Gas transportation, geopolitics and future market structure

Yuri Yegorov *, Franz Wirl

University of Vienna, Faculty of Business, Economics and Statistics, Department of Industry, Energy and Environment, Brunner Strasse 72, A- 1210, Vienna, Austria

1. Introduction. Factors influencing future natural gas market

This article is devoted to an analytical forecast of the development of future market for natural gas, and the role ofgeopolitics and transportation technology in particular. Natural gas differs from other energies by its relatively high cost oftransportation, exceeding one for oil by factor 8. This highlights the role of costly infrastructure. Its development will dependon many highly uncertain factors, where direct investment costs play important but not overwhelmingly important role.

Futures 43 (2011) 1056–1068

A R T I C L E I N F O

Article history:

Available online 29 July 2011

A B S T R A C T

Recent studies have shown the important role of geography, politics and technology for

the evolution of markets for natural gas. Gas market differs from other markets due to high

share of transport and infrastructure costs. Since investment is location specific, it involves

also geopolitical aspects as a consequence. Future market structure becomes path

dependent on the investment decisions, particularly in gas infrastructure (pipelines and

LNG). Another important aspect that shapes future gas market is heterogeneity in reserve-

production ratios across gas producing countries that will eventually lead to the

emergence of narrow oligopoly formed by countries with the largest reserves: Russia, Iran

and Qatar. The goal of this paper is to analyse a long run gas game. There exist several time

scales, and by backward induction we arrive at the conclusion that some time during the

21st century (we name it long run) there will be an oligopoly consisting of only three major

gas reserve holders: Russia (26%), Iran (15%) and Qatar (14%). They will face the demand

from three major gas importers: EU, USA and Core Asia. While the development paths and

market structures are highly uncertain in the middle run (when temporal competition

with rivals having 3% or less of gas reserves is feasible), the cloud of uncertainty shrinks in

the long run. But investment strategies of major players in the middle run will determine

the topology of gas infrastructure in the long run. All the players have a vector of strategic

choices where geography, politics and technology set their limitations. Putting it in a

simple formal framework, we can say that players choose: intensity of exploitation and

shares of investment in transport infrastructure (LNG and location-specific pipelines).

Geographical analysis of gas fields of Russia shows that it has moderate flexibility, but still

can control the future share of LNG and pipeline flows to Europe and Asia. Pipelines to EU

are slightly preferred to pipelines to Asia but political aspects may play crucial role. Qatar

is likely to invest only in LNG, but has the flexibility in the speed of its field exploitation (it

may be lower that for Russia). Iran has the highest technological and geographical freedom

in choices. Future market structures for gas can vary from oligopolistic to monopolistic–

monopsonistic relationship, with possibly different prices.

� 2011 Published by Elsevier Ltd.

* Corresponding author.

E-mail addresses: yury.egorov@univie.ac.at (Y. Yegorov), franz.wirl@univie.ac.at (F. Wirl).

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doi:10.1016/j.futures.2011.07.005

Therefore path dependency characterizes future market structure on the basis of particular infrastructure plans, and thisselection is defined not only by cost, but to high extent by geopolitics. While gas prices are still regional (there is some priceconvergence, but we cannot talk about unique world price), the world energy market is globalized, and events in somecontinents also influence other continents. Here it is important to highlight one of important uncertainties: how fast the USdemand for natural gas imports will grow.

The big other uncertainty facing energy markets – global warming – will not decrease demand for natural gassubstantially since any reduction in carbon emissions will lower aggregate energy demand but increase the share of naturalgas mostly at the expense of coal. In short, an active policy against global warming is going to be rather favourable thanharmful for the use of natural gas.

Gas is an interesting example in which the market structure cannot be derived from pure economic aspects. Due to hugerequired investments, substantial transport costs and large heterogeneity in gas deposits and major consumption areasgeography is very important. Politics also plays an important role possibly constraining the economically optimaldevelopment. As a consequence, land locked countries (like Central Asian) have very few choices of transport routes, andgeopolitics more than economics governs the choice of pipelines including projects. Therefore, any analysis of the gasmarkets should include not only economic theory, but also geography and politics. Besides that, it is important to rememberprinciples of economics of non-renewable resources.

There exists several case studies that show how geography and politics perturb otherwise optimal economic decisions.The case study of Turkmenistan (see Olcott [15]) is a good example since it presents the case when geopolitics becomes moreimportant than economics. While Turkmenistan has substantial gas reserves, it is a land locked country, for long time havingthe only pipeline via Russia, thus giving Russia monopoly power over its gas transmission. The pipeline to Turkey via Iran wasproposed by US State Secretary A. Haig in 1993. It was never implemented, and US sanctions over Iran at present is the mainproblem here.

There is explosive growth of economic literature on natural gas in the last years. One of the reasons is that gas marketbecame hot topic among journalists, especially after the recent gas transit conflict between Ukraine and Russia. But theremight be another reason for that: understanding that gas sector is a complex system that cannot be described by purelyeconomic tools (that often give wrong policy arguments) and requires the development of interdisciplinary science. Theseideas have been first summarized in the book about geopolitics of gas [18]. There also exists policy driven literature (thatalso shows partial superiority of politics over economics for gas markets) that sets some political objective and useseconomics for its implementation. Here we can refer to dissertation of V. Putin (mentioned also in (Ericson [4])) that showsthe role of state that can make Russia an energy superpower with rising control over other countries, the argument that issuccessfully implemented into practice. Clearly, it gave rise to completely opposite trend of literature trying to show howRussia is bad and how to reduce its energy power. European agenda on Energy Security was partly implementation of thisagenda; see [5].

The recent articles in ‘‘Energy Policy’’ (Bilgin [1]) and ‘‘Eurasian Geography and Economics’’ (Ericson [4]) show thegrowing role of interdisciplinary approach in the description of markets for natural gas. Ericson [4] has the focus on thepolitical economy of network interdependence. He highlights Gazprom’s role both as a supplier of natural gas toEurope and as the core of a monopoly controlling exports of natural gas from Russia and Central Asia byexpropriating and/or blocking foreign ownership of natural gas reserves as well as production and transportationfacilities in Russia. A mutual dependence, with political overtones, exists, raising ‘‘security issues’’ for both sides of thistied ‘‘market.’’ Bilgin [1] analyses the influence of geopolitics that can perturb optimal economics plan to bring Caspiangas to Europe. In particular, he shows the vulnerability of Nabucco project, focusing on potential suppliers andassociated risks.

It is also important to consider the future of natural gas in its interplay with other energies. Bilgin [2] develops theprinciples of new energy order and sustainable energy security. He suggests the shift to new energy mix with lower share ofoil and higher share of nuclear energy and renewable. Devezas et al. [3] reconsider dynamics of primary energy sources,showing the shift from logistic substitution of energies to energy saving, and suggest that renewable and nuclear energy canreach 30% of energy portfolio by 2050.

Robert and Lennert [16] consider the consequences of oil peak for Europe. They consider two scenarios; the first(optimistic) assumes that oil peak will not take place before 2030 (and Europe has to adjust slowly to growing oilprices), the second (pessimistic) considers the case of oil peaking about 2015, with plateau phase till 2020. Authorsdiscuss both macroeconomic consequences for Europe (less competitive energy-intensive industries, relocation outsideEU) and the measures to use more renewable energy (thermal insulation, windmill parks, solar, hydrogen, nuclearenergy). European peripheral regions strongly depend on transportation (using oil), which will be under shock fromhigh oil prices. Low-cost air transport will not be maintained. The share of transport cost (and thus the price) willincrease more for peripheral regions, making them less competitive. There will be general trend away fromsuburbanization and towards more compact cities. The 2nd scenario (oil peak around 2015) will lead not only toextremely high oil prices, but also to oil scarcity at world level. The change will be too rapid and chaotic, not allowingfor planned substitution for renewable energies and new technologies (like fission). Industrial economy based on cheapoil will become obsolete. Substitution of oil for gas will be rapid (where technically available). Transportation(especially by air) will be less substitutable (in the short run there are no technologies on table). Production systemswill be re-optimized accounting for increased transport cost.

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1.1. About time scales

The more distant is the future, the more it becomes uncertain. Contrary to many other economic sectors, history playsvery important role for natural gas. It happens because infrastructure capacity limits trade flows, and its development is bothcostly and time consuming. There exist several time scales that play important role.

The first time scale, T1 (about 5 years), is characteristic time necessary to build a new strategic pipeline. The second timescale, T2 (quite fuzzy, about 20–50 years), is characteristic time for important technological changes as well as changes onpolitical landscape. The third time scale, T3 (about 30–40 years), is lifetime of pipelines. The fourth time scale, T4 (about 60–70 years) is the current reserve-production ratio for the world gas.

The middle run forecast (T1< TMR< T3) can be done on the basis of amending newly build capacities to already existing,taking into account extrapolation of trends in demand and supply. Structural changes in world economy (like unpredictedinnovations and changes in political landscape) are assumed to be small. If we turn to long run horizon, fuzziness of futureincreases substantially1. To reduce the long run forecast uncertainty, scenario approach is often used.

Hence, energy future for gas can be divided into 4 fuzzy intervals:

(a) the short run (SR) – about 5 years (T1), i.e. till 2015;(b) the middle run (MR) – about 10–20 years (T1< TMR< min{T2,T3}), 2020–2030;(c) the long run (LR) – about 30–40 years (T3), 2040–2050;(d) the very long run (VLR) – about 50–100 years (T4), 2060–2100.

During these periods the following factors are important (but of different degree):

(a) evolution of gas demand in different regions (there are projections of IEA [19,20] based on macroeconomics,demography, etc.);

(b) growth of production in different regions (more fuzzy, since it also depends on infrastructure development, that isinfluenced not only by economic factors);

(c) development of new infrastructure: those that are in the process of construction are relevant for the SR, planned – for MR,while LR depends more on political evolution and geopolitical constraints.

1.2. Focus of the paper

The focus of this paper is on long run and partly on very long run (VLR), which is complementary to related CGE modelsthat elaborate on existing and planned infrastructure and thus focus on short (SR) and middle run (MR).

In the LR existing capacities (related to particular regions) may be halved while additional demand may grow by 50–100%; thus the role of existing and planned infrastructure plays fewer roles. Geographical differences in gas reserves becomemore important (see Yegorov and Wirl [22]). As for Russia, it is a spatially large country, and its internal geographicalstructure of gas deposits is also strategically important.

In the distant future (LR), gas flows will highly depend on capacities for new gas links, some of which are even not plannedtoday. That is why it might be impossible to predict technological details of new pipelines and LNG plants, and the analysisshould be based on overall strategy of gas infrastructure development in particular countries. Fortunately for the forecast, theset of strategically important gas suppliers will be shrinking over time due to resource depletion in countries with low R/P ratios.

From the side of gas suppliers, these flows (both volume and orientation) will depend much on technological,geographical and political factors. Only Russia, Iran and Qatar have the shares of gas reserves above 10% that guarantees theirimportant role on gas market in LR and VLR. For the rest of the countries, these reserves are not more that 3–4%.

The further discussion is about some details of natural gas supply and demand in the long run. Next, we will focus onpossible development paths for new infrastructure. Once built, gas pipelines will lock in particular links between regions. Onthe other hand, new LNG plants can increase market flexibility. Long run market structure will depend on both spatialstructure of new pipelines (in particular, their West-East split) and on long run share of LNG in overall gas trade. Undercertain scenarios (influenced by not only pure economics like cost considerations, but also by geopolitics and technologicalconstraints) markets might be segmented into bilateral links between producers and consumers (that might be consistentwith some non-vanishing price difference across regions), while under other scenarios there will be unique world market,with arbitrage opportunities via substantially large non-committed LNG flows leading to unique price.

1.3. Other factors

It is never possible to include all factors. However, we want to comment on two: (a) external shocks, (b) interactionbetween different fuel markets. Both have very high volatility making predictions for future even more uncertain. Thereforewe will proceed as follows. Sections 2–4 will consider the baseline model where the future of natural is derived only from

1 For example, one can compare the predictions till 2020 done by McRay [13] in 1994 with the reality in 2010.

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natural gas, and the influence of shocks is not considered. Section 5 considers several scenarios (due to shocks andinteractions).

2. Long run future for gas supply and demand

2.1. Supply of natural gas in the long run

In the long run (and for sure in the very long run) three countries that have the largest proven gas reserves at present willdominate the market for gas export. These countries are Russia (26% of proven reserves), Iran (15%) and Qatar (14%). Thereason is the substantially lower reserves (not exceeding 3% of world reserves) for any other market participant. Here weassume political stability and no huge discoveries in new regions.

If we look at optimal development, related to technology only, there is a choice between pipeline and LNG, and pipe direction(WestorEast). Duetogeography andpolitics,Qatar’soptionsare limited toLNG technology2. Thus, itwill contributesubstantiallytoworldLNG supplies. Both Russiaand especially Iran face serious dilemmas about the choice of newinfrastructure. By2030, halfof active gas sources in Russia will be depleted, and the development of new sources will be associated with choosing newinfrastructure to connect them tomarket. There are 3 basic options: LNG, new pipelines tothe West (EU) and new pipelines totheEast. Iran has similar alternative, but contrary to Russia (that has already bulk of pipelines to EU) it does not export gas today (dueto political sanctions) and thus its future export pattern has all options (West pipe, East pipe, LNG).

In the end, geopolitics may perturb optimal technological decision (cost minimization given equal market access) byclosing some options (as it does for Iran today). Strategic considerations like influence of the speed of infrastructuredevelopment on its prices today, tomorrow and response of competitors, are also important.

2.2. Russian strategic choices

At present, Russia is the largest gas producer and exporter in the world. It also has the largest gas reserves. However, dueto severe cold climate and prices well below the world level, about 70% of produced natural gas is consumed domestically.Until recent gas quarrel with Ukraine (January 2009), Russia has exported a large fraction of gas to CIS countries at the pricesubstantially lower than in Europe. Thus, until 2008 Russia received the world price for only a small fraction (about 25%) ofproduced gas. Thus, having large reserves and high time discount (that is seen from fast expansion of oil export; now it iscomparable with one of Saudi Arabia, despite the fact that Russia has quite modest oil reserve share and low R/P ratio for oil),Russia has a clear incentive in fast increase of gas production as well as its role in the world market.

However, it faces several obstacles:

(a) New gas deposits are located in Far North (Yamal), on shelf (Shtokman and Sakhalin) and in the Centre of Eastern Siberia;in all cases both extraction and link to the market are either expensive or require new technologies for Russia, likesubmarine development and building LNG plants;

(b) In the recent years there have been substantial disagreement and growing tension in energy relations between Russiaand EU, partly as a negative externality of gas transit game between Russia and Ukraine, partly due to European concernabout energy security and its strive for diversification in supply.

That is why it makes some sense for Russia to take a strategic pause related to commitment of new costly fields (likeYamal and Shtokman) to European market. At the same time, it makes sense to diversify the set of gas importers from Russiaby development of gas deposits in Far East (Sakhalin’s shelf) with primary commitment to LNG market. This can be a shortrun strategy. However, in the middle run the core fields in Nadym will substantially depreciate and some new investmentshould be done at least to compensate otherwise reduced gas flow to Europe, simply to cope with long run contracts. Whilepart of this problem can be solved via re-export of gas from Central Asia (where Russia still has dominant position), thesituation might change already in the middle run, when Turkmenistan will be able to sell part of its gas to Europe directly (viaNabucco) and part to China by new direct pipeline.

East Siberian gas deposits are located between Baikal Lake and Yakutsk. They can be transported to Asian consumers vianew gas pipeline passing Tynda, Khabarovsk and Vladivostok. The gas deposits from the shelf zone of Sakhalin will partly goto LNG plant in Southern Sakhalin and partly to Vladivostok via pipeline [14].

Currently exploited Russian gas fields (Nadym-Pur-Taz) will peak in 2011 with about 620 bcm of annual output, and then willdecline to about half of the present output in year 2030. Thus, new fields have to be developed. The General Scheme of Gas SectorDevelopment in Russia (quoted in[14]) suggests that in year 2030 the major replacementof depleted fieldswillcome fromYamaland other fields in Western Siberia (up to 260 bcm). This will compensate declining production from Nadym (present supplier),keeping the production in these fields at 500–600 bcm/y. This gas is connected with European consumers by existing pipelines.

In the middle run, the major growth of Russian gas production by 2030 will come from Shtokman (Arctic shelf, about70 bcm/y), Far East (Sakhalin shelf, about 70 bcm/y) and East Siberia (about 30 bcm/y). It is cheaper to connect gas fields in

2 For Qatar (see [7], p. 235), cross border argument limit its possibility to export gas via pipelines, while there might be also upper limit for LNG capacity,

taking into account not too long coast line along with ecological constraints.

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East Siberia and Sakhalin with Asian consumers, although in the long (or very long) run Russia can build interconnecting linkbetween Eastern and Western Siberia to integrate its gas network and be able to arbitrage the flows. Shtokman field may beused as LNG (traded worldwide) or be connected with Europe via pipeline. The submarine part of pipeline from Shtokmanfield is much larger than for Sakhalin; this may make its development more expensive and it will be delayed comparing toSakhalin. Again, after reaching mainland (Kola Peninsula) by this pipeline, Russia has two options (land pipeline and LNGplant) and is likely to exploit both options to have more strategic flexibility in future. Thus, by year 2030 Russia mightproduce 850–900 bcm of gas, with export oriented LNG up to 100 bcm.

Gazprom3 owns 33.1 trillion cubic meter out of 47.6 trillion cubic meter of Russian gas reserves, that forms 26% of provenworld reserves (according to BP). Out of them, almost half (22.3) is located in Nadym-Pur-Taz (major production locationtoday), 10.4 trillion cubic meter in Yamal peninsula and 3.8 trillion cubic meter in Shtokman area. Kovykta and other EastSiberian deposits have about 4.1 trillion cubic meter of natural gas, while Sakhalin shelf (I and II) has 900 bcm of gas deposits.In 2004–2008, Gazprom’s production stayed at flat level close to 550 bcm, between 80% and 90% of overall gas production byRussia. In 2008, Gazprom sold 184.4 bcm of gas to Europe and 96.5 bcm of gas to CIS and Baltic states.

According to BP Statistical Review 2008, in 2007 Russia produced 607 bcm of gas, exported 147 bcm and used 439 bcm fordomestic consumption. Despite some differences between Russian and BP data on Russian gas export (that comes partlyfrom accounting in sales to CIS and non-CIS countries), it is clear that at present Russia can export 150–180 bcm of gas toEurope out of 600 bcm produced. What will happen if it will increase its production to 850–900 bcm by the year 2030?Russian estimates by Mitrova [14]4 suggest that in 2030 Russia will be able to export 360 bcm of gas, thus consuming about500 bcm of gas domestically (modest increase, since domestic prices are expected to grow). How can this export of gas besplit between Europe and Asia (and potentially USA, if we take into account new LNG plants)? An interesting question is howmuch flexibility will have Russia given its geographical possibilities and political preferences (or constraints).

First of all, Russia might deviate from its plan of relative speed of development of new gas fields. However, this decision has tobe taken in advance (5–10 years before) since development takes time. So we assume that it sticks to production plans5 fromdifferent geographical areas (described above) but will decide on export volume to different regions at the spot. We assume thatall planned pipelines and LNG plants are constructed. At present, Sakhalin is expected to produce 60 bcm of gas by 2020 andabove 70 bcm by 2030. All this gas (except for relatively small domestic consumption in this region) can be oriented to sale inAsia (mostly Japan and Korea), both in forms of pipeline gas and LNG. The gas from Shtokman is not likely to go to Asian market(too far), but part of it can go instead of Europe to USA (as LNG). Thus, Russia has high flexibility in use of these 70 bcm ofpotential export capacity, and the capacity of new LNG plants will increase this flexibility. The potential of East Siberia isrelatively high. Russia can choose to have overall gas peak close to 2040–2050, when most of countries that export gas today willstay without reserves. Now we need to consider two other largest gas reserve holders – Qatar (14%) and Iran (15%).

2.3. Qatar and Iran

According to reference scenario of Hartley and Medlock [6], world gas production will peak in 2035, with180 tcf/yr6 (about5100 bcm).In2040,Russiansupplywillbeat33 tcf(or930 bcm,slightlyaboveRussianforecast,butclosetoit).Outofthis,Russiaisbelieved toexportabout 14–16 tcf (400–450 bcm)in 2030–2040, a bit more than according toRussian scenario. Productionin theUSA will drop to 500–550 bcm, and it will need substantial gas imports to compensate it. Iran will become substantial producer,with about 500 bcm of output, most of which can be exported. Production of Qatar will stayat 170 bcm. European production willdecline. Caspian region will have production growth to 250 bcm, but it will only compensate the decline in EU production.

Here we are interested more in production of Iran and Qatar, since all other countries have below 3% of world reserveseach and cannot play important role in gas export in very long run. If we look at relative reserves of Russia, Iran and Qatartoday (26:15:14), we will see that their production levels at the time of world gas peak are not in the same proportion. Thismeans that Russia will peak first (out of 3), Iran a bit later and Qatar – very late. It is likely that Qatar has technical constraints(limited coastline, border problems) that limit its gas output. This will keep it as major supplier of LNG in the very long run.

As far as Iran is considered, we face high uncertainty. It will become definitely one of the largest gas exporters(comparable with Russia). At the same time, the direction of its export is highly uncertain. Since at present it has no export, infuture Iran is free to choose between pipeline export to West, to East and development of LNG. Also, there is time uncertaintyfor Iran with the development of gas project, with delays coming due to political reasons.

2.4. Long run and very long run future for gas demand

Let us start from middle term forecasts (by year 2030). According to IEA ([20], Table 4.2), US gas production will stagnate,slightly reducing to 515 bcm in 2030. Here we have also to take into account the fact, that reduction in conventional gas

3 http://eng.gazpromquestions.ru/index.php?id=7.4 http://www.eriras.ru/papers/2009/mitrova_03_09.pdf.5 Russia still has some flexibility even here. For example (Mitrova [14]) Yamal area can substantially increase its output already in 2012, but can also wait

till 2020–2030, when this increase is currently planned. The development of gas in Eastern Siberia and Far East is planned to go with comparable increments

each year between 2010 and 2030, but it might go faster after 2015.6 Since we work with bcm, conversion is needed: 1 cm = 35.33 cf. Hence, 180 tcf = 5090 bcm.

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production might be even faster, but there are substantial possibilities to replace it by non-conventional gas. For how long, itis still uncertain: official data always tell that R/P ratio for US gas is close to 10, and even less in neighbouring Canada andMexico. Hence, if US will need more imports in the long run, they can come only in the form of LNG. IAE ([20], Fig. 4.6)estimates that in 2030 US will import 142 bcm of gas, with major flow coming from Middle East (93 bcm), followed by LatinAmerica (35), Africa (12) and Russia (2). African gas export will grow substantially, but its main destination will be Europe. Inthe Middle run it is expected to drive out Russia as major European gas supplier (modest growth from 137 bcm in 2006 toonly 156 bcm in 2030), while Africa will supply 261 bcm and Middle East 61 bcm. Altogether this gives EU’s necessity toimport 478 bcm of gas in 2030. We may argue that particular flows might deviate from this prediction, but overall Europeandemand for gas imports is likely to be of this order, and will not decline in the long run7.

African gas reserves are modest, with only Algeria and Nigeria having close to 3% of world reserves. That is why Africa cansupply plenty of gas to the world market only for relatively short time; in the long run this flow will be much lower, and in thevery long run might not exist at all.

As for Asia, it is quite heterogeneous, and might have three different markets in future:

(a) Japan and Korea (most of imports as LNG, in 2030 expected at the level 179 bcm, with most (106 bcm) coming fromMiddle East (presuming Qatar), 70 bcm from Australia and Indonesia and only 3 bcm from Russia;

(b) Chinese gas imports will grow substantially, to 106 bcm by 2030, with 63 bcm are expected from FSU (Russia and CentralAsia) and 43 bcm from Australia and Indonesia/Malaysia;

(c) India will form a separate region (since spatial integration with China is both costly and politically insecure), with 70 bcmof gas imports coming from Middle East.

We see that on aggregate Asia will demand around 355 bcm of gas imports in 2030, and it will become the second largestgas importing region after Europe.

The first uncertainty is related to new discoveries of natural gas in importing regions. For example, for the USA R/P ratiofor gas was close to 10 for relatively long time. This means that new discoveries exactly compensated produced natural gas.However, over last decade import of gas was growing, and this suggests that the USA might become one of major importers ofnatural gas in the long run. As for EU, it is already the major importing region for gas and will remain in future. South-EastAsia is the third importing region, with substantial growth of gas consumption and import in coming decades.

The second uncertainty is related to the speed of innovations in energy (energy saving, shift to renewable). EU has quiteambitious program 20-20-20 to use 20% of renewable energy by the year 2020 and to have similar energy saving. The cost ofusing solar energy by 2030 may be reduced to the level to become competitive with other ways to produce electricity, butstill this would not eliminate substantial demand for natural gas by 2030. OPEC [21] predicts that by the year 2030, worldshare of renewable will still remain below 10%, with 24.4% of natural gas in energy portfolio.

How the things might change in the long run? Even if we assume demand stabilization for all importing regions, the roleof exporting regions will change. Russia, Iran and Qatar will become major players, and they will substitute the previouslyimportant role of Africa and Australia.

3. Path of development for new infrastructure

3.1. Middle run

Here only planned infrastructure matters. Key European projects include North Stream (Baltic Sea submarine gaspipeline, with planned capacity 30–60 bcm), South Stream (Black Sea gas pipeline from Russia to EU, with capacity 60 bcm)and Nabucco (land gas pipeline connecting Caspian zone with EU, planned capacity 30 bcm).

Financial crisis that started in 2008 has shown that projections for demand growth are fuzzy (they depend on world’smacroeconomic development). Before crisis implementation of all 3 projects (giving additional capacity between 90 and150 bcm) can approximately match with European growth in gas demand (by 109 bcm, from 214 in 2004 to 333 in 2015(see [19], Table 4.2). However, this crisis has down-scaled the growth of EU gas demand in the short run, and this bringscompetition. While North Stream can be used by Russia in the short run for alternative purpose – decline of Ukrainianbargaining power for gas transit (see [9]), South Stream and Nabucco might become competing projects, at least in theshort run.

3.2. Long run

Here path dependency is very important. The example of EU with growing shortage of infrastructure capacity [8] suggeststhat most of newly built pipes will be used close to full capacity. Will Russia build new pipeline capacity towards West orEast? Hartley and Medlock [6] conclude that under reference scenario, Russia will remain the largest gas producer and thelargest supplier of natural gas to the European market, primarily by pipeline. Their analysis also reveals growing importance

7 IEA forecasts change across years quite substantially. For example, in 2006 it predicted different pattern of US gas imports in 2030: 65 bcm from Africa,

59 bcm from Latin America and 34 bcm from Middle East [19]. However, predictions in flows are more volatile then overall regional demand.

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of Middle East region, especially after 2030. High political uncertainty in this region does not allow for exact forecast, andthus focus on scenarios of behaviour of large players there (especially Iran and Qatar). Russian choice depends not only ontechnological advantage but on geopolitics too. Its choice done in the next decade will shape the pattern of gas export in thelong run.

The same applies to Iran. There are two sub-choices: (i) when will it become a substantial gas exporter (2020 or 2030?depending on geopolitics), (ii) where major export will go?

4. Market shape in the long run

While short run dynamics of gas production depends on technological factors (plants under construction today), formiddle term forecast it is important to consider the new projects among those that have higher net present values. This isusually done by computable general equilibrium models, like those by Hartley and Medlock [6].

In the long run, there are too many uncertainties. If one would try to predict the detailed sequence of investments anddynamics of production in each country, this can be also affected by unpredictable political events. That is why it is importantto consider key assumptions and different scenarios. First, the key assumptions will be stated and then the crucial marketparticipants in the long run are derived. Finally, we will consider how much flexibility in strategies they will have and whateffect on market structure in the long run they will impose.

We analyse the set of production dynamics for finite resources. Output increment in the next period is driven by currentinvestment and natural depreciation of gas fields:

Qðt þ 1Þ ¼ QðtÞ þ Aðt;RðtÞÞIðtÞ � dQðtÞ; (1)

where I is investment (in $s) and A(t, R(t)) converts this financial investment into new production capacity depending onremaining reserves (R) and possibly on calendar time (capturing progress in extraction technologies). We also have theequality

RTQ(t)dt = R0, where R0 denotes initial reserves, R(t) those at time t, T – time interval of production of world gas (till

full extinction). In continuous set up, Eq. (1) leads to continuity in gas production dynamics (given natural assumption thatvery rapid investment becomes prohibitively costly and thus never optimal).

The property of an exhaustible resource – cumulative production has an upper bound – implies that all producers mustsooner or later decline and, in turn, that producer with much larger reserves than a competitor will produce more than thecompetitor for a significant fraction of time. For example Algeria may be a supplier of equal magnitude say as Russia but thenonly for a period of about 10 years.

4.1. Reserves and flexibility in production dynamics

Consider the class of production dynamics:

QðtÞ ¼ at expð�btÞ: (2)

It is important to make here a reference to King Hubbert [10], who has suggested the following formula for the dynamicsof cumulative proven discoveries (proven reserves and accumulated production):

QDðtÞ ¼ Q1=ð1 þ a expð�btÞÞ: (3)

This functional form is the well known logistic function which is the solution to the differential equation dQ/dt = rQ(1 � Q/P)that emerges as a model to many processes in nature and social life. The logistic curve shows early exponential growth fornegative t, and then approaches constant asymptote with an exponentially decaying gap. Based on empirical observations,Hubbert suggests that for oil (and other finite resources) cumulative production path follows the path of cumulative discoverieswith some constant delay. Differentiation of Hubbert curve (3) gives the bell shape of production function with exponentialdecline.

The class of functions suggested in this paper bears asymptotical similarity to the derivative of the curve (3). There is alsoexponential decline at high t, combined with almost linear growth at low t. Besides that, it is possible to explain suchasymptotic behaviour by economic reasons. If one assumes constant flow of investment in new fields that leads to lineargrowth in production8, then it is possible to neglect the depreciation of capital at the initial stage (see Eq. (1) for small Q). Inthe medium term, it will be necessary to keep investment constant just to maintain the output of declining fields. In the longterm, no investment is optimal (being too costly, if we assume growing cost to get the ‘‘tail’’ of cumulative discoveriesproduced, like Hubbert did), and output will decline exponentially.

The family (2) is two-parametrical and it stylistically describes inverse-U shape of production dynamics (with one peak)that is typical for each country that produces finite resource. We add the constraint on resource, requiring that this integralequals to reserve R:

RQ(t)dt = R. After integration (over formally infinite horizon) we have: R = a/b2. Thus, a country with

8 Exponential growth is typical in non-resource economics and in resource economics (early stage in logistic curve) when investment is limited by

current revenue. In the present globalized market capital is not scarce and constant investment flow leading to linear growth of resource extraction is

justifiable.

Y. Yegorov, F. Wirl / Futures 43 (2011) 1056–10681062

reserves R has only one-parametric set of production strategies (given the condition of simultaneous start at t = 0 from zerooutput level):

QðtÞ ¼ Rb2t expð�btÞ: (4)

To become more realistic, we can also introduce delay in production, putting instead of argument t new argument t–t:

QðtÞ ¼ Rb2ðt � tÞ expð�bðt � tÞÞ: (5)

Now it is possible to simulate competition in gas market, given that all countries have chosen parameters of developmentspeed b and delay t. Not always country chooses this optimally for itself. For example, Iran can have forced delay due tosanctions; Qatar has low b due to technological constraint, while Russia simply cannot have too high b due to high cost ofdevelopment (if not, might have it, due to high discount).

Fig. 1 shows the simulation using formula (5). At present, Russia has much higher production level than both Iran andQatar. Iran has not started substantial production (has no export), but is assumed to become important exporter by year2030. Thus, delay of 20 years comparing to Russia and the same shape (b = 0.03) was chosen. Qatar is expected to develop gasmuch slower, and thus b = 0.02. However, contrary to future prospects of Qatar and Iran, that may export major share ofproduction, Russian domestic demand is high, and its export is about one third of its output. The graph with this level is alsoshown (Rus-exp). It becomes clear that while Russia has much higher importance for world market (given the delays of Iranand Qatar) in the short and middle run, in the long run it will be only one of comparable gas exporters, along with Iran andQatar.

Fig. 2 simulates competition among many producers. Since the rest of the countries have no more than 3% of worldreserves, two typical representatives with this reserve share are chosen. They are named Algeria and Nigeria, but we can poolother smaller reserve holders in a similar manner. Here much faster development speed is chosen (b = 0.1 for both). But theyhave different delays. Such strategy allows each of such countries to be substantial competitor to Russia, but over short timeintervals (about 10 years). In scenario on the graph Algeria ‘‘shots’’ first and Nigeria does it later.

Fig. 1. Simulation of gas output by major producers using the function q(t) = a(t � t) exp(�b(t � t)). Russia and Iran are assumed to develop fields faster

(b = 0.03) than Qatar (b = 0.02). Parameters a are chosen proportionally to proven reserves (26%, 15% and 14%), but upgraded to 30 for Russia. Qatar has 10

years of delay comparing to Russia, while Iran has 20 years of delay. Russian gas export is set at 33% of output.

Fig. 2. Simulation of gas output with several competitors. Algeria and Nigeria have 3% of world reserves, but develop them fast (b = 0.1) and at different time

(10 year delay for Nigeria and Iran, while Russia has negative delay of �10 here). This allows small competitors to play an important but temporal role on the

world market.

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4.2. Uncertainty in US gas demand. Long run share of LNGs

While the future demand for gas imports by EU and Asia has some uncertainty, the largest uncertainty comes from longrun demand for gas imports from the USA. According to official statistics (BP Statistical Review), the USA has only 3% ofproven world reserves for conventional gas. However, they have substantial resources (USGS expects USA to add more than3% from non-discovered yet resources). At present, USA imports only small fraction of its demand, but it was growing overtime. In WEO forecast, USA will require 150 bcm of imports in 2030, and in the future this quantity is likely to increase. Byhow much will it increase is a big uncertainty, and we consider here optimistic and pessimistic scenarios.

The future of the USA depends a lot on the amount of economically extractable shale gas. The topic of shale gas productionbecame a hot discussion in 2010. This resource of non-conventional gas did not enter proven gas reserves (see BP StatisticalReview) till the last year because its extraction seemed to be too expensive. However, USA managed to start technologicalrevolution in this direction quite recently. Since deposits of non-conventional gas are large the consequences for gas marketsin future decades can be quite substantial. Some publications in US press revealed the fact about substantial increase ofproduction of shale gas that may turn US from net gas importer into exporter into next decade. The current cost of shale gasproduction is about 90 $/tcm, but uncertainties with future costs and efficiency are high. Most experts cite that we have 450trillion cubic meter of shale gas. Cedigaz suggests that proven reserves of shale gas add only 4% to world reserves, i.e., 7trillion cubic meter (of 182 trillion cubic meter)9. In the case of optimistic scenario for shale gas the USA might turn into gasautarky, exploiting its total gas reserve according to own demand. However, environmental concern will not allow Europe todevelop it at US scale, and it will still depend on gas imports.

In optimistic scenario, USA will be independent from imports of gas for few decades, relying on its non-conventional gas.In moderate scenario, in the long run its demand for imported gas will be close to 150 bcm per year. In this case, it will remainthe third largest importing region in the world, after Europe and South-East Asia. In pessimistic scenario, the demand forimports will grow beyond this level, reaching maybe 300 or 400 bcm. In this case, the long run demand for gas for threeimporting regions (Europe, Asia and USA) will be comparable.

Now it is important to note that due to geographical and technological reasons, the long run demand for US gas importshas to be satisfied using LNG. The problem is that neighbouring Canada and Mexico have not better R/P ratios for gas, andcannot be gas exporters in the long run. The only important reserve holder is Venezuela, but it stays in Latin America, andcannot be connected with USA by pipeline (it will be too costly, apart from possible transit games). Another country thatdepends crucially on LNG imports is Japan. Thus, the sum of long run demands for gas imports by USA and Japan determinethe minimal long run LNG capacity to avoid scarcity for this product. As for Europe and other Asian countries, they can beconnected to pipeline network, and thus depend on LNG not crucially. This means that if LNG becomes prohibitivelyexpensive (due to scarcity), Europe can substitute for pipeline gas, but USA cannot do that.

Finally, it is important to determine what choices of producing countries will determine long run LNG export capacity. It isclear that practically all export from Qatar will be in form of LNG. Although Qatar has high reserves and can potentiallyexport 300 or 400 bcm of gas per year over large period, it probably cannot do it, maybe due to environmental ortechnological constraints. If we assume that forecast of producing 170 bcm is a kind of environmental or technological limit,then Qatar can contribute only this LNG capacity in the long run. Thus, all will depend on technological choices of Russia andIran. However, Russia has less flexibility here, since it already has a lot of commitment to pipeline gas, and LNG can beproduced only from newly developed gas deposits on shelf. Russia is likely to produce 50 bcm of LNG in the long run, but it ishighly unclear whether it will rationally choose to produce 100 bcm or more. In the case of pessimistic scenario thisproduction along with Qatar’s 170 bcm will not be enough to satisfy world LNG demand, even under optimistic scenario (150to USA and 150 to Japan). Thus, the technological choice of Iran becomes crucial.

As a consequence of the above follows: If long run capacity of LNG is below the critical LNG demand (sum of one from USAand Japan, countries who cannot get pipeline gas in the long run due to technological constraints), there will be scarcity inthis gas market segment and LNG price will exceed one for pipeline gas, all LNG will go to these countries and countries withaccess to pipelines will buy only pipeline gas. If the premium exceeds some threshold, additional investment in LNGcapacities will be done, and price difference will be reduced later. If long run capacity of LNG will be above critical LNGdemand, LNG will serve as a mean of arbitrage and gas prices will be equalized among all countries having ports, while stillmay differ in land-locked countries (being below or above, depending on closeness to supplier and its power).

4.3. Strategies

Solving a corresponding formal dynamic game even accounting only for the three key players and the most crucialstrategies and constraints is beyond the scope of this paper and presumably impossible. Given that each of three countrieswith large gas reserves has uncountable continuum of strategies of supply dynamics (in continuous time model), the formalgame with such complexity cannot be solved, and simplifications are needed. Nevertheless, economic rationality argumentsallow for reducing the set of outcomes. One of suggested simplifications (see formula (5)) still has several continuous choiceparameters. Still some qualitative conclusions can be done based on rationality of players.

9 Melnikova S., Geller E. (2010) Shale revolution under question (in russian); http://www.ng.ru/energy/2010-04-13/14_revolution.html.

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While Russia has the largest gas reserve share (26%), it also has the largest share of domestic consumption. It might varybetween 60% and 80%, but we will assume that Russia will export on average about 30% of its output. If Iran will develop itsgas fields, it might export about half of its output (roughly, 250–300 bcm out of 500–600 bcm), since it has about half ofRussian population, but might need some gas for oil production. The share of exported gas will be the highest for Qatar;although its output is not likely to exceed 200 bcm due to ecological constraints (limited coast line that has to be used formultiple purposes and problems with pipelines).

The South Pars Gas Field contains about 50% of Iran’s gas resources and is regarded as the largest offshore gas field in theworld. It is a joint property of Iran and Qatar. Gas production at Iran’s offshore natural gas field South Pars will rise to 175Mcm per day within the next 2 years. However, political restrictions may delay the emergence of Iran as important exporterof natural gas in the next decade. This uncertainty will not affect very much the joint supply of the big three since Russia andQatar will be ready to deliver. If Iran moves forward with gas production fast, having relatively low-cost, Russia may consideran investment in Iranian gas, an option which dominates in the middle run the domestic alternative of developing itsexpensive fields in Siberia and Arctic. As a result, Iran will deplete its resources faster, but Russia may peak not in 2040, but1–2 decades later. The overall dynamics of aggreagate natural gas supply from Russia, Iran and Qatar will not differ much.

Given that Russia has to produce at least 500 bcm of gas to satisfy its own needs and to serve long term contracts and given itshigh discount rate (clearly seen from fast development of oil export), it is likely that it will use all possibilities to expandproduction fast, and only technological constraints and relatively high cost can limit the speed of its development of gas fields inthe middle run. Thus, it can reach the level between 800 and 1000 bcm already by 2030. It has two strategic choices:

(a) When to peak (most likely narrow choice between 2040 and 2050, based also on strategic considerations); in the firstcase its maximal export can reach 400 bcm but will last for fewer decades,

(b) The long term LNG capacity (most likely, the choice between 50 and 100 bcm).

Russia might also be strategic in these choices, but choices are narrow. In any case, in the long run it can choose to exportbetween 300 and 400 bcm of gas, including 50–100 in the form of LNG. Export to pipeline gas to Asia will be at least 50 bcm,and to Europe at least 200 bcm, so it can vary strategically only 50–100 bcm of gas across markets.

Having lower fraction of domestic consumption, Iran can go to the market with volumes comparable to Russia. However,due to delay in field development it will peak 10–20 later than Russia. Qatar will be the latest to peak; it has limited capacityto absorb cash flow from export and thus will keep substantial fraction of reserves into 22nd century.

Going backwards, we can say that Qatar is likely to remain the major supplier of conventional gas in the 22nd century.However, it is not clear if it can enjoy monopolistic position since some substitute for natural gas as energy source will bediscovered by this date.

The second half of the 21st will definitely see oligopolistic competition among these three gas exporters, with volumesquite comparable. There will be also three major importing regions. Since the productions profiles are almost predeterminedby previous considerations, the key aspect of modelling this oligopolistic game will be in choice of technological investment:pipe to West, pipe to East and LNG. As it was already discussed, Iran (in few years or decade) is likely to have the largestflexibility in these options. Having cash constraint, it might use the cost issue as the primary objective. The cheapestpossibility might be to supply gas to India, but it has limited absorbing capacity, limited at 70–100 bcm. Pipeline to China willbe more costly, and next option might be between pipeline to Europe (a kind of Nabucco-2 or LNG). The relative cost now ishighly uncertain, as well as long run gas demand by USA, and this makes equilibrium forecast a bit fuzzy.

4.4. Market structures

Market structure depends on the strategic choices of the major suppliers. First of all, with 3 large players the probability ofa tacit or open cartel agreement is high and no anti-trust court can deter this. Second, knowing the lack of commitment to ex-post cartel arrangements, the players may lock themselves into particular markets. In order to stress this point consider theoptions for Russia and aggregated Middle East and ignoring LNG trade to the rest of the world (US, Japan and others). Then anopen or only tacit agreement on market separation, (e.g., Russia going to Europe, the Middle East to Asia) avoids competitionamong major suppliers creating ex post stable monopolistic markets. Clearly the incentives to do so are high. This separationis in addition supported by bounded rational solution focussing on the costs for infrastructure only. Adding the scope for LNGexports changes nothing as long as the (regional) prices for pipeline gas are lower than the price for internationally tradedLNG. A cartel of major gas producers has an interest to keep LNG expansion low to mitigate the ex post competition which inturn should put a premium on the price for LNG. Otherwise, any cartel agreement on pipelines is counteracted by the threatof LNG competition by other members in its backyard.

Among the many conceivable evolutions, we restrict our analysis to two market structures between three large exporters(Russia, Iran, Qatar) and 3 importing regions (Europe, Asia, USA) due to simplicity and likelihood of emergence according tothe above analysis. We have to look at overall balance of demand and supply and its split between pipeline gas and LNG. Inthe first structure there is segmentation into pairs producer–consumer, with potentially different prices that cannot beequalized by arbitrage mechanism due to differences in cost of delivery. In the second case, the world gas market becomesintegrated, and each player has not too costly alternative option, if the partial switch to alternative supplier (or consumer)becomes important for economic or political reasons.

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4.5. Moderate long term scenario (for mid-century)

Here we consider approximate quantities and will focus on likely flows. Consider first the case when US demand forimported gas remains modest at 150 bcm. EU demand is the largest at 400 bcm, followed by Asian demand of 250 bcm.Totally this gives 800 bcm of gas demand. Suppose that Russia and Iran develops 300 bcm of export each, while Qatarexports 200 bcm. The critical LNG demand is assumed at 250 bcm, and 200 bcm will come from Qatar anyway. SinceRussia will develop at least 50 bcm of LNG capacity, there will be no LNG scarcity independently on choice of Iran (whois likely to develop some LNG, maybe 100 bcm). Russia most likely will commit 200 bcm of pipeline gas to Europe and50 bcm of pipeline gas to Asia due to technological considerations. Both Russia and Iran can arbitrage between Europeanand Asian markets, but 100 bcm of extra LNG (above critical level) will equalize prices across regions.

4.6. Pessimistic long term scenario

Suppose that either all demands are higher (imagine 1000 bcm), or gas producers strategically limit fields development,potentially forming GasPEC. If total supply is below demand, due to inelastic demand, prices will grow, and can differregionally. Strategically limited LNG supply will keep this source scarce, with higher prices than for pipeline gas. At the sametime, there will be lock-in in producer–consumer chain, with prices set by monopolistic–monopsonistic consideration,highly dependent on good will and other political reasons.

5. External shocks and interactions between energy markets

This section elaborates on external influences on gas sector that can perturb our predictions derived from theconsideration of natural gas sector taken alone: external shocks and interactions between different energy sectors. Thesefactors cannot be known in advance (the known unknowns), and thus the volatility of predictions from these considerationsis high. That is why we consider several additional scenarios.

5.1. Role of shocks

The analysis of the main focus of WEO reports (and core presentations in IAEE conferences) shows that energy forecastsvary substantially over the last years. Before 2007 the main concern was about global warming, in 2008 it was the rapidincrease of energy prices, in 2009 the shift was to crisis duration and energy security (after Russian–Ukrainian gas conflict),and in 2010 the forecast change was driven by the discovery of substantial economic reserves of shale gas.

These recent and important shocks – global warming, high oil prices, financial crisis and subsequent recession,political instability and the issue of reliable supply, discoveries of new gas substitute (shale gas), oil spill in the Gulf ofMexico – affect energy demand, supply (as documented in the changes in IEA’s forecasts) and highly volatile energyprices. Aside from the future shocks (the unknown unknowns) the question is how long will last the impact of the recentshocks. Generally, one can think about demand or supply shock, with typical magnitude (X% at present) and duration (Y

years).In the long run the effect of all these recent shocks may die out: recession already seems to be overcome; oil prices have

returned to their 2007-level; the financial crisis continues to affect short run investment and therefore middle run capacity.Summarizing, there will be no substantial long run effect.

In the years 2009–2010, we really observe an increase of natural gas supply (through more use of now economical shalegas, at least in the USA) and the shrink of its demand, due to effect of crisis, both leading to a substantial decline in gas prices.The question is: for how long? Here we have to consider an inter-link between gas and oil. At present, the proven reserves foroil are for 40 years and for gas for 65. How much the discovery of shale gas will prolong them? Today this question cannot beanswered with certainty, and the main uncertainty is the cost distribution of the shale gas reserves (not yet studied). Here wecan only describe the limits. In the pessimistic limit (for consumers) the economically extractable reserves of shale gas willadd only few % to total reserves (say, pushing them to 70–75 years from present 65), while in the optimistic scenario they candouble or even triple them. In the last case we can rely on gas abundance for the next 130–200 years, making it only a bitscarcer resource than coal and much less scarce than oil.

5.2. Substitution between gas and oil (transportation), gas and coal

The issue of substitution path between different energies is an important topic of research per itself. Here we observestructural change. The first simple model based on logistic curves was suggested by Marchetti [12], and its fit with the realitywas perfect before 1980s. Further changes are discussed by Devezas et al. [3] and include several amendments to Marchetti’smodel. Briefly speaking, replacement of dominant energies (first wood, then coal, then oil) now follows a different path, withtemporal stabilization of shares for different enefgies in world’s energy portfolio, and focus on energy saving. In particular, oilhas been substituted by natural gas less quickly then according to Marchetti’s logistic model. The main prediction of today isthe decline of the sum of oil and gas, by substitution from reneables and nuclear energy.

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Robert and Lennert [16] consider two scenarios for oil peak, slow (2030) and fast (2015). As for natural gas, they are toopessimistic, suggesting that its peak will follow shortly after oil peak (around 2025). We think that it may not take placebefore 2040, and given additional shale gas, it might take place after 2050.

We also expect that non-conventional oil and gas will not change much the time horizons of production peaks. As for non-conventional oil, Salameh [17] suggests that the potential of unconventional oil resources such as Canada’s tar sands oil andVenezuela’s extra-heavy oil is highly overrated. Kuhn [11] analyses the role of shale gas. While it had led to a reassessment oflong-term gas balance in the USA and to removal of its dependency on imports of natural gas at least for several decades, itsrole as game changer in Europe is much less likely. The reason is in existing economic constraints and obstacles in Europethat make the cost and the development risk for shale gas much higher than in the USA.

What are the consequences under this scenario of fast oil peak for the dynamics of prices for natural gas? As we observethe situation in 2010, the ratio of gas prices to oil prices did not reach pre-crisis level. Here we see two main reasons: (a)discovery of economic shale gas in the USA, (b) more awareness about coming oil peak. We expect that in the short run thegas/oil price ratio will stabilize on a new level (accounting for relatively scarcer oil comparing to gas), and then both priceswill start co-movement. Before oil peak we can expect positive trend in both oil and gas prices (maybe 3–5% per year), whilepresence of gas can smooth and prolong plateau phase for oil production, giving few more years of adjustment to high oilprices. Between 2020–2030 and 2040–2050 there will be a period with a decline in oil production, but still an increase in gasproduction, with relatively more expensive oil and substantial positive trend for natural gas prices. After the peak of naturalgas (around 2040–2050), its price will also jump substantially (or follow more fast positive trend). However, details dependon innovations and R&D.

As for the different scenarios, we have to distinguish between extreme (optimistic and pessimistic) dates for oil andnatural gas peaks. For each of scenarios by Robert and Lennart (2015 and 2030 for oil), we consider two peaking scenarios fornatural gas: pessimistic (2040) and optimistic (2060). Here the timing is rough (plus–minus 10 years or even more). Theirrealization depends on many factors: (a) the total volume of non-discovered oil and gas (including non-conventional), (b)substitution path between these two fuels, (c) substitution by nuclear and renewable. Thus, we have 4 scenarios (startingfrom more pessimistic):

(1) Oil peak in 2015, natural gas peak in 2040,(2) oil peak in 2015, gas peak in 2060,(3) oil peak in 2030, gas peak in 2040,(4) oil peak in 2030, gas peak in 2060.

In Scenario 1 oil price will rise fast around 2015, driving oil substitution by natural gas and other renewable. Since naturalgas is much less scarce, there will be enough time to prepare for its peak (than for oil peak) and technological substitution by2040 will make this peak less painful. Scenario 2 takes place when we have a lot of economical non-conventional gas and thisgives even more time for this substitution. Natural gas price will follow positive but moderate trend, being well below oilprice (for toe). Scenario 3 will take place when we have not so much shale gas, but more oil than expected. The postponementof oil peak will allow for more substitution between oil and gas, and two peaks will come later, but almost simultaneously.This will push both oil and gas prices high after 2030–2040, but will allow for moderate trend in prices for both before 2030.In the case of scenario 4 (most optimistic), the world is likely to have enough time to prepare technologically for both peaks,and we may not observe huge price shocks with negative macroeconomic consequences.

What will be the relative price path for these fuels given different scenarios? Robert and Lennart [16] suggest that beforepeaking prices rises with a moderate trend, while during the peak they rise sharply to the level, where further rationing ofnormal use of particular fuel will take place (driven by economic reason) along with its substitution for other fuels. Ofcourse, if this pattern is known to a number of market participants, the no-arbitrage condition imposes a constraint on theprice rise, unless it is a surprise as so often in the past. There exist many uncertainties that drive heterogeneous beliefsabout oil recovery, about global warming mitigation, about technological breakthroughs which all affect absolute andrelative fuel prices. Nevertheless, we expect oil and gas prices to move in line. Of course we are aware that unforeseenevents can alter the relative fuel prices substantially in either direction. As soon as markets get an information about thetiming of oil peaking and the possibilities how to substitute oil by gas (as well as by other fuels), oil and gas prices will moveto new levels, at which the investment in replacing technologies will become profitable. Similar arguments hold when gasproduction will approach its own peak. We also have to take into account future discoveries, including the level of maximalutilization of non-conventional oil and gas.

While long run trend is somehow predictable, there remains a lot of short term price volatility, mutually driven by futureshocks of all types, lack of spare capacity in the short run and, maybe, irrational expectations. For example, stagnating naturalgas prices driven by demand not fully recovered after the financial crisis, current excess capacity of LNG, optimism aboutshale gas suppress investment in new capacities with potential of gas prices spiking in the middle term.

6. Conclusions and policy implications

The principle of backward induction is crucial: You cannot predict the medium term without any idea about the ‘endgame’, i.e., the long-term situation. The purpose of this paper is to fill this gap by focusing on the long run and on the shadow

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that this casts over the medium term. Inter alia our analysis suggests the following. Given that long run future gas marketwill have few large players under the ownership by sovereign states (thus beyond anti-trust laws), the incentives for cartel-like agreements are strong. Furthermore, the heavy investment into infrastructure may provide a commitment device toreduce ex-post competition leading possibly to almost monopolistic situations in regional markets. This degree of regionalmonopoly depends on the long-term share of LNG in gas trade since that can be used to enter the ‘home’ market of othersuppliers. As a consequence, limiting LNG development by one or more of the crucial suppliers (in particular by Russia) canbe a signal for a tacit cartel arrangement.

In energy markets it is very hard to ignore politics, not only in the short and medium term when it is harming the Iranianaspirations, but also in the long run. For example all countries but in particular Iran and Russia face the obstacle of lowdomestic prices, which can even threaten long term export volumes. In the case of Qatar, its resource richness given its smallpopulation and its military impotence may attract some of its Arab or Muslim brothers to ‘annex’ it. Fortunately it issurrounded by resource rich Saudi Arabia but it may nevertheless receive protection by a global power; Russia because ofcartel interest, US and China due to consumers interest.

Conversely, consuming countries may re-consider their strategies. For example, an anti-global warming policy (basedcurrently on an increase of the share of natural gas, since the only option to save CO2 permits is to run gas fired instead of coalfired power plants) may be reconsidered (pushing e.g. CCS, nuclear power and R&D in alternatives and renewable). On theother hand diversification will help today but at the cost of even less competitive future supplies by mid 21st century due toresource constraints.

While it is difficult to forecast the details of gas markets 20–30 years from now, some policy issues can be derived fromtheir long-term structure. If LNG becomes scarce, USA will submit higher bids compared with EU. If Russia builds LNG plantsor Asian pipelines in earlier period, it is not optimal for it to increase gas sales to EU by building new pipelines in the long run.Thus, EU should have an economic interest to invest in pipelines to Russia in the middle run, to reduce Russian risk in energydemand and to reduce Russian incentive to invest more in Asian pipelines and LNG. By doing this, EU can improve its termsfor gas supply in the long run.

Future external shocks (like oil peak) and interaction between markets for different energies add complexity to forecast,making it more chaotic and fuzzy. Here we consider different scenarios for the timing of oil and gas production peaks. Due totechnological possibility of substitution between oil and gas, we expect a smoothing of transition process and almost parallelgrowth of oil and gas prices in the middle run, making the current decline in the relative price of natural gas a temporalphenomenon. Non-conventional gas and oil can change the time horizons of peaks but are not likely to change the generalstructure of the forecast described in Section 4.

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