the Middle East and Australia,destined almost entirely for the Far Eastern markets,while the addition of Nigerian gas gave a new boost toAfrican exports, directed mainly (90%) at Europe.LNG exports from Latin America began only at theend of the 1990s, and were targeted mainly at meetingthe increasing production deficit of the United States.

Both in terms of technology and logistics, the LNGcycle is considerably more complex than pipelinetransport. It involves pipelines from producing fieldswithin the exporting country, liquefaction terminals,loading and unloading ports, methane tankers,regasification terminals and pipelines linking these totransport networks within the importing country. Thecomplexity of the system is also reflected in the staffemployed. Worldwide, the sequence of activities fromthe liquefaction to the regasification numbered a totalof about 20,000 employees in 2004, compared to3,000 for pipeline transport. In terms of gas volumes,the international transport of 1 billion m3/yr of gas bypipeline required an average of 6 employees comparedto 110 employees for gas tanker transport.

Table 16 shows the main characteristics of the LNGtransport system, broken down by world regions. Themajor feature that comes to light is the far greaterdegree of capacity utilization of liquefaction terminalscompared to regasification terminals (88% comparedto 41% worldwide in 2004). Excluding Latin America,which currently has only one operating regasificationterminal (Dominican Republic), which came on streamin 2004, the world average is influenced by the verylow utilization of capacity in Japan and Asia(specifically South Korea); capacity is maintainedhigh for security reasons and in order to modulatepeak loads in the absence of underground storagefacilities. The table also highlights the largedifferences between the frequency of tanker voyagesas a function of distance and tanker capacity. In 2004,LNG tankers from Africa and mainly directed towardsEurope, made an average of 25 voyages with anaverage cargo of 89,000 m3. Tankers originating in theMiddle East and directed mainly towards the Far East,

made only 9 voyages, with an average cargo of135,000 m3.

The data reported in the table also reflect the drivetowards economies of scale to reduce the high costs ofthe transport chain. The capacity of liquefaction trainshas actually tripled since the 1970s to today’s 3 Mt ofLNG per year, equivalent to almost 4 Gm3 of gas.32

This increase is correlated with the significantincrease in storage capacity in those regions whichhave most recently developed liquefaction plants:120,000 m3 of liquefied gas per liquefaction train inLatin America (Trinidad and Tobago) compared to anaverage of 49,000 in Africa. A similar trend, althoughless marked, can be seen in the case of regasificationterminals, with an evident increase in the averagecapacity of vaporizers and storage tanks in the mostrecently developed gas offloading areas.33 Similarly,the inverse correlation between the age and averagecapacity of LNG tankers in different regions reflectsthe large increase in capacity over time: from30-50,000 m3 of LNG in the 1970s, to 150,000 m3 andover in more recent years.34

Underground storageThe seasonal gas storage is mainly undertaken in

underground geological formations. There are twomain types of underground storage: in poroussubstrata (depleted reservoirs and aquifers) and incavities or caverns (in impermeable salt formations).Most storage capacity is found in depleted reservoirs,followed by aquifers, salt caverns and rarely in rockformations or abandoned mines.

Table 17 reports the distribution of undergroundstorage facilities in the main world regions, togetherwith their operating characteristics. Storage facilitiesare concentrated in regions with marked seasonalvariations in consumption (see above), and arecompletely absent in three of the eight regions underconsideration. Most underground storage facilities areowned by transport or distribution companies, andthey are managed jointly and integrated with transportactivities. Storage activities can be spread out overseveral plants and carried out under competitive



32 One m3 of natural gas in the liquid phase is equivalentto 615 m3 in gaseous form. One t of LNG corresponds to1,317.8 m3 of natural gas in the gaseous phase.

33 An exception is Japan, which uses regasificationterminals to store gas. The most recent storage tanksinstalled in this country have a capacity of 200,000 m3 ofLNG.

34 The initial development of LNG exports from Algeriaand Alaska is reflected in the far lower average capacities inthe United States and Africa. Many old LNG tankers are nolonger earmarked for specific routes but still findopportunities in the spot trade.



* Refers to gas in the liquid phase. ** Refers to gas under standard conditions. *** The region refers to the producing country. **** Refers to the number of tankers not used on specific routes which carry out short-term and spot sales.

Table 16. Characteristics of the LNG cycle in 2004 (CEDIGAZ, 2004; IEA, Natural gas information, 2004)

World regions(Liquefaction terminals)

Ports TerminalsLiquefaction

trains

Storagecapacity*

(Mm3)

Liquefactioncapacity(Gm3/yr)

Volumeliquefied**

(Gm3)

Utilizationof capacity

(%)

Capacity per train

Liquefaction(Mm3/yr)

Storage(103 m3/yr)

United States and Canada 1 1 2 0.1 1.9 1.7 88.4 1.0 54.0

Japan and Oceania 1 1 3 0.3 15.4 12.2 79.0 5.1 86.7

Europe – – – – – – – – –


– – – – – – – – –

Asia 4 11 25 1.9 79.2 70.7 89.2 3.2 75.7

Middle East 3 5 10 1.1 42.3 40.5 95.6 4.2 110.0

Africa 5 6 27 1.3 48.9 39.0 79.7 1.8 49.2

Latin America 1 1 3 0.4 15.0 14.0 93.3 5.0 120.0

World 15 25 70 5.1 202.7 178.0 87.8 2.9 72.1

World regions(regasification terminals)

Ports TerminalsVaporization

lines

Storagecapacity*

(Mm3)

Regasificationcapacity(Gm3/yr)

Volumeregasified**

(Gm3)

Utilizationof capacity

(%)

Capacity per line

Vaporization(Mm3/yr)

Storage(103 m3/yr)

United States and Canada 5 5 28 1.2 30.5 19.2 62.8 1,089 41.1

Japan and Oceania 14 25 219 13.9 242.7 77.0 31.7 1,108 63.6

Europe 10 10 57 2.1 61.2 35.8 58.4 1,074 36.9


– – – – – – – – –

Asia 6 5 74 4.1 96.5 41.7 43.2 1,304 55.0

Middle East 1 1 7 0.3 6.3 4.3 67.8 900 36.4

Africa – – – – – – – – –

Latin America 1 1 2 0.2 2.5 0.2 7.2 1,250 80.0

World 37 47 387 21.7 439.7 178.0 40.5 1,136 56.0

World regions(LNG tanker fleet)***

TankersWeighted average age

(Yr)Capacity

(103 m3 of LNG)Average capacity

(103 m3 of LNG)Yearly frequency

of voyages

United States and Canada 4 21.4 291 76 8.4

Japan and Oceania 9 13.4 1,189 127 14.8

Europe – – – – –


– – – – –

Asia 53 20.0 6,063 114 16.9

Middle East 46 10.7 6,265 135 9.4

Africa 25 27.6 2,235 89 25.3

Latin America 10 3.0 1,383 135 14.7

Others**** 22 28.4 2,131 96 14.8

World 170 17.2 19,556 115 14.8

market conditions; legal or ownership separation fromother activities of the gas chain is not generallyrequired. Only in circumstances where there is a highconcentration of facilities under a single operator doesstorage become an essential infrastructure and de factoa monopoly, thus requiring regulation.35 Based on thedata available for the few companies exclusivelyundertaking storage activities, employees can beestimated as about 15,000 worldwide.

Table 17 shows the working gas (active reserve)which can normally be delivered to balance demandand for field production. In some countries (includingFrance and Italy) a significant portion of this gas ismaintained by law as a strategic reserve to meet thetemporary unavailability of one or more sources ofsupply (imports, domestic production) or exceptionallyhigh demand (very cold winters). The remaining gas(almost 50% worldwide) cannot generally be deliveredwithout compromising operation of the storagefacility; known as cushion gas, it is essential toprovide the basic thrust in the delivery phase.

Typically, underground storage facilities are filledduring the months when demand is low and emptied inthe months when it is high (summer and winterrespectively in the northern hemisphere). However, inrecent years, with the liberalization of gas markets, thefrequency of the storage filling and emptying cyclehas increased in some countries (the United Kingdomand the United States) in order to exploit priceopportunities between purchase and sales, usingstorage facilities to all effects as a gas parking facility.The possibility of increasing cycle frequenciesdepends on the maximum deliverability and injection

capacity of the storage facility. While the formerdepends mainly on the natural characteristics of thestorage system (permeability and rigidity of thegeological formation), on the amount of cushion gasand the pressure (generally lower than 150 bar), thelatter depends on compressor capacities. Naturaldeliverability decreases as the facility progressivelyempties, tending to zero as only cushion gas remains.Towards the end of the natural cycle, any increase inwithdrawals to meet peaks requires the use of pumps.

Short-term storage to meet daily peaks (peakshaving) can also partly make use of the storage tanksof LNG regasification terminals; these can be quitelarge, in the order of 100 million m3 of gas understandard conditions. However, although they arelocally significant (for example in the UK and Japan),the role played by these terminals overall is marginal.Short-term storage functions for daily or hourlymodulation may also be performed by transport andlocal distribution networks, when input exceedsdelivery. However, even in the largest transportnetworks, the so-called line-pack does not normallyexceed about 10 million cubic metres over the courseof a day (roughly 5% of the gas contained in thepipelines). Finally, in many parts of the worldtraditional gasometers are still widely used to managelocal peaks.

Table 18 illustrates the distinctive properties of thethree main types of underground storage facility: totalcapacity; volume of working gas; maximum pressure



Table 17. Characteristics of underground storage infrastructure at the beginning of 2004(CEDIGAZ, 2004; IEA, Natural gas information, 2004)

World regionsDepletedreservoirs

AquifersSalt

formationsOther Total

Capacity (Gm3) Working gasper plant

(Mm3)

Maximumdelivery(Mm3/d)

Cushiongas

Workinggas

Total

United States and Canada 359 40 31 3 433 146 130 276 300 2,640

Japan and Oceania 4 0 0 1 5 1 1 2 262 20

Europe 56 22 27 4 109 78 69 147 635 1,435


34 12 1 0 47 72 121 193 2,574 769

Asia 0 0 0 0 0 0 0 0 0 0

Middle East 2 0 0 0 2 2 2 4 950 15

Africa 0 0 0 0 0 0 0 0 0 0

Latin America 0 0 0 0 0 0 0 0 0 0

World 455 74 59 8 596 299 324 623 543 4,880

35 Currently, these are regulated only in Italy, the UnitedKingdom and the United States.

and deliverability; number of wells; duration, obtainedby dividing the volume of working gas by themaximum delivery. The properties of individualfacilities differ significantly from one another, to someextent due to their partial interdependence; forexample, maximum delivery depends on the pressureand number of wells, and the proportion of cushiongas. The data reported are therefore merelyrepresentative, mainly illustrating the principaldifferences between the three types of storage facility.

Depleted reservoirs Depleted reservoirs are the most common form of

underground storage facility due to their broadavailability and lower development costs. Their locationand geological properties can be easily identified usingthe data collected during the earlier resourceexploitation phase, and field preparation phase does notusually take longer than a couple of years.

The potential for converting a reservoir into astorage facility depends on three main factors: themaximum pressure allowed by the geologicalformation, which determines its capacity in terms ofvolume; the amount of cushion gas needed to supplythe basic thrust during utilization; and the porosity ofthe rocky sediment which influences maximumdelivery. The main item of expenditure concerns thewells which must be drilled to reach the projectspecifications; this can be 10-20 times greater than theflow during gas production from the field.

AquifersUnlike depleted reservoirs, the location and

properties of aquifers are not usually known. As aconsequence, the determining of geological

properties generally requires a preparatoryexploration phase, seismic analyses and drilling,significantly increasing costs. An assessment of thecapacity requires determining the rock’s porosityand its ability to withstand high pressures. Afterascertaining the suitability for conversion into astorage facility, an average of 4 years are requiredand sometimes much longer to prepare theformation for storage, injection and delivery.Compared to a depleted reservoir, developmentcosts are also raised by connections to the gastransport network for injection of cushion gas,absent in aquifers, and dehydration plants, since thestored gas is usually saturated with water vapour.

Salt caverns Salt caverns have characteristics which make them

ideal for storing natural gas. However, they are notwell-distributed in nature and are extremely expensiveto develop, with investment costs two or three timeshigher for the same storage capacity. Salt caverns arepractically impermeable to gas, which therefore doesnot leak into the atmosphere, but their preparationrequires salt removal by leaching, a process whichtakes several years and which generally incurs highcosts to avoid polluting the surrounding land. Giventhe rigidity and low permeability of the walls, saltcaverns require relatively little cushion gas (as little as30% of the total volume); in the event of anemergency, this can be fully extracted withoutcompromising the functioning of the facility.

The same properties make it possible to attain highdelivery rates. Salt formations often reach depths of upto 10 km, but storage facilities are usually no deeperthan 1-2 km, since at greater depths temperature andpressure conditions make the salt fluid and difficult toextract. The best storage facilities in caverns arespherical or oval in shape and up to a couple of km indiameter; depending on the type of geologicalformation, they may be wide and shallow rather thandeep and narrow. Moreover, their size is determined byduration requirements and delivery levels, and it maybe preferable to develop several medium-sized storagefacilities at a given site rather than a single large one.

Domestic transport and local distributionDomestic transport and local distribution ensure

the transfer of gas to end-users. In most of the largegas consuming countries, these two activities arecarried out by separate companies: transportcompanies convey large volumes of gas, generallyover long distances; local distribution companiesdispatch smaller gas shipments over relatively shortdistances. The boundary between the two is somewhatblurred, however; large consumers (electric power



Table 18. Technical properties of undergroundstorage facilities: representative worldwide values

(UNECE, 1999)

PropertiesDepletedreservoirs

AquifersSalt

caverns

Depth (m) 1,270 900 1,260

Pressure (bar) 134 90 150

Total capacity(Mm3)

1,760 930 550

Working gas (%) 49 42 70

Maximum delivery(Mm3/d)

14 6 18

Number of wells 32 19 11

Duration (d) 64 66 22

stations and many industrial plants), due to the largevolumes and high pressures involved, are generallysupplied directly from transport networks.Additionally, in some industrialized countries (such asthe United Kingdom and France) and almost alldeveloping countries, transport and distribution arecarried out by the same company.

A meaningful distinction between transport andlocal distribution can be made only on the basis of thephysical characteristics of the two activities andspecifically the transport pressure and the diameter ofthe pipes. The term transport is usually applied to thetransfer of large volumes of gas from point of origin(wellhead or import terminal) to point of final delivery(power station, industrial plant, local distributionnetwork), generally at pressures of over 15 bar and inpipelines with a diameter ranging from 20 to 40inches. In the larger countries, a distinction is alsomade between national transport at pressures of above40-50 bar up to over 80 bar, essentially for the transferof large bulk volumes, and regional transportation atlower pressures for final delivery. The pressure andsize of the pipelines are commensurate with thevolumes of gas to be transported and the transfertimes, determined in turn by the incoming flow andthe transportation distances.36

Transport capacity increases with the workingpressure in a non-linear way37 and is determined bytechnological characteristics (steel quality andproduction techniques) and by physical phenomena.Along its journey, the flow of gas slows down due tothe energy dissipated by the viscous friction betweenthe gas molecules and the inner wall of the pipeline.Maintaining required flow rates in transport tubingrequires compression at regular intervals, when thepressure drops below a critical value characterising thenetwork, generally around 55-60 bar. In networks witha prevalently linear configuration, compressors arespaced at intervals of 100-200 km; meshed networksrequire a compressor every 10-20,000 km2.

Centrifugal compressors are generally used, drivenby gas turbines which work in a similar way to aircraftturbines. The turbines have varying capacities in therange 10-30 MW, depending on the type of service.Before compression, the gas is filtered to removeimpurities (dust, water, liquid hydrocarbons, etc.)which would otherwise compromise operation of thecompressor and the integrity of the pipelines (in whichthe gas can move at velocities close to the speed ofsound). The gas can heat up considerably duringcompression and, if necessary, is cooled in heatexchangers on exit to avoid damaging the pipelinesand their lining.

Delivery from the transport system to localdistribution networks generally takes place at

pressures of around 15 bar, more rarely at higher orlower pressures (24, 12 or 5 bar depending on thecircumstances). Final distribution within townnetworks is carried out at a broad range of pressures,depending on user characteristics. The primarypressure reduction stations feed into medium-pressurenetworks with further reductions (initially to 0.5 barand 100 mbar) ending at deliveries to residentialcustomers, generally at pressures of between 20 mbarand 40 mbar.38 Simulteanously, the diameter of thepipes decreases to 10-12 inches for the larger usersand 2-3 inches for residential end-users.

The inter-linkage between bulk transport andlocal distribution systems typically makes use ofautomatic pressure regulation devices guaranteeingclose coordination between the different elements(injections, compressor stations, withdrawals,maintenance, network extensions, etc.). Remotemeasuring and control from a central despatchstation allows timely intervention over the entiretransport system, from cross borderinterconnections to linkages with large end-usersand local networks, which in turn operate despatchsystems on a local scale.

The development of transport and distributioninfrastructure by major world regions over the periodfrom 1970 to 2003 is shown in Table 19 in terms of kmof pipeline. The length of transport lines reported inthe table also include international gas pipelines buttheir contribution is minor (less than 5%), with theexception of Africa (35%), where export pipelines playa dominant role in the energy economy, and LatinAmerica (14%). However, it is impossible to draw aclear boundary between pipelines for national andinternational transport, since the latter are alsoemployed for domestic transport.

By 2003, transport networks had reached a totallength of about 1.2 million km worldwide, comparedto the 5.1 million km for distribution networks. Table19 shows the faster growth of distribution networkscompared to transport networks in almost all worldregions. Worldwide, the ratio has increased steadilyfrom 2.5 in 1970 to 4.4 in 2003. The differences



36 In the United States, transport from the largestreservoirs located in the South to the main areas ofconsumption in the North-East takes several days. In mostEuropean countries transfer from entry points at nationalborders does not generally require longer than a day.

37 For an equivalent pressure drop, the capacity of apipeline is proportional to the diameter of the tube to apower of about 2.5.

38 Conventionally, for the sake of brevity and clarity,pressures are always given with reference to the atmosphericpressure base. For example, a pressure of 20 mbar is 1.020 bar.

between regions mainly reflect variations in sectoralcontribution, in extension of distribution networks andin transport distances. The greater transport distancesin North America lead to a far higher ratio in Europe,although distribution networks are more or lessequally widespread. At the other extreme, Africa, withlimited diffusion of residential uses and longtransportation distances (linked in part to internationaltrade) has a ratio of just over 2.

Viewed from this angle, the Japan and Oceania andthe Asia region seem somewhat anomalous; these arealso the only regions where the ratio of distribution totransport network lengths has fallen over time. Both theseareas import most of their gas in the form of LNG andhave privileged the use of gas for electricity generationnear terminals (with short transport distances),developing uses in residential, commercial and publicand industry mostly in proximity to power stations.

The system described above comprises about350 transport companies worldwide, about 225 ofwhich in the United States alone.39 Internationalstatistics on distribution are fragmentary andrelated assessments are necessarily approximategiven the enormous variety of local situations. Forexample, the State of California, with a populationof 35 million, has 8 gas distributors, whereasGeorgia, with a population of just over 8 million,has more than 70. Similarly, in Europe, Italy andGermany have hundreds of local distributors,whereas the Netherlands have only 12 and theUnited Kingdom none. Crude estimates based on



39 Specifically, 25 companies for interstate transport(covered by Federal regulations) and 200 companies fortransportation within individual states (regulated by stateauthorities).

Table 19. Development of transportation and distribution networks (103 km) worldwide during the period 1970-2003(CEDIGAZ 1997-2004; IEA, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

World regions and networks 1970 1975 1980 1985 1990 1995 2000 2003

TransportationUnited States and Canada 448 464 475 493 500 500 507 510Japan and Oceania 2 4 7 10 13 15 17 20Europe 91 122 155 190 214 230 249 262Russia and other former Soviet countries 68 95 132 175 203 205 215 227Asia 3 5 6 9 15 23 32 44Middle East 2 3 7 9 12 17 22 28Africa 2 3 5 7 9 13 18 23Latin America 13 17 21 32 35 37 44 47World 628 715 808 925 1,000 1,039 1,104 1,161

DistributionUnited States and Canada 1,013 1,110 1,215 1,338 1,516 1,697 1,777 1,908Japan and Oceania 48 65 86 95 118 125 125 133Europe 373 476 602 677 921 1,203 1,407 1,571Russia and other former Soviet countries 63 105 136 183 290 550 647 886Asia 53 84 104 124 174 210 254 304Middle East 2 2 5 13 29 49 71 108Africa 2 4 6 9 18 28 36 51Latin America 12 17 26 39 59 106 124 166World 1,565 1,863 2,179 2,479 3,125 3,966 4,441 5,128

Distribution/transportation ratioUnited States and Canada 2.3 2.4 2.6 2.7 3.0 3.4 3.5 3.7Japan and Oceania 28.8 17.0 13.0 9.7 9.3 8.4 7.3 6.8Europe 4.1 3.9 3.9 3.6 4.3 5.2 5.7 6.0Russia and other former Soviet countries 0.9 1.1 1.0 1.1 1.4 2.7 3.0 3.9Asia 20.7 16.2 16.5 14.0 11.7 9.1 7.9 6.9Middle East 0.7 0.7 0.7 1.5 2.4 3.0 3.2 3.9Africa 1.3 1.3 1.2 1.2 1.9 2.1 1.9 2.2Latin America 0.9 1.0 1.2 1.2 1.7 2.9 2.8 3.5World 2.5 2.6 2.7 2.7 3.1 3.8 4.0 4.4

the available international sample and sectoralconsumption in the different world regions giveresult in about 3,000 local distribution companiesworldwide, about a third of which are in the UnitedStates. Very often, these companies arehorizontally integrated with other public utilitiessuch as electricity, water and urban waste. They areboth publicly and privately owned, with a strongtrend towards (at least partial) privatization inalmost all countries.

Network management activities typically havea high employment rate, especially for distributionnetworks. However, employment in this sector isset to fall significantly with the gradual separationof network and marketing activities, the greaterefficiency introduced with network regulation,subcontracting of meter reading and thedevelopment of remote measuring. Currently, itcan be estimated that just over 70,000 people areemployed worldwide in transportation, and almost1.2 million in the distribution sector; these figurespartly include employment in gas marketing incountries where network and sales activities havenot yet been separated. Employment is closelyrelated to the number of customers, estimated tobe over 550 million worldwide, a great majority ofwhich in the residential and small businesssectors. The data provided in Table 20 indicate aworldwide average of about 440 users peremployee, but this number varies considerablydepending on the sectoral distribution ofcustomers.40

The development of reserves and resources

In the United States, the exploitation of natural gasfor energy purposes began over a century ago, but formany decades this source was considered the poorcousin of oil on account of its physical characteristics,exemplified by its extremely low energy content perunit volume and its dependence on a fixedinfrastructure for transport and distribution. Asubstantial proportion of resources was discoveredaccidentally during exploration and developmentactivities in the oil sector. Considered more of aimpediment than a resource, these discoveries wereoften not even recorded and were rediscovered in laterperiods.

Associated and non-associated gasIt is estimated that about 35% of known gas

resources in the 1970s were of associated gas(CEDIGAZ, 1997-2004, year 2000), that is gasdissolved in crude oil or filling the cavities aboveoil reservoirs and which inevitably escaped whenthe oil was extracted. The high cost of downstreamuse did not justify its recovery, except for specificlocal activities, mostly in industry. Before thegreat depression of the 1930s, significant gas production occurred only in the United



40 Not surprisingly, the number of customers peremployee is lower in areas dominated by residential uses,reflecting winter heating.

Table 20. Employment in gas transportation and distribution in 2003(figures estimated on the basis of data from CEDIGAZ, 2004; Eurogas, 2005; various enterprises)

World regionsEmployment (103)

Users (106)Users peremployee

km of pipeline per employee

Transportation Distribution Total Transportation Distribution

United States and Canada 22 505 527 170.5 323 22.8 3.8

Japan and Oceania 3 21 24 22.5 919 6.2 6.3

Europe 15 313 328 123.3 376 17.3 5.0


14 222 236 109.8 465 16.4 4.0

Asia 5 52 57 45.3 792 8.5 5.9

Middle East 4 25 29 46.2 1,603 6.8 4.4

Africa 3 14 17 12.7 746 7.0 3.7

Latin America 5 39 44 27.2 616 9.1 4.3

World 72 1,191 1,263 557.6 441 16.1 4.3

States41 as a replacement for town gas, producedfrom coal, to meet urban demand.

At least until the middle of the Twentieth century,associated gas from oil reservoirs, of no economicvalue, was flared at the wellhead, contributing topollution and (unknowingly at the time) to theproduction of greenhouse gases. In the United States,oil production without recovery and treatment of theassociated gas was prohibited beginning in 1947, butin the rest of the world over 30% of the natural gasproduced continued to be flared into the atmosphere,and far more in some countries like Saudi Arabia.42

During the 1950s (mainly in the United States),reinjection to improve oil recovery began to spreadand gas was used to some extent for field operations,including power generation. In recent years, newopportunities have emerged such as the use oftechnologies for conversion of gas to liquids; thoughcostly to produce, these entail far lower transportcosts.

During the 1970s, the strong increase in oil pricesled to a re-evaluation of natural gas resources as a

replacement for oil in many uses and interest in therecovery of associated gas from oil fields as well as innon-associated gas development grew in manyproducing countries. A number of Middle Easternproducers developed local industries based on naturalgas, particularly in the petrochemical sector, and usedgas for electricity generation and in the residentialsector. Numerous large projects for pipeline exportwere conceived, and international transport based onliquefied natural gas took off.

However, gas losses remain significant in manyproducing countries, due mainly to the lack ofeconomic alternatives for their use but also becausereinjection, in any case, represents a cost. On a worldscale, marketing as a fraction of wellhead production



41 Most of the resources known in the United States atthat time were of associated gas.

42 It is estimated that since the beginning of resourceexploitation over 15,000 billion m3 of natural gas (almost5% of currently known original resources) have been wastedin this way.

* Corresponds to total production in the raw form before combustion or venting into the atmosphere, reinjection, treatment andself-consumption. Losses during the treatment phase include purification and the extraction of liquid fractions (LPG - Liquefied PetroleumGas, gasolines and other condensates). ** Consumption for the operation of treatment plants and other plants. *** The gas is sent into gaspipelines towards markets and subject to further losses (not included in the table) in gas pipelines and compressor stations before consumptionin intermediate or end-use sectors.

Table 21. Balance of gross natural gas production* between 1960 and 2004(CEDIGAZ, 1997-2004; IEA, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

Year Gross productionReinjected into

reservoirFlared or ventedinto atmosphere

Self-consumptionand other uses**

Marketedproduction***

Quantity (Gm3)1960 614 72 76 20 4461970 1,330 85 161 45 1,0401975 1,567 78 173 52 1,2641980 1,854 113 164 59 1,5191985 2,105 171 103 88 1,7421990 2,524 235 110 110 2,0681995 2,730 306 103 117 2,2042000 3,073 346 95 142 2,4902004 3,428 408 94 164 2,763

Share (%)1960 100.0 11.8 12.4 3.3 72.61970 100.0 6.4 12.1 3.3 78.21975 100.0 5.0 11.1 3.3 80.61980 100.0 6.1 8.8 3.2 81.91985 100.0 8.1 4.9 4.2 82.81990 100.0 9.3 4.4 4.4 82.01995 100.0 11.2 3.8 4.3 80.72000 100.0 11.3 3.1 4.6 81.02004 100.3 11.9 2.7 4.8 80.8

increased from an average of 73% during the 1960s,stabilizing at values close to 82% in the 1980s beforefalling slightly since the 1990s. The increase inmarketed gas up to the late 1980s is largely explainedby the significant drop in the share of associated gasflared or vented into the atmosphere and the increasein reinjected gas (Table 21), but also reflects anappreciable decline in the share of associated gas intotal production, from values above 40% in the 1960sto values close to 20% at the end of the 1980s; thiswas due above all to the growing contribution ofRussian gas to world production.43

The stabilization and slight drop in marketed gassince the 1990s is due essentially to the increasingcontribution of producing areas with reserves oflargely associated gas, especially in Africa, LatinAmerica and the Middle East. In the former tworegions, associated gas accounts for over 50% ofproven reserves, and in the latter for just under 50%.Also contributing to the drop is the increasing quantityused for gas treatment, consisting of drying,purification and extraction of liquid fractions(liquefied petroleum gas, gasoline and othercondensates) included in Table 21 under the headingSelf-consumption and other uses.

Overall, associated gas reserves represent todayabout 25% of total proven reserves.44 This figure hasfallen significantly from values of nearly 35% in the1970s, thanks to investments in areas favouring agreater preponderance of non-associated gasresources. But, as already noted, production over thepast decade and more has been growing faster inareas with associated gas resources.45 This isreflected in the balance by world regions in Table 22,

showing that in 2004 the countries of Africa, LatinAmerica and the Middle East contributed 64% ofthe gas flared, vented into the atmosphere orreinjected worldwide, as compared to a total grossproduction of only 29%.



43 Over 99% of the gas extracted from Russian fields isnon-associated gas. In contrast, almost 50% of the total gasproduction of the United States from the beginning ofexploitation up to the end of the Twentieth century was ofthe associated type.

44 A rough estimate of the share of associated gas inproven reserves in world regions is: United States andCanada 11%; Japan and Oceania 4%; Europe 16%; Russiaand other former Soviet countries 1%; Asia 9%; Middle East42%; Africa 55%; Latin America 52% (CEDIGAZ,1997-2004).

45 The case of Nigeria is well-known; here between 50and 70% of associated gas is still flared in the atmosphere.In fact, the local market is extremely limited, and onlythrough the export of liquefied gas and conversion into GTLcan this gas be monetized.

Gto

e

020406080

100120140160180

year1960 1965 1970

oilnatural gas

1975 1980 1985 1990 1995 2000

Fig. 3. World proven reserves of natural gas and oil during the period 1960-2004.

Table 22. Balance of natural gas production (Gm3) in the world regions in 2004(CEDIGAZ, 1997-2004; IEA, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

World regionsGross

productionReinjected

into reservoirFlared or ventedinto atmosphere

Self-consumptionand other uses

Marketedproduction

United States and Canada 861 108 4 34 715

Japan and Oceania 45 1 0 5 39

Europe 384 36 5 14 329

Russia and other former Soviet countries 817 0 11 13 793

Asia 339 7 7 37 288

Middle East 417 93 12 32 280

Africa 319 110 45 16 148

Latin America 246 52 10 13 171

World 3,428 408 94 164 2,763

Proven reservesRapid growth in proven reserves began in the

1970s, with the economic re-evaluation of natural gas(Fig. 3). In 1960, these amounted to 40% of those ofoil. Between 1960 and 1985 they increased 5.5 times,compared to 2.5 times for oil, corresponding to about86% of the latter in energy terms. Relative growthslowed in the following decade due to the sizeablere-evaluation of oil reserves during the second half ofthe 1980s, but then picked up again with renewedvigour; since 2000, proven reserves of natural gas havebeen larger than those of oil.46

The most eloquent indicator of the resource base isthe reserves to production ratio (R/P), whichcorresponds to the number of years of remainingproduction, assuming that both reserves andproduction remain constant over time. Worldwide, theR/P ratios for oil and gas show significantly divergenttrends, with increasing longevity of remaining gasreserves (Fig. 4). Over the course of the two decadesending in the 1970s, the R/P ratio for oil fell from 36to 27 years, compared to an increase for natural gasfrom 38 to 45 years. During the 1980s, in the newconditions emerging from the energy crises of thepreceding decade, energy savings and oil substitutiontogether with the re-evaluation of oil reserves causedthe R/P ratio for oil to rise again to about 40 years. Atthe end of the 1980s, the ratio for natural gas wasalmost 60 years and continued to grow, though at aslower rate despite the increase in proven reserves, dueto the strong increase in consumption; it seems to havestabilized at around 65 years at the beginning of thenew century. On the other hand, the R/P ratio for oilhad already stabilized around a value of 40 yearsduring the 1990s.

This worldwide trend conceals significant diversitybetween the main regions which reflect differencesboth in natural gas resources and production dynamics(Table 23). Two regions, the Middle East and Japanand Oceania, had an R/P ratio of over 100 years in2004; the former rising, the latter falling. Two regions,

Africa and Russia and the other former Sovietcountries, had an R/P ratio in 2004 of between 50 and100 years, declining in both cases. Latin America andAsia had a falling ratio, although still over 40 years,while in Europe the ratio has remained practicallyconstant for some time at just over 20 years. Of greaterconcern is the situation in the United States andCanada where the R/P ratio has now fallen to anaverage of 10 years, below which the exploitation ofresources generally becomes inefficient and damagingto reservoirs.

A very significant fraction of reserve growth hastaken place in offshore reservoirs, largely as a result ofthe availability of new exploration and developmenttechnologies. Given the higher development costs,their contribution to total proven reserves is generallydecisive in world regions where resource exploitationis most advanced (in the United States and Canada,and in Europe). However, as shown in Table 24, theirshare of total reserves has grown dramatically in allregions with the exception of Latin America, whereoffshore reserves were already prevalent in the 1970s,and of Russia and the other former Soviet countries,characterized by enormous onshore resources and avery low ratio of coastline to land area.47 Offshore gasproduction in the different world regions closelymirrors the extent of resources, as shown in Table 25.With the exception of the United States and Canada,Europe and Latin America, the R/P ratio of offshorereserves is higher, in some areas considerably higher,than that of onshore reserves (77 compared to 65 yearsworldwide).

Of greater significance for the evaluation of trendsin reserve growth is the concept of addition to reservesin a given year which, since this eliminates the effectsof different trends in consumption. Additions toreserves, calculated by adding a given year’sproduction to the difference between the provenreserves at the end and beginning of the year,48 isreported in Table 26 for each world region in the twoperiods 1970-89 and 1990-2004. The data show thatthe addition to oil and gas reserves worldwide wasbasically identical during the years under



rese

rves

/pro

duct

ion

(rem

aini

ng y

ears

)

year1960 1965 1970

oilnatural gas

1975 1980 1985 1990 1995 200010

20

30

40

50

60

70

Fig. 4. World reserves/production ratio during the period 1960-2004.

46 Data on proven reserves vary significantly fromsource to source, and above all over time. The presentassessment attempts to reconcile the three main historicalsources: CEDIGAZ, «Oil & Gas Journal», BP statisticalreview of world energy.

47 Data on offshore reserves are to be consideredapproximate given the rapid technological advances whichhave led to a constant revision of assessments.

48 Proven reserves generally refer to December 31 or(alternatively) January 1 of a given year. In any case,reserves at the beginning of a year are equivalent to thereserves existing at the end of the previous year.

consideration. However, while annual additions tonatural gas reserves increased slightly from one periodto the next (0.8%), the additions to oil reserves fellsignificantly (�12%).

Appreciable differences between world areas areapparent for natural gas, highlighting the extremesensitivity of additions to reserves to specific underlyingfactors. Foremost among these are technologicaladvances which have opened up new horizons foroffshore resources, particularly at great depths beneaththe sea surface. The quadrupling of additions over thetwo periods in Japan and Oceania (essentially inAustralia) and the significant increase in Africa and theMiddle East are particularly striking. The increase is stillpositive in the United States and Canada and in Asia, butfalls below the world average in Europe and, especially,in Latin America and in Russia and the other formerSoviet countries where it is practically halved.

ResourcesProven reserves refer to those located in known

reservoirs,49 for which there is a good degree ofcertainty that gas can be produced under thetechnological and economic conditions prevailing atthe time of the evaluation. An assessment of the futurepotential of natural gas cannot exclude a brief analysisof probable reserves and potential resources. Probablereserves are those additional reserves which are likelyto become available for production in knownreservoirs as a result of technological advances and theimproved knowledge of fields, assuming there aresuitable economic conditions for their development.Potential resources are resources whose existence can



49 A known reservoir is a reservoir that is adequatelycharacterized through seismic analyses and drilling,including information acquired during the production phase.

Table 23. Reserves, production and their R/P ratio in the world between 1970 and 2004(CEDIGAZ, 1997-2004; IEA, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

World regions and reserves 1970 1975 1980 1985 1990 1995 2000 2004

Proven reserves (Tm3)United States and Canada 9.4 8.5 8.0 8.4 7.5 6.5 6.2 7.0Japan and Oceania 0.1 0.2 0.2 0.7 1.0 1.6 2.7 4.0Europe 4.1 4.5 4.5 6.2 6.0 6.9 7.6 6.9Russia and other former Soviet countries 12.1 23.7 31.0 37.5 52.0 58.2 56.9 56.3Asia 1.5 3.1 4.6 6.3 9.6 11.5 12.1 12.3Middle East 6.6 15.3 18.5 25.8 37.8 44.6 53.9 71.6Africa 3.8 5.2 5.7 5.9 8.5 9.9 11.0 13.8Latin America 1.9 2.4 4.4 5.4 6.9 7.8 7.7 7.8World 39.4 63.1 76.9 96.3 129.3 147.1 158.2 179.8

Production (Gm3)United States and Canada 651.8 619.7 624.4 548.0 611.7 685.3 722.6 715.0Japan and Oceania 1.8 6.6 13.0 17.6 25.2 33.6 36.6 39.3Europe 115.9 223.4 248.7 252.7 237.2 271.3 302.9 328.5Russia and other former Soviet countries 198.0 289.3 434.8 643.0 814.6 705.2 723.1 792.9Asia 15.2 30.7 61.1 92.1 123.8 176.9 235.5 287.7Middle East 19.5 37.6 44.1 64.0 99.9 146.9 207.0 280.1Africa 3.4 12.5 27.2 51.3 70.9 85.1 127.8 148.3Latin America 34.5 43.7 65.5 73.5 85.0 99.6 134.9 171.2World 1,040.1 1,263.5 1,518.8 1,742.2 2,068.3 2,203.9 2,490.3 2,763.0

R/P ratio United States and Canada 14.5 13.8 12.8 15.3 12.2 9.5 8.6 9.8Japan and Oceania 42.1 33.2 15.0 40.6 40.0 47.4 72.6 102.7Europe 35.0 20.3 18.1 24.7 25.5 25.6 25.1 21.2Russia and other former Soviet countries 61.0 81.9 71.3 58.3 63.8 82.5 78.7 71.0Asia 97.1 102.4 75.3 68.5 77.2 65.2 51.5 42.8Middle East 339.4 407.5 420.1 403.8 378.7 303.9 260.3 255.5Africa 1,127.6 419.4 208.9 114.8 119.7 116.1 86.3 93.4Latin America 54.3 53.8 66.5 74.0 81.4 78.3 57.4 45.4World 37.9 49.9 50.6 55.3 62.5 66.7 63.5 65.1

be deduced only from geological knowledge, and forwhich no other data exist beyond those which can beextrapolated from known reservoirs in neighbouringareas or in other areas with similar characteristics.

The financial norms in force in most countriesoblige companies to declare the proven reserves in thereservoirs assigned to them. The evaluation ofprobable reserves is based both on oil industry dataand on comparative analyses with similar geologicalprovinces. Estimates of the extent of potentialresources are based essentially on geological analyses.While proven reserves are defined with reference to agiven historical moment in time, probable reserves andpotential resources make reference to a period ofseveral decades, during which there is a goodprobability that they will be added to proven reserves.

The data on probable reserves and potentialresources introduced below are based on the

evaluations of the US Geological Survey (USGS),one of the most authoritative institutions in thissector.50 The USGS has undertaken periodiccalculations of worldwide hydrocarbon resourcessince 1984 for oil and since 1987 for natural gas.51 Inthe most recent update, resources were estimated onthe basis of information gathered for 270 geologicalprovinces in 96 countries, referring to subsurfaceformations with a hydrocarbon content above a



50 Unlike the World Energy Council (2001) and otherinternational bodies, which only publish data on provenreserves, the USGS specializes in the evaluation of probablereserves and potential resources.

51 Specifically, five evaluations for oil and four fornatural gas. The latest USGS update (2003) also givesseparate estimates for natural gas liquids. The analyticaleffort is very extensive, involving around forty experts for aperiod of 3-5 years.

Table 24. Offshore reserves during the period 1970-2004(CEDIGAZ, 1997-2004; IEA, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

World regions and reserves 1970 1975 1980 1985 1990 1995 2000 2004

Offshore reserves (Tm3)United States and Canada 1.1 1.3 1.5 1.5 1.6 1.3 1.2 1.3Japan and Oceania 0.0 0.0 0.1 0.6 0.7 0.9 1.6 2.7Europe 0.9 1.4 2.1 3.0 3.5 4.2 5.2 5.0Russia and other former Soviet countries 0.2 0.3 0.5 0.7 1.7 3.1 3.6 4.2Asia 0.3 0.8 1.8 2.6 4.7 7.7 8.4 8.7Middle East 1.2 2.9 6.6 9.8 13.4 16.3 24.0 29.3Africa 0.2 0.3 0.6 0.8 1.2 1.8 2.2 3.0Latin America 0.7 1.0 1.6 1.8 1.7 1.8 2.1 1.8World 4.4 8.1 14.9 20.8 28.4 37.1 48.2 56.1

Total reserves (Tm3)United States and Canada 9.4 8.5 8.0 8.4 7.5 6.5 6.2 7.0Japan and Oceania 0.1 0.2 0.2 0.7 1.0 1.6 2.7 4.0Europe 4.1 4.5 4.5 6.2 6.0 6.9 7.6 6.9Russia and other former Soviet countries 12.1 23.7 31.0 37.5 52.0 58.2 56.9 56.3Asia 1.5 3.1 4.6 6.3 9.6 11.5 12.1 12.3Middle East 6.6 15.3 18.5 25.8 37.8 44.6 53.9 71.6Africa 3.8 5.2 5.7 5.9 8.5 9.9 11.0 13.8Latin America 1.9 2.4 4.4 5.4 6.9 7.8 7.7 7.8World 39.4 63.1 76.9 96.3 129.3 147.1 158.2 179.8

Share (%)United States and Canada 11.1 15.4 19.1 18.2 20.8 19.1 18.9 18.5Japan and Oceania 11.6 18.1 70.5 79.4 69.7 59.1 61.2 67.0Europe 22.2 31.6 47.3 48.6 58.2 60.5 67.8 72.0Russia and other former Soviet countries 1.2 1.2 1.6 1.8 3.2 5.3 6.3 7.5Asia 19.8 23.9 39.4 40.5 49.5 66.4 69.0 71.0Middle East 18.1 19.0 35.7 38.0 35.3 36.5 44.5 41.0Africa 3.9 6.0 10.9 13.0 13.5 18.2 20.0 22.0Latin America 34.7 44.3 35.8 33.8 25.0 23.1 27.3 23.0World 11.2 12.8 19.4 21.6 22.0 25.2 30.5 31.2

threshold which, depending on the area underexamination, ranged from 1 to 20 million bbl of oilequivalent (0.1 and 2 billion m3 of gas). The USGSassessments are restricted to the gas in conventionalhydrocarbon reservoirs, and exclude the vastquantities of methane trapped in coal-bearingformations (coalbed methane), in permafrost layersin sub-arctic areas (Siberia and Alaska) and on thesea floor, since these are not well known and areunlikely to be exploited during the coming 30 years.

The data reported in Table 27 indicate that,worldwide, by the end of 2004 just over 14% of totalnatural gas reserves originally in place had beenproduced (including gas liquids), 33% were stillavailable for production in the form of proven reservesand 19% as probable reserves in known fields.Potential resources deducible from geologicalinformation accounted for the remaining 33% of

original resources. The global distribution of probablereserves and potential resources does not differ verysignificantly from that of proven reserves. However, asmight be expected, there is clearly a greaterconcentration of potential resources compared toproven and probable reserves in areas whereexploitation is most advanced.

The degree of exploitation of original resourcesvaries considerably from region to region, passingfrom values below 5% in the Middle East, Africaand Japan and Oceania to above 20% in Europe and50% in the United States and Canada. In 2004,proven reserves accounted for 33% of total originalresources and 39% of remaining resourcesworldwide. Table 27 shows a significant disparitybetween regions in terms of the degree ofdevelopment of original resources; proven reservesrepresent about 20% of remaining original resources



Table 25. Offshore production in the world between 1970 and 2004(CEDIGAZ, 1997-2004; IEA, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004)

World regions and production 1970 1975 1980 1985 1990 1995 2000 2004

Offshore production (Gm3)United States and Canada 91.1 120.2 159.7 131.4 157.2 161.9 172.9 173.7Japan and Oceania 0.0 1.6 3.2 5.7 8.9 14.0 15.9 17.8Europe 15.9 45.2 84.1 98.7 113.8 156.9 204.8 241.1Russia and other former Soviet countries 3.5 8.0 12.7 15.9 10.9 6.5 5.2 4.8Asia 0.0 8.1 16.5 36.5 50.2 76.5 116.6 141.9Middle East 1.0 2.0 8.5 12.3 19.0 35.8 51.2 66.9Africa 0.1 0.2 1.3 3.6 3.9 4.4 11.6 12.6Latin America 10.0 11.0 16.5 20.4 28.2 39.3 50.6 71.4World 121.6 196.3 302.5 324.5 392.1 495.3 628.7 730.2

Share of total production (%)United States and Canada 14.0 19.4 25.6 24.0 25.7 23.6 23.9 24.3Japan and Oceania 0.0 24.9 24.8 32.2 35.5 41.6 43.4 45.3Europe 13.7 20.2 33.8 39.1 48.0 57.8 67.6 73.4Russia and other former Soviet countries 1.8 2.8 2.9 2.5 1.3 0.9 0.7 0.6Asia 0.0 26.2 27.0 39.7 40.5 43.3 49.5 49.3Middle East 5.1 5.3 19.3 19.2 19.0 24.4 24.7 23.9Africa 2.9 1.6 4.8 7.0 5.5 5.2 9.0 8.5Latin America 29.0 25.2 25.2 27.8 33.2 39.5 37.5 41.7World 11.7 15.5 19.9 18.6 19.0 22.5 25.3 26.4

R/P ratio United States and Canada 11.5 10.9 9.6 11.6 9.9 7.7 6.9 7.5Japan and Oceania – 24.1 42.6 100.0 78.4 67.4 106.3 152.0Europe 56.6 31.7 25.3 30.7 30.9 26.8 25.6 20.7Russia and other former Soviet countries 42.9 35.1 38.5 42.4 151.8 476.9 705.9 887.7Asia – 93.4 110.1 69.9 94.3 100.1 77.2 61.6Middle East 1,200.0 1,457.8 777.2 798.5 703.0 455.3 502.9 438.2Africa 1,500.0 1,580.9 478.1 211.9 294.9 409.1 210.5 241.7Latin America 65.0 94.8 94.5 90.1 61.5 45.8 43.7 25.0World 36.2 41.2 49.2 64.0 72.4 74.8 79.7 76.9

in Latin America and Europe, compared to 40% andover in other regions. Probable reserves are quitesizeable; worldwide, additions to reserves during thenext two or three decades in known reservoirs(probable reserves) correspond to just under 60% ofproven reserves existing at the end of 2004. It isinteresting to observe that this growth is far greaterin areas where exploitation is most advanced andwhere the subsurface is better characterised: about180% in the United States and Canada, 150% inEurope and 95% in Latin America, as opposed to60% in Russia and the other former Soviet countriesand less than 40% in the remaining regions.

Worldwide, potential resources are shared almostequally between offshore and onshore reservoirs, buttheir distribution varies significantly from region toregion (Table 28). Offshore fields account for morethan 90% of resources in Japan and Oceania and inEurope, and for less than 20% in the Middle East.About 75% of potential resources are believed to bein the form of non-associated gas. The prevalence ofnon-associated gas is confirmed in all regions andrepresents a significant reversal with respect toproven reserves and historical production, oftencharacterized by the far higher share of associatedgas. It is also interesting to note the great disparitybetween potential and proven offshore reserves(Table 24): in Russia and the other former Sovietcountries, for example, offshore reserves represent7.5% of total proven reserves but 60% of potentialresources. Finally, Table 28 highlights the importanceof natural gas liquids, which represent 18% ofpotential resources worldwide; only in the UnitedStates and Canada is the contribution of gas liquidsthought to be lower than 10%.

The USGS estimates carried out in different yearsshow a constant re-evaluation of potential resourceswhich partly mirrors that of proven reservesexamined above. A comparison of successiveestimates must necessarily exclude probable reserves,since these were not considered in evaluations priorto 2000. Table 29 shows a 40% increase in potentialresources between the 1987 and 2000 evaluations, ascompared to 85% for proven reserves. Thissignificant difference can be attributed to the highincrease in proven reserves between 1987 and 1994,



Table 26. Annual addition to proven gas and oilreserves during the period 1970-2004 (BP, 2005)

1970-2004

1970-1989

1990-2004

Ratio

Gas (Gm3)United States and Canada 522 466 593 1.27Japan and Oceania 125 55 214 3.89Europe 305 334 268 0.80Russia and other former

Soviet countries 1,711 2,180 1,117 0.51Asia 397 392 404 1.03Middle East 1,838 1,483 2,288 1.54Africa 324 239 432 1.80Latin America 233 287 165 0.58World 5,456 5,436 5,481 1.01

Oil (Gm3)World 5,433 5,778 5,111 0.88

Probable reserves and potential resources correspond to USGS evaluations. Cumulative production and proven reserves are updated to 2004with data from the IEA, 1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004.

Table 27. Extent of natural gas resources (Tm3) in the world at the end of 2004 (USGS, 2003)

World regionsCumulativeproduction

Provenreserves

Probablereserves

Potentialresources

Originalresources

United States and Canada 37.4 7.0 12.7 16.9 74.0

Japan and Oceania 0.5 4.0 1.6 4.1 10.3

Europe 8.5 6.9 10.5 13.7 39.5

Russia and other former Soviet countries 18.0 56.3 35.3 52.0 161.5

Asia 4.5 12.3 7.4 13.1 37.4

Middle East 3.7 71.6 23.3 48.0 146.6

Africa 1.8 13.8 5.5 12.4 33.6

Latin America 3.4 7.8 7.3 18.9 37.3

World 77.7 179.8 103.6 179.1 540.3

while the increase between the last two evaluations isalmost identical (25%). In addition to total resourceson a world scale, Table 29 reports the increasebetween 1994 and 2004, broken down bygeographical area. The comparison shows asignificant disparity in the re-evaluations of potentialresources, with very high increases in some regions(the Middle East52 and the United States and Canada)and virtually non-existent or even negative in others(Russia and other former Soviet countries).

Geographical distribution

Attention has already been drawn to the strongincrease in the average transport distance of gas fromproducing fields to final consumption in the 1950s and1960s. Although pipelines of 2,000 km and longer



Table 28. Distribution of potential resources (Tm3) by resource type (USGS, 2003)

World regions

Location Type of reservoir Type of gas

TotalOnshore Offshore

Associatedgas

Non-associatedgas

Naturalgas

Gasliquids



Europe 1.2 12.4 1.8 11.9 11.0 2.6 13.7

Russia and other former Soviet countries 21.1 30.9 9.8 42.2 44.1 7.8 52.0

Asia 6.8 6.4 2.4 10.7 11.3 1.8 13.1

Middle East 39.3 8.7 10.6 37.4 36.5 11.6 48.0

Africa 4.7 7.7 6.1 6.3 10.0 2.4 12.4

Latin America 5.4 13.4 7.1 11.8 15.4 3.5 18.9

World 90.6 88.5 43.7 135.4 147.1 32.1 179.1

52 The reassessment of the proven reserves of the MiddleEast is particularly evident, accounting for over 70% of theincrease and due almost entirely to the reserves of Qatar.

Probable reserves are excluded as these were not evaluated by the USGS before 2000. 2004 cumulative production and proven reserves are updated with data from the IEA (1960-2004; 1971-1987; 1989-2001; 1996-2004; 2001-2004). For potential resources the variation refersto the period 1994-2000.

Table 29. Historical re-evaluation of natural gas resources (Tm3) during the period 1987-2004 (USGS, 2003)

Year Cumulative production Proven reserves Potential resources Total resources

Year of USGS evaluation1987 29.1 96.3 128.8 254.21991 39.6 110.6 135.4 285.61994 43.4 142.9 143.5 329.82000 77.7 179.8 179.1 436.7

Variation 1994-2004United States and Canada 10.3 0.6 18.5 29.4Japan and Oceania 0.5 2.5 0.6 3.7Europe 4.3 0.2 2.2 6.7Russia and other former Soviet countries 11.1 �0.8 �9.7 0.6Asia 3.0 2.2 1.3 6.5Middle East 2.6 26.5 12.5 41.6Africa 1.6 4.8 2.0 8.3Latin America 1.8 0.2 8.0 10.0World 35.2 36.1 35.6 106.9



* Degree of self-sufficiency calculated as production/consumption.

Table 30. Reserves, production and consumption by region and country in 2004 (BP, 2005)

World regionsProven

reserves(Gm3)

Production(Gm3)

Consumption(Gm3)

Degreeof self-sufficiency*

(%)

Reserves/production

Reserves/consumption

United States and Canada 6.896 725.7 736.2 98.6 9.5 9.4United States 5,293 542.9 646.7 83.9 9.7 8.2Canada 1,603 182.8 89.5 204.2 8.8 17.9

Japan and Oceania 2,539 41.6 100.3 41.5 61.0 25.3Australia 2,462 35.2 24.5 143.7 70.0 100.5Japan 40 2.8 72.2 3.9 14.2 0.6New Zealand 37 3.6 3.6 100.0 10.3 10.3

Europe 5,565 307.5 493.1 62.4 18.1 11.3Norway 2,461 78.5 4.6 1,706.5 31.4 535.0Netherlands 1,492 68.8 43.5 158.2 21.7 34.3United Kingdom 590 95.9 98.0 97.9 6.2 6.0Romania 305 13.2 18.8 70.2 23.1 16.2Germany 207 16.4 85.9 19.1 12.6 2.4Italy 188 13.0 73.3 17.7 14.5 2.6Poland 116 4.4 13.2 33.3 26.4 8.8Denmark 94 9.4 5.4 174.1 10.0 17.4Hungary 34 2.9 13.0 22.6 11.6 2.6Ireland 20 0.7 4.1 16.4 29.7 4.9Austria 15 2.1 9.5 22.0 7.2 1.6Slovakia 15 0.2 6.8 2.9 76.5 2.2France 14 1.6 44.7 3.5 8.9 0.3Other countries 14 0.4 72.3 0.6 34.5 0.2

Russia and other former Soviet countries 58,235 740.9 561.3 132.0 78.6 103.8Russia 48,000 589.1 402.1 146.5 81.5 119.4Kazakhstan 3,000 18.5 15.2 121.7 162.2 197.4Turkmenistan 2,900 54.6 15.5 352.3 53.1 187.1Uzbekistan 1,860 55.8 49.3 113.2 33.3 37.7Azerbaijan 1,370 4.6 8.5 54.1 297.8 161.2Ukraine 1,105 18.3 70.7 25.9 60.4 15.6Other countries 454 11 32 34.6 40.7 14.1

Asia 11,781 287.6 274.4 104.8 41.0 42.9Indonesia 2,557 73.3 33.7 217.5 34.9 75.9Malaysia 2,464 53.9 33.2 162.3 45.7 74.2China 2,229 40.8 39.0 104.6 54.6 57.2India 854 29.4 32.1 91.6 29.0 26.6Pakistan 790 23.2 25.7 90.3 34.1 30.7Burma-Myanmar 445 7.4 1.3 586.8 60.1 352.9Bangladesh 436 13.2 13.2 100.0 33.0 33.0Thailand 430 20.3 28.7 70.7 21.2 15.0Brunei 345 12.1 2.3 536.3 28.5 152.9Vietnam 235 4.2 3.3 126.1 56.0 70.5Philippines 107 2.1 2.5 83.8 51.0 42.8Other countries 889 7,7 59,5 68,3 192,7 82,5

Middle East 72,723 283.1 288.3 98.2 256.9 252.2Iran 27,570 85.5 87.1 98.2 322.5 316.5Qatar 25,783 39.2 15.1 259.6 657.7 1,707.5Saudi Arabia 6,754 64.0 64.0 100.0 105.5 105.5United Arab Emirates 6,060 45.8 39.6 115.7 132.3 153.0Iraq 3,113 2.5 2.5 100.0 1,225.6 1,225.1Kuwait 1,572 9.7 9.7 100.0 162.1 162.1Oman 990 17.6 8.8 199.0 56.3 111.9Yemen 478 0.0 0.0 – – –Syria 250 5.2 5.9 88.9 48.1 42.7Other countries 153 13.6 55.6 24.4 11.3 2.8

Africa 13,942 145.1 82.6 175.7 96.1 168.8Nigeria 4,997 20.6 7.7 268.0 242.6 650.1Algeria 4,545 82.0 21.2 386.8 55.4 214.4Egypt 1,725 26.8 25.7 104.3 64.4 67.1Libya 1,491 7.0 6.3 111.4 213.0 237.3Other countries 1,184 8.7 21.7 40.1 136.1 54.6

Latin America 7,509 169.3 180.6 93.7 44.4 41.6Venezuela 4,219 28.1 28.1 100.0 150.1 150.1Bolivia 782 8.5 2.4 356.7 92.0 328.2Argentina 613 44.9 37.9 118.5 13.7 16.2Trinidad and Tobago 588 27.7 12.0 230.2 21.2 48.9Mexico 421 37.1 48.2 77.0 11.3 8.7Peru 247 0.9 0.9 95.3 287.9 274.4Brazil 245 11.1 18.9 58.7 22.1 13.0Colombia 114 6.4 6.3 101.6 17.8 18.1Chile 108 2.1 8.3 25.6 50.8 13.0Other countries 172 2.5 17.6 14.2 68.8 9.8

World 179,190 2,700.8 2,716.8 99.4 66.3 66.0

were already in use before 196053, gas was producedand used almost entirely within national borders; onlyafter 1970, with increasing international trade, did theaverage length exceed 1,000 km worldwide. Over thelast thirty years, growing requirements in anincreasing number of countries, compared to thestrong concentration of proven reserves in limitedareas of the world, have led to a growing geographicalimbalance between demand and supply and a rapidincrease in transport distances.

The gap between consumption, production andreserves, observed for the world macro-regions, iseven more marked in individual countries withinthe various regions (Table 30) and is certain toincrease over the coming decades. The followingevaluation of the future logistics of natural gas, isdrawn from the IEA’s demand and supply scenario,

used for the most recent investment forecasts to2030 (IEA, 2003a). These forecasts indicate theappearance of numerous new transport routesbetween producing and consuming countries, bothvia pipeline and LNG tanker. In many cases, naturalbarriers in the form of mountain ranges and thepresence of oceans favour transport in liquefiedform, and this is predicted to double its contributionto almost 50% of total transport during the periodunder consideration.

A quantification of foreseen developments ininternational transport are compared with historical



53 However, only the Transcanadian gas pipelinestransporting gas from fields in Alberta and British Columbiato Oregon and California, built in 1957 and 1958, envisagedinternational transport.

Distances refer to individual importing countries. The reported data include imports and transportation between countries within each region,including the former Soviet Republics.

Table 31. Average distance travelled by natural gas from origin to destination by importing area(IEA, Natural gas information, 2004)

Transportationand world importing regions

Quantities imported (Gm3) Average distance (km)

1983 2004 2030 1983 2004 2030

Gas pipelineUnited States and Canada 22 111 104 1,441 1,525 1,427Japan and Oceania – – 8 – – 1,794Europe 120 323 486 1,653 1,754 1,883Russia and other former Soviet countries 84 115 145 1,763 1,794 1,850Asia – 15 67 – 540 2,237Middle East – 25 50 – 947 700Africa – 1 15 – 90 2,500Latin America 2 27 70 2,970 1,065 1,300World 227 617 944 1,685 1,623 1,756

LNG tankerUnited States and Canada 3 18 365 6,130 5,105 9,660Japan and Oceania 26 77 132 5,335 6,195 7,142Europe 13 36 257 1,875 3,979 5,783Russia and other former Soviet countries – – – – – –Asia – 42 120 – 5,553 4,366Middle East – 4 9 – 4,484 2,750Africa – – – – – –Latin America – 1 7 – 760 2,300World 43 178 890 4,343 5,419 7,323

TotalUnited States and Canada 25 129 468 2,065 2,037 7,839Japan and Oceania 26 77 140 5,335 6,195 6,837Europe 133 358 743 1,675 1,976 3,233Russia and other former Soviet countries 84 115 145 1,763 1,794 1,850Asia – 57 187 – 4,210 3,606Middle East – 30 59 – 1,456 1,013Africa – 1 15 – 90 2,500Latin America 2 28 77 2,970 1,056 1,391World 270 795 1,834 2,106 2,473 4,457

trends in Tables 31 and 32, referring respectively toimporting and exporting regions.54 The figures indicatethat the average transport distance will almost doublefrom about 2,500 to 4,500 km during the periodconsidered, reflecting both the growing role of LNGand the increased importance of long-distance haulage(especially towards the United States and Canadaregion) and the longer transport distances on new searoutes (from Latin America and the Middle East).

On the import side, the incremental demand forinternational transport as a whole is dominated by theUnited States and Canada and by Europe, eachaccounting for over a third of the total increase,followed at a distance by Asia. Growth in LNGimports is also largely dependent on the contributionof the United States and Canada, with over 50% of thetotal increase, due to growing limitations on traditionaloverland imports from Canada. On the export side, thedata clearly highlight the increasing role played by theMiddle East, followed by Africa: taken together, they

account for almost two thirds of the increase ininternational export trade; but the contribution of LatinAmerica and of Japan and Oceania (Australia) are alsosignificant in relative terms, the latter relying entirelyon LNG technology.

2.4.4 The production function and the costs

The main elements of the natural gas system havebeen described in the above. This section focuses onthe economic aspects with the overall objective of



Distances refer to individual exporting countries. The data include exports and transportation between countries within each area, includingthe former Soviet Republics.

Table 32. Average distance travelled by natural gas from origin to destination by exporting area (IEA, 2003b)

Transportationand world exporting regions

Quantities exported (Gm3) Average distance (km)

1983 2004 2030 1983 2004 2030

Gas pipelineUnited States and Canada 20 122 95 1,525 1,416 1,525Japan and Oceania – – – – – –Europe 60 154 120 323 461 461Russia and other former Soviet countries 139 269 422 2,308 2,430 2,199Asia – 15 22 – 540 1,685Middle East 2 5 91 490 675 1,769Africa 2 37 116 2,028 1,882 2,059Latin America 4 16 79 1,837 1,583 1,195World 227 617 944 1,685 1,623 1,756

LNG tankerUnited States and Canada 1 2 – 5,686 5,686 –Japan and Oceania – 12 100 – 7,177 5,573Europe – – 6 – – 6,877Russia and other former Soviet countries – – 22 – – 9,867Asia 23 71 131 4,959 4,569 10,206Middle East 3 40 332 8,522 8,544 9,150Africa 16 39 198 2,736 3,975 4,784Latin America 0 14 101 – 3,134 3,732World 43 178 890 4,343 5,419 7,323

TotalUnited States and Canada 21 123 95 1,797 1,474 1,525Japan and Oceania – 12 100 – 7,177 5,573Europe 60 154 126 323 461 766Russia and other former Soviet countries 139 269 444 2,308 2,430 2,579Asia 23 86 153 4,959 3,854 8,980Middle East 5 45 423 4,952 7,716 7,570Africa 19 76 314 2,652 2,960 3,777Latin America 4 30 179 1,837 2,313 2,619World 270 795 1,834 2,106 2,473 4,457

54 The data on quantities reported in these tables do notalways correspond to IEA forecasts since, in order toprovide a more complete overview of pipeline transport,they include contributions to transport between countrieswithin macro-regions. The main difference concernstransport between the former Soviet countries.

estimating the costs of natural gas supply in the worldmacro-regions. The starting point is the abovementioned analysis of investments published by theIEA in 2003, the most recent and authoritative study inthis sector covering the whole world. The study refersto the period up to 2030 and addresses the issue ofinvestments as a function of energy demand growth,the economic characteristics of reserves in thedifferent world areas and technological advances inproduction and transport techniques (IEA, 2003b).

The following section briefly discusses the mainassumptions underlying the IEA investment forecastsand examines the main results. The section concludeswith a consideration of the contribution of the otherproduction factors (other than capital), to arrive at anoverall evaluation of the cost of natural gas to theend-user over the coming quarter of a century.

The investment scenario

As already mentioned, the IEA scenario refers tothe projections of demand formulated in the 2002World Energy Outlook. In the light of eventssubsequent to the IEA analysis, some of theassumptions may seem outdated or at leastdebatable;55 though not to the point of substantiallyaltering the overall results. The IEA’s assumptionsrefer to five main components: exploration andproduction; LNG transport; pipeline transport; localdistribution and underground storage.

Exploration and productionNew production capacity required worldwide to

replace the fields depleted over the course of thethirty-year period (2000-30) is over double theincrease in demand between the beginning and end ofthe period. New developments in seismic techniquesusing underground sensors, the widespread applicationof horizontal drilling and the use of multiphase pumpsin offshore environments, especially in water depths ofover 1,500 m, are expected to allow furtherimprovements in the identification of reservoirproperties and an increase in success rates.56

Although a strong increase in drilling is predictedin lower cost areas (Middle East and Africa), unit costswill tend to rise worldwide due to the development ofsmaller and more marginal reservoirs in many worldregions (United States and Canada, Europe) and thegrowing contribution of offshore reservoirs.Furthermore, in many regions enhanced recovery ofresources using thermal, chemical and biologicalprocesses will tend to increase unit costs. Finally, inmany regions, the lower quality of reserves will bereflected in the increasing investment costs in gastreatment plants.

LNG tanker transportThe increasing importance of the Middle East and

Africa as exporting areas towards Europe and NorthAmerica will stimulate the development of LNGtransport, whose contribution to international trade isexpected to increase six-fold, to approach that ofpipeline transport by 2030, with a significant increasein the utilization of liquefaction capacity. In parallel,increasing security of LNG supply sources and thegrowing role of international trade will result in betterutilization of regasification capacity.57

Advances in liquefaction and refrigerationtechnologies will contribute to lowering the unit costsof LNG transport, though less than in the past.58

Economies of scale will continue to reduce costs in thevarious parts of the LNG cycle: in liquefactionterminals through increasing capacity of the trains andnumber of trains per terminal;59 in regasificationterminals through increasing vaporizer capacities andstorage tank size; in LNG tankers through anincreasing number of refrigeration chambers.60

Increasing recourse to offshore liquefaction andregasification terminals is reflected in constructioncosts which are comparable to or lower than those foronshore terminals, since they are independent of portactivities and attract less public opposition.

Pipeline transportPipeline transport capacity will grow mainly as a

result of increased requirements in relatively newregions (Asia and Latin America). Growth is forecastto be stronger for export flows from producing toconsuming countries (Russia and other former Sovietcountries towards Europe and Asia; between thecountries of Latin America), but will be considerablealso for high pressure transport inside countries which



55 For example, export flows from Russia to the UnitedStates appear to be underestimated. Similarly, the increase intransport and distribution capacity and in storage capacity inJapan seems too low.

56 Over the past two decades, worldwide drilling successrates have increased from around 83% to about 93%; furtherincreases will therefore be limited.

57 As already noted, the currently low worldwideutilization of capacity (40%) can be attributed essentially toJapan, where it is barely over 30%.

58 The earliest projects consumed 15-20% of theliquefied gas; in plants of recent design, theself-consumption included in contracts has been halved to8-10%.

59 Over the 1990s, the capacity of new terminals morethan tripled from 2 to 7 million t/yr of LNG.

60 LNG tankers in the range 200 and 250,000 m3 are inthe design phase. These can be compared with the averagesize of the current world fleet (115,000 m3), of the largesttankers currently in use (137,000 m3) and of those underconstruction (145,000 m3).

have recently begun to use gas. Utilization of moreresistant materials will allow for further increases inthe diameter, pressure and transport capacity of gaspipelines, significantly cutting transport costs overlong distances. However, the large contribution andincreasing unit costs of labour (the main component ofonshore pipeline investments) will tend to limit thedecrease in unit costs.61

A very substantial increase in sub-sea gas pipelinesis foreseen, both for export (between the countries ofAsia and from the Middle East to Europe) and for theexploitation of offshore resources. However,technological advances in materials and techniques forlaying pipelines on the sea floor will continue toreduce the investment costs of sub-sea pipelinessignificantly.62

Local distributionThe increase in worldwide demand will be

concentrated in the electricity generation sector,which, given the high pressures involved, normallyrequires direct connection to transport lines. Incountries which have recently begun to use natural gas(especially in Africa, Asia and many parts of LatinAmerica), relatively favourable climates oftenpreclude the widespread use of winter heating and,therefore, reduce the convenience of buildingextensive networks to supply the residential (andcommercial) sectors. In these countries, investments inlocal distribution networks will be aimed mainly at theindustrial sector, with lower unit costs.

Technological advances are unlikely to affect theunit cost of distribution networks significantly;however, investment costs will vary considerablybetween the various world regions and individualcountries, as a function of the cost of labour and theprevailing supply sector (residential and commercialas opposed to power generation and industry).63

Underground storageThe increase in underground storage capacity will

be concentrated in countries with cold winters,requiring seasonal demand balancing. Significantdevelopment is also forecast for some exportingcountries (especially in the case of associated gas) andtransit countries. The construction of new storagecapacity will also be driven by the liberalization of gasmarkets, which encourages short-term sales, temporaryparking of gas in storage facilities to take advantage ofarbitrage opportunities. The impact of technologicaladvances in upstream oil and gas development oninvestment costs in storage facilities will tend to becounterbalanced by more restrictive environmental andsafety regulations in most of the world, and nosignificant variations in unit costs are predicted.

Supply costs in 2030

The results of the IEA study are summarized inTable 33, with reference to all the main costcomponents in terms of three fundamental parameters:the increase in capacity of the various components ofthe global supply system between 2000 and 2030; therelated total investments; the specific unit investments.

The overall results show that 55% of investmentsworldwide are required to develop productioncapacity. Pipeline transport accounts for 18% ofoverall investments compared to only 8% for LNGtransport (inclusive of LNG tankers and liquefactionand regasification terminals), despite the far morerapid growth of the latter.64 Local distributionaccounts for 16% and storage for 3% of the total.These figures vary significantly from region to region,depending above all on investment costs in explorationand production and in transport infrastructure; thoughthese often have contrasting effects.

The most interesting data concern unit investments,which appear highly diversified in different regions.The overall unit investment along the whole natural gaschain ranges from a minimum of dollars 235,000/Mm3

per year in the Middle East to a maximum of dollars1,369,000/Mm3 per year in the United States andCanada. Here, too, the main difference can beattributed to exploration and production costs, whichrange from a minimum of dollars 220,000/Mm3 peryear in the Middle East and dollars 335,000/Mm3 peryear in Africa, to a maximum of dollars4,600,000/Mm3 per year in Europe. The significant



61 The contribution of labour costs varies considerablybetween countries and world regions. For example, in theUnited States, the average investment cost for onshore gaspipelines increased from 470,000 to 760,000 dollar/kmbetween 1990 and 2000, essentially due to the increase inthe cost of labour, which currently accounts for about 50%of the total unit cost. In China and other developingcountries, the cost of labour currently contributes about 10%to the total cost, but this is likely to increase significantly inthe future.

62 The data available for the United States suggest thatunit costs halved (from 1,800,000 to 900,000 dollar/km)between 1990 and 2000; the contribution of labour fell fromabout 850,000 to 400,000 dollar/km, while the contributionof materials fell from about 600,000 to 200,000 dollar/km.

63 The contribution of labour costs is inverselyproportional to the diameter of the pipes, and is thereforesignificantly higher for networks aimed at the residentialand commercial sectors.

64 The incremental capacity is similar for both forms oftransportation (about 900 Gm3/yr between 2000 and 2030),but the larger investments in replacing old gas pipelinesshould be taken into consideration, especially in the regionswhich developed earliest (United States and Canada, Russiaand other former Soviet countries, Europe).

differences between regions in the unit costs of localdistribution reflect the greater concentration ofinvestments in the industrial (rather than residential)sector in areas with relatively warm winters.

The supply costs reported in Table 34 have beenestimated from the IEA investment forecasts,considering depreciation expenses, operating costs(materials and labour) and natural gas consumptionand losses, present in almost all phases of the cycle.65

The data reported are mean values centred around theyear 2030, and reflect the costs incurred along thewhole natural gas chain.66 The cost to the end-userdistinguishes between gas produced and consumedwithin a country, gas imported by pipeline and gasimported as LNG. The cost takes account of the matrix

of international flows identified by the IEA. However,while the IEA only considers trade between differentworld regions, the estimates reported in Table 34 alsoinclude trade between countries within individualregions.67



65 Based on parameters widely employed inprefeasibility studies in the gas industry.

66 The assessment is inevitably sensitive to theparameters used to estimate operating costs, but notexcessively so. For example, an overall increase in thedepreciation period of 10% increases supply costs by 5%,whereas a reduction of 10% in gas consumption and lossesdecreases costs by only 2%.

67 The largest differences concern flows within Europe,the countries of the former Soviet Union and Asia.

* Transmission and distribution are expressed in 103 km. ** Sea transportation is shared among regions proportionally to the capacity of (or investments in) liquefaction terminals.

Table 33. Investments in natural gas supply capacity (2000-2030) (IEA 2003b)

Variables and world regionsExploration

and developmentLiquefaction Regasification Transmission Distribution Storage

Tankertransportation**

Total

Incremental capacity (Gm3)United States and Canada 124 0 420 216 827 80 0 624Japan and Oceania 84 90 56 13 14 6 75 312Europe 55 6 268 139 693 84 5 418Russia and other former

Soviet countries 500 22 0 167 535 129 18 669Asia 478 82 139 119 827 30 69 797Middle East 638 335 5 95 202 19 280 1,276Africa 459 192 0 66 57 2 160 813Latin America 429 107 0 88 356 6 89 632World 2,767 834 888 903 3,510 356 697 5,542

Total investments (109 $)United States and Canada 509 0 32 118 182 13 0 854Japan and Oceania 47 12 7 15 13 2 7 103Europe 252 1 19 83 113 23 1 491Russia and other former

Soviet countries 271 3 0 117 50 39 2 481Asia 200 11 8 76 74 10 7 386Middle East 139 47 0 65 15 5 28 299Africa 153 27 0 33 3 0 16 232Latin America 159 14 0 51 40 2 8 275World 1,730 115 66 558 489 94 68 3,120

Average unit investment (103 $/Mm3·yr or 103 $/km)United States and Canada 4,105 – 76 546 220 163 – 1,369Japan and Oceania 560 133 123 1,112 953 299 94 330Europe 4,595 167 70 597 163 274 118 1,173Russia and other former

Soviet countries 542 136 – 703 93 298 96 719Asia 418 134 59 642 89 340 95 484Middle East 218 140 74 688 74 273 99 235Africa 333 141 – 500 53 – 99 285Latin America 371 131 – 575 113 319 93 434World 625 138 75 618 139 263 98 563

The average worldwide cost resulting from thisexercise in 2030 is 1.7 dollar/MBtu. This cost refers tothe end-user and varies significantly from one worldregion to another, both due to domestic production andsupply costs and the different contribution of domesticproduction and imports. The costs range from aminimum of 1.0 dollar/MBtu in the Middle East and inRussia and the other former Soviet countries, to amaximum of 2.0 and 2.6 dollar/MBtu in Europe andthe United States and Canada respectively. Given themethod of estimation, these results only reflectproduction costs and do not include any economicmargin in the various components of the gas chain.Actual market prices reflect the market conditions ofcrude oil, oil products and other fuels with whichnatural gas is in competition, as well as the indexingmechanisms established in supply contracts. For acomparison, reference can be made to the mean priceof the gas imported in the United States and Canada,in Europe and in Japan and Oceania, which averaged5.0, 3.9 and 4.8 dollar/MBtu, respectively, in 2003.

Table 35 shows the significant contribution ofinvestment costs to the total cost of supplying naturalgas to the end-user. Over the whole chain this amountsto 50% worldwide, ranging from a minimum of 43%in the United States and Canada to a maximum of 55%in Africa. The far stronger variations for individualcomponents of the chain reflect the varyingcontribution and cost of labour and materials indifferent parts of the world, as well as differences ingas consumption and losses along the chain.Specifically, these range from a minimum contribution

of 23% for local distribution in the United States andCanada to a maximum of 61% for exploration andproduction in Asia. Worldwide, the highest share ofinvestment costs is in exploration and production at56% and transmission at 55%. These are followed byregasification at 48%, liquefaction at 47% and storageat 44%. LNG transport and local distribution have alower share, around 30%, due both to the highercontribution of the labour factor and the consumptionof materials, including natural gas itself.

2.4.5 From regional to global markets

Definition of a global marketMarkets are global when it is possible to purchase

commodities anywhere in the world and at any time, inany quantity and for any period of time, based on theprice resulting from the unrestricted balance of supplyand demand on a global level. Markets are not globalwhen they are segmented on account of productquality differentiation by constraints in transportsystems or obstacles of a commercial, regulatory orfiscal nature.

In the case of oil, the convenience of sea transportbetween different parts of the world has, from theoutset, allowed for a high degree of flexibility in flowsbetween origin and destination. Longer-term contractsfor oil and its derivatives exist, but from the mid-1980soil tanker cargoes have increasingly been purchased atspot prices determined on international markets (New



Imports include flows between countries within individual regions.

Table 34. Average unit cost to the end-user in 2030 by form of supply (IEA, 2003b)

World regions

Supply (Gm3) Average cost ($/103)Total

average cost($/MBtu)Domestic

ImportsTotal Domestic

ImportsTotal

By pipeline As LNG By pipeline As LNG

United States and Canada 768 98 248 1,114 97 71 55 85 2.6

Japan and Oceania 93 5 108 206 40 31 51 46 1.4

Europe 314 410 181 905 101 45 54 66 2.0


739 127 0 867 33 32 0 33 1.0

Asia 547 49 91 686 43 31 62 45 1.4

Middle East 377 40 7 424 32 21 49 31 1.0

Africa 186 10 0 197 41 40 0 41 1.2

Latin America 368 54 5 427 47 36 60 46 1.4

World 3,391 794 640 4,825 58 43 55 55 1.7

York Mercantile EXchange or NYMEX and theInternational Oil Exchange or IPE). In the case of oil,CIF (Cost, Insurance and Freight) prices in differentparts of the world are correlated and price differencesessentially reflect differences in quality (Table 36).

Natural gas is quoted on the commodities markets(Henry Hub in the United States, National BalancingPoint in the United Kingdom, Zeebrugge in Belgium),but at prices which have an exclusively regional orlocal consequence, since the infrastructures suited tomanaging interregional transport in real time are notnormally in place. They would need to be planned andimplemented years in advance. The lack of suitabletransport infrastructures precludes price discoveryreflecting the balance between supply and demand ona global scale, because of restrictions on the free flow

of gas between origin and destination. Gas prices inthe world’s main regions are far less correlated thanthose of oil, especially as far as monthly variations areconcerned (Table 36).

Current market regionsIt is possible to identify three distinct regional gas

markets characterized by different mechanisms forprice determination. The US market is dominated bygas to gas competition, with prices indexed at theHenry Hub; these reflect the balance between supplyand demand and are therefore extremely volatile. TheJapanese market continues to be dominated by take orpay contracts, aimed at guaranteeing security andcontinuity of supply, with rigid price formulas indexedto a basket of oil products. In the European market,long-term indexed contracts prevail, but the greaterpotential for renegotiation and ongoing deregulationare gradually encouraging competition and affectingprice formation, albeit in a still limited way.

The role of LNGThe globalization of the natural gas market is

generally associated with the development of LNG,since this does not depend on rigid infrastructureswhich constrain the origin and destination of gas, as isthe case for pipelines. Globalization would also bepossible in the case of pipeline transport, were thetechnical and commercial conditions such as to allowrerouting the gas between different parts of thenetwork. Highly meshed networks, such as those inplace in Europe and the US, only allow for the creationof regional markets since the transport capacity to



Table 35. Percentage values of depreciation in supply costs (IEA, 2003b)

World regionsExploration

anddevelopment

Liquefaction Regasification Transmission Distribution StorageSea

transportationTotal

United Statesand Canada

49 – 46 53 23 38 – 43

Japan and Oceania 55 45 50 54 35 51 36 50

Europe 52 46 47 53 26 41 32 45


57 47 – 52 29 45 30 53

Asia 61 48 50 55 32 48 33 53

Middle East 58 47 48 56 30 46 28 51

Africa 58 47 – 58 30 – 31 55

Latin America 51 43 – 50 25 39 30 46

World 56 47 48 55 29 44 32 50

table 36. Correlation of the average CIFprice and its variations in the major importing areas(data based on IEA statistics referring to the period

January 1993-June 2005)

Natural gas Oil

Monthly value (%)United States and EU-15 76.1 99.5United States and Japan 76.3 98.5EU-15 and Japan 86.2 98.4

Monthly variation (%)United States and EU-15 25.9 92.4United States and Japan 7.6 58.5EU-15 and Japan 36.4 42.0

other world regions is insufficient. However, theEuropean market cannot be considered a genuineregional market as long as it continues to besegmented on a country by country basis by take orpay contracts, destination clauses, price indexingformulas and other restrictions which prevent theemergence of a true market.

In the case of LNG, transport costs have asignificant impact on final prices, and proximitybetween producing and consuming countries providesa strategic advantage in contract negotiations.Currently, the main transport flows identify tworegional LNG markets: the Asia-Pacific basin,revolving around Indonesian, Malaysian andAustralian suppliers; and the Atlantic basin,comprising the producers of North Africa and LatinAmerica. Trade flows from the Middle East towardsAsia, Europe and the United States are still notsufficiently important to form a separate market andtend to follow the pricing logic of these two basins.

The development of LNG projectsLNG projects originally had, and in part still have,

an integrated structure from production to liquefaction,sea transport and regasification, with marketing basedon CIF contracts. The need to share risks has generallyled to different forms of joint participation in theupstream segment of the chain (production, liquefactionand storage, transport and marketing), corresponding tothe sale of LNG, and in the downstream segment(storage and regasification, distribution and retail sales)corresponding to its purchase.

In this context, the structure of participation in theupstream segment is particularly relevant.Liquefaction and storage are typically managed in ajoint venture between the production companies (thestate companies of producing countries, internationaloil companies), the purchasing concerns and financialinstitutions. Transport is entrusted to a commercialmaritime company which is usually partly owned bythe same parties operating in the liquefaction phase.

The 1990s saw the emergence of various partiallynon-integrated projects characterized by the separationof sea transport from production and liquefaction, withthe purchase of LNG on the basis of FOB (Free OnBoard) contracts. Decoupling sea transport from theother components allowed for greater flexibility andopportunities for consuming countries, whosecompanies entered into the ownership andmanagement of LNG shipping. Sometimes thesecompanies obtained a minority share in upstreamdevelopment projects in order to increase the securityof supply and gain greater control over prices. At thesame time, oil companies also began to own shares inthe sea transport and regasification phases.

More recently, independent concerns are taking theopportunity for greater involvement in the ownershipof maritime companies, decoupled from specificsupply chains, with the objective of supplying spot orshort-term markets. Based on forecasts of strong LNGgrowth, some independent companies have evenunderwritten purchase contracts without a specificmarket outlet (Wood, 2005). The most recentdevelopments suggest the possible extension of thetolling model to liquefaction plants, with theseparation of production from liquefaction. However,it is also true that these liberalising developments arein part counterbalanced by the need to ensure a returnon investments.68

Despite the increasing flexibility of the LNGmarket, it is unlikely that merchant facilities willbecome established in the near future. Indeed, theparticipation of purchasers bound by take or paycontracts, at least for a part of the total production,still remains a critical element in the development of aliquefaction project.

Surplus capacity and spot marketsOver the past decade, the Atlantic basin has seen

increased flexibility in the gas market induced by thehigh prices of the gas sold on the US market (after2000) and the liberalization process under way inEurope (since 1998). After almost twenty years ofinactivity, regasification terminals on the Atlanticcoast of the United States, have again begun tooperate at full capacity; with the major differencethat they no longer work exclusively with referenceto long-term contracts, but on the basis of short-termcontracts and spot sales based on the pricedetermined at Henry Hub. This logic has alsoaffected the European market, which has seen anincrease in re-routing of LNG cargoes originallydestined for Europe (especially Spain) towards theUnited States since 2001.

While the focus in the Atlantic basin hasincreasingly turned to prices, in the Pacific basin thealmost exclusive link with LNG has continued tofavour long-term take or pay contracts, for reasonslinked to security and reliability of supply. Even in thismarket, however, spot sales and short-term sales havebegun to emerge, as a result of contingencies (such asthe temporary closure of the Arun plant in Indonesia),which have had the merit of showing the sustainabilityof more flexible forms of supply. The Japanese



68 See, for example, the exemption from third-partyaccess granted by the Federal Energy RegulatoryCommission, FERC, to the United States Hackberry plant in order to encourage investments in regasification (FERC, 2002).

utilities, which own most of the regasificationterminals, have for some years been pushing forgreater contractual flexibility, based on a mix of short,medium and long-term contracts, aimed on the onehand at safeguarding the profitability of investmentsand the security of supply, and on the other atbalancing fluctuations in demand. Also, some Asianand Australian suppliers have shown a greaterwillingness to move towards shorter term take or paycontracts (5 years as opposed to the two decades oftraditional contracts).69

The increase in short-term contracts and spot salesis due to both short-term factors (the Asian crisis of1999, the shut-down of liquefaction terminals, theinterruption of nuclear plants in Japan, high priceincreases in the United States) and structural factors(surplus liquefaction and regasification capacity, greatercommercial flexibility in Europe with the gradualelimination of destination clauses). The growing gapbetween the capacity of plants and their actualutilization has already been mentioned (Table 16). Inthe case of liquefaction, surplus capacity was in theorder of about 25 Gm3 in 2004. In the case ofregasification, the surplus of 250 Gm3 was concentratedin Japan but was also significant in other areas.

Overall, it can be seen that the share of spot andshort-term sales on worldwide LNG markets has risenfrom 1% in 1992 to about 9% in 2004. The stronggrowth in recent years has essentially been determinedby the American market, where spot suppliesaccounted for about 50% of world spot purchases in2001 and 90% in 2004.70

Towards a global marketBetween 1950 and 1980 gas markets developed

from basically national to regional and it is almostcertain that by 2030 they will have evolved fromregional to global. This depends essentially on thedevelopment of international trade in liquefied gas.However, for a genuinely global LNG market todevelop a gradual convergence of market practices inthe three large regional markets is required. In theJapan and Oceania region, in Asia and in Europe, thereis a need for greater flexibility in pricing mechanisms;in the United States, a greater reliance on long-termcontracts might facilitate the construction of importterminals.

The forecast surplus capacity in the LNG chainshould facilitate a higher degree of liberalization inLNG trade with the creation of a global market overthe next two decades. Current expansion plans indicatean ongoing gap between the supply and demand forliquefaction and regasification capacity, although thisseems certain to be smaller than in the past.Furthermore, in the future, increasing sea transport

capacity decoupled from specific long-term supplycontracts appears to be a likely outcome.71

Overall, it is clear that over the coming decadecontractual flexibility will increasingly become thestrategic element in capturing new market share,driven by the growing importance of the US market. Inthis context, the forecast development of newregasification terminals on the Pacific coast issignificant; this should transmit liberalization trends toAsia and to the Japan and Oceania basin.72

Supply arbitrage will be determined by the need toexploit the capacity of producing country terminalsand the price differential between different markets,especially with respect to the US market, as has beenseen in recent years with LNG cargoes re-routed fromEuropean ports towards the United States, and theincrease in prices at the Zeebrugge terminal, the mainLNG hub in Europe. This trend also affects Australia,which is expanding its liquefaction terminals,especially with a view to serving the US market.

Although globalization depends on thedevelopment of LNG, it is not limited to LNG. In fact,growing competition from LNG will tend to bringglobalization also to pipeline trade.

References

Baker Hughes (2005) BHI International rig count, BakerHughes.

BP (British Petroleum) (2005) BP statistical review of worldenergy, London, BP.

CEDIGAZ (Centre International d’Information sur le Gaznaturel et tous Hydrocarbures Gazeux) (1997-2004) Naturalgas in the world, Rueil-Malmaison, CEDIGAZ.

CEDIGAZ (Centre International d’Information sur le Gaznaturel et tous Hydrocarbures Gazeux) (2004) LNG tradeand infrastructures, Rueil-Malmaison, Institut Français duPétrole.



69 The contract between the Malaysian MLNG Tiga andsome Japanese utilities, which involves a fixed long-termsupply for 60% of the volume, and annual contracts for theremaining 40% is significant in this context.

70 Short-term supply accounted for 64% of LNG importsto the United States in 2001 and 71% in 2004 (CEDIGAZ,2004).

71 Malpensa (2002) notes that already in 2000 BP hadordered three large LNG tankers (and an option on theconstruction of another two) without specifying either theorigin or destination of the LNG. In 2004, 15 LNG tankersnot covered by specific supply agreements were in variousphases of construction.

72 At the end of 2004, 6 regasification terminals wereplanned for the Pacific coast, with an annual capacity ofabout 50 Gm3. These terminals represent 15% of the entireregasification capacity currently in use or in the constructionor planning phase in the United States.

Eurogas (2005) Annual report 2004-05, Eurogas.FERC (US Federal Energy Regulatory Commission) (2002)

Hackberry LNG Terminal, L.L.C.: preliminary determinationon non-environmental issues, FERC Order 3049, 18December.

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IEA (International Energy Agency) (2003a) World energyoutlook 2002, Paris, Organization for Economic Cooperationand Development/IEA.

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investment outlook 2003, Paris, Organization for EconomicCooperation and Development/IEA.

IOGCC (Interstate Oil & Gas Compact Commission) (2005)Marginal oil and natural gas. American energy for theamerican dream, 2005 Report.

Malpensa M. (2002) Il mercato LNG: la nuova frontiera,«Energia», 23, 60-73.

UNECE (United Nations Economic Commission for Europe)(1999) Study on underground gas storage in Europe andcentral Asia, New York, United Nations.

USGS (United States Geological Survey) (2003) Worldpetroleum assessment 2000. Description and results, Reston(VA), USGS.

WEC (World Energy Council) (2001) Survey of energyresources, London, WEC.

Worldwide gas processing survey (2005), «Oil & Gas Journal».Wood D. (2005) Where we are: relationships, contracts

evolve along the supply chain, «Oil & Gas Journal», 103,54-59.

Oliviero BernardiniAutorità per l’Energia Elettrica e il Gas

Milan, Italy



2.4 the economics of natural gas - treccani...2.4.1 introduction over recent decades, natural gas...

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