In terms of natural gas „geography" the paper confines its focus to the natural gas consuming areas impacted by LNG; being those entioned above and the new emerging or „niche" markets of South America and the Middle East, and of course the LNG suppliers.The period spanning the end of the 1990s to 2010 has seen significant changes in the sphere of natural gas in these geographies. These include:

• a changing perception of the availability of supplies of natural gas,
• a pro-liberalisation policy-driven gradual change in market structures in continental Europe
• in Asia the growth in spot LNG purchases to offset the decline in Indonesian LNG export towards the end of the period
• general LNG supply project slippage.

The paper does not foresee the development of a global, liquid traded commodity market as has developed in oil; the lower energy density and hence the cost of transportation infrastructure and storage (and the historic tendency for long term contracts to remunerate the investment in such supply systems) would mitigate against a rapid transition to such a state. What has happened however is the partial undermining of the „national incumbent" gas purchaser in Europe, the adoption of limited spot purchases of LNG in Asia and the development of distant long-lead time supplies of LNG for the liberalised gas markets of North America and the UK.

The paper also explores the consequences of the „system" in which supply and demand becoming periodically unbalanced and the specific response mechanisms (through price signals) which will, over time, bring it back into balance.

The paper derives a set of future assumptions (a „quantitative envelope") and develops a modelling framework to explore the trends and discontinuities for the period to 2020. A suite of modelled cases are discussed to illustrate the scale of the system de-stabilisation likely in the period to 2012 and the scale of price-driven response necessary to re-balance it.

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Natural gas plays a central role in the UK (and the world) energy market in the first decade of the 21st century, but is facing the prospect of a decline in its importance as environmental factors combine to reduce the importance of natural gas and the other carbon-based fuels. This will inevitably result in the future of the gas industry becoming dependent on wider considerations, which can be summed up as „environmental energy policy. Policy makers looking to the longer term are primarily concerned with producing electricity from the least emitting fuel; reducing emissions in line with national policy and international agreements; the security of energy supplies for their own countries; and the cost of energy for national users. The future of the gas industry is a long way down the list of priorities, and this is unlikely to change.
Three questions need to be asked at this point:

• What is the UK's energy policy?
• Where does natural gas sit within that policy? and,
• Is there a need for more central direction? There is no easy answer to any of these questions.

This report investigated these questions and comes to the following answers:

What is the UK's energy policy? There is a carbon reduction policy, but it is not specific about the policy for individual fuels.

Where does natural gas sit within that policy? There is no clear answer. The assumption is that the role of gas will be to plug gaps and compensate for the lack of preferred generation fuels, but it is only an assumption.

Is there a need for more central direction? Almost certainly yes, both for overall energy planning and for gas, even if only in certain defined areas, such as supply security.

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The scenarios in this paper were developed to gain insight into how large a role gas will play in the transition to low-carbon electricity supply in the Netherlands. Although all three scenarios are possible, reality will probably be more nuanced. Following the almost sacred principle of fuel diversification in the energy sector, a balanced mix of generation technologies is most likely. Nuclear power has the lowest probability of expanding its share in the generation mix due to the political and public controversies which it raises. However, an increasing sense of urgency about climate change, could alter this outlook. In any case, the government and energy companies must be aware of the conflicts and possible lock-in effects in especially base load generation capacity development. This also includes the latent lock-in effect of pre-construction phases of large scale capacity.
The combination of large scale wind and nuclear or coal with CCS capacity will have detrimental effects on the value of one of those investments. The coming years will be pivotal for the transitional design of the Dutch generation mix and a ‘keeping options open’ approach will not help to establish this. Although base load technologies can co-exist to a certain extent, the conflicts between the different options, which also depend on the development of export opportunities, require decision makers in the sector to commit to significant investments in a specific technology.

The envisaged strong position of gas in energy transition requires the Dutch government to evaluate a longer term gas policy. An outlook which gives an increasingly important role to gas in power generation in the transition phase, in combination with depleting national reserves, puts current production and export policy in a different perspective. Although increasing power sector demand will be partly offset by a decrease in household and commercial demand, the importance of an energy transition which includes CO2 reduction and energy security probably requires a different allocation of national gas resources. In other words, if gas is considered as an important transition fuel and the Netherlands does not want to depend too much on imports after 2020, production and exports will have to be curtailed to decrease the depletion rate of indigenous resources.

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With proven natural gas reserves standing at 991.6 trillion cubic feet (Tcf), Iran holds the world’s second largest gas reserves after Russia1. Since the Islamic revolution in 1979, the production of gas in Iran has mainly been intended to meet the domestic demand2. However, at the end of 2001 Iran began to export gas to Turkey. Besides the Turkish desire to explore the Iranian gas market, the huge natural gas resources have also attracted international energy companies worldwide. However, from the Iranian side the focus has mainly been on oil exports, and the Iranian gas market has been very difficult for international companies. Policy makers in Iran have also been hard to cooperate with, and tough conditions have been imposed on any company seeking to invest in Iran´s natural gas fields. The most successful Iranian gas export trade in the post-revolutionary era has been between Iran and Turkey even though this relationship, which is the focus of this paper, has been far from successful.
This paper intends to examine the bilateral natural gas trade between Turkey and Iran, through analyzing the commercial natural gas cooperation, but also their political relationship. The intention is also to present an analysis that could contribute to the broader picture of Iran as a potential gas supplier to the fourth corridor, i.e. the European market. Bilateral trade between Turkey and Iran reveals much about the commercial reliability of both parties. This is important because the political and commercial relationships between these two countries are of crucial importance for a possible future natural gas route from Iran to Europe.

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Planned Albanian gasification, aimed at meeting fast growing energy needs, is set to be a challenge, as the low-price environment both there and in neighbouring markets hampers investments in greenfield LNG capacity, especially in the current cash-strapped environment. Meanwhile, plans to connect to new gas links inescapably suffer from delays in their implementation. Nonetheless, construction of a direct link to ITGI via Greece seems to be closer to realization than other regional pipeline projects, and could see the first volumes flow to the country before 2015. The revised National Energy Strategy of Albania projects demand levels of up to some 1.8 bcm/y by 2020, but the 94 decrepit state of existing Albanian gas infrastructure suggests that this may be too optimistic. Hence, even very limited northwards flows from ITGI could support Albania in the initial phases of its gasification.
Greece is a fast-growing gas market which enjoys a number of international gas links (and has more planned), including the flexibility of an LNG terminal in Revithoussa. Demand is likely to contract for the first time this year due to the global financial crisis, but the structural trend is clearly upwards as a result of an expanding gas-fired power generation sector and increasing penetration in the residential and commercial sectors. Demand in 2015 will probably be in the range of 7.1?8.1 bcm/y but Athens seems to be relatively well placed to meet the supply challenge. By 2015, Greece could have a total real import capacity increment in excess of 2.3 bcm/y compared to the current levels of 7.2 bcm/y, or a real import volume increment of more than 5.3 bcm/y compared to 2008 levels of 4.2 bcm/y, assuming full utilization of existing capacity and planned logistical upgrades at the Revithoussa LNG terminal by 2013.
The supply/demand balance outlook for Greece is thus conditional on Athens succeeding in securing the additional gas volumes needed to sustain high utilization rates in both existing and planned import infrastructure. If it fails to do so, serious imbalances will appear from 2012/2013 onwards, when the bulk of new gas-fired power generation will have come online. In contrast, if it succeeds both in moving forward with planned investments as well as in sustaining high utilization rates, it will find itself in a position of not only being able to meet growing domestic needs, but of also being able to export natural gas volumes to regional countries. Exports to the neighbouring Balkans and beyond seem in any case to be a strategic priority for Greek gas operator DEPA, and plans to construct the IGB as well as a new LNG terminal in Kavala would extend the influence of Greece over a number of Balkan countries.
However, rapid construction of a second LNG terminal in Greece would be premature, unless as part of a grand commercial–political bargain between Greece and Bulgaria for enhancing security of supply, penetrating the Balkans, and providing political leadership in the region. A final investment decision should thus be delayed until uncertainties stemming from the current global financial crisis have been clarified. Investors should use the time to complete FEED by early 2012, including assessment of the emerging regional supply/demand balance, in order to allow construction by 2015, if conditions allow. Successful fruition of even some of the major proposed pipeline links in the coming decade would undermine utilization rates of a greenfield Greek LNG terminal, thus rendering the whole project considerably less profitable.

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This article presents an overview of the impact of the current world economic crisis on natural gas markets in Russia and the CIS. It will discuss two types of changes that reflect broader international trends. First are the initial consequences of the recession that was triggered by the US financial crisis of September 2008: sharp falls in gas consumption, which have produced oversupplied markets and falling prices; cuts in production and investment; and intensified competition between suppliers. Second are deep-going changes that could result over the longer term, as these impacts of the recession combine with other factors. The recovery of demand, however long it takes, will be accompanied by trends such as (i) technological advances, for instance those allowing the economic recovery of unconventional gas reserves, which could in time spread beyond the US; and (ii) changes in market structure, and particularly the increasing availability of liquefied natural gas (LNG), which will have consequences for regional markets for pipeline gas.

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Since at least 2006, concern has been expressed by a number of commentators, both western and Russian, that Gazprom has not invested in future production sufficiently to guarantee that it can meet its market obligations and, particularly, its long term contract export obligations to European customers. This argument runs that, although Gazprom may have huge reserves, it has not paid enough attention to developing them. Instead, at the behest of the Russian government, it has invested hugely in the Russian oil and electricity sectors, as well as exotic overseas projects in African, Middle Eastern and Latin American countries.

This paper draws attention to a complete change in the short term outlook for Russia gas supply which emerged due to the global recession which commenced in 2008 and reduced levels of gas demand in Russia, CIS countries and Europe. Concern about Gazprom’s ability to deliver volumes contracted to European buyers has been replaced by the latter asking for relief from their contractual obligations to take these volumes. As a result, Gazprom has been forced to cut back its own production, and that of other Russian producers, and no gas has been imported from Turkmenistan for six months due to a contractual dispute.

Some may wish to argue that the problems identified prior to 2008 will return post-2012, and that Gazprom will face difficulty in meeting its contractual obligations in Europe. Those holding this view are again referred to the need for detailed analysis of the different elements of the matrix (Table 1); in particular the difficulty of projecting post-recession levels of Russian and CIS gas demand. In addition, future European gas demand is also not easy to predict; it may be that a combination of reduced economic growth and increased low carbon energy supplies will mean that demand may not increase significantly beyond 2008 levels prior to 2020.41 In the shorter term, there is confusion in Europe about the security aspects of Russian gas, with concern about reliability of supplies because of transit problems, combined with opposition to investments in new pipelines which would improve this situation by avoiding transit countries. The potential for criticism of Russian gas policy in the late 2000s is substantial, with the slowdown in price and market reform at the top of that agenda. But continual unfocussed criticism about lack of investment obscures, rather than illuminates, the complexity of the Russian gas situation.

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This paper does not repeat the majority of 2007 paper, which questioned the continued rationale of the linkage of Continental European long term contract gas prices to oil product prices, but focuses instead on developments over the past two years and the outlook in September 2009.

What is certain is that contractual decoupling will be an unwelcome development for the majority of major Continental European market players, both buyers and sellers and some part of the responses in Table 1 probably reflect this antipathy. Contractual decoupling of gas prices from oil product prices should not be regarded as either better or worse than oil linked pricing. A gas price mechanism which more closely reflects the balance of supply and demand for the commodity should be regarded as a natural and overdue evolution for an industry which accounts for around a quarter of European energy demand.

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This study describes the development of the German gas market from 2006 to 2009 and its transition from a market situation where hardly any competition was observable to a market where competition is starting to take place.

The main obstacle that prevented any change was the issue of network access. The German government did not install a regulatory authority at the beginning of formal market liberalisation but relied on negotiated third party access. But associations were not able to agree on a system that really facilitated access for new market entrants and encouraged competition.
In the present study I describe how this changed after the German government changed the energy law in 2005 and installed a regulatory authority, the Bundesnetzagentur (BNetzA) following the prescriptions of the second – EU directive 2003/55/EC - which repealed the first one. The BNetzA finally enforced – after lengthy and difficult discussions with the main stakeholder associations - a model of network access, called the “two-contract model” that allowed rather easy and non-discriminatory third party access to the German networks. But the model still had one severe shortcoming. It allowed the network operators to divide Germany into so called “market areas”, and the two-contract model was applied in each market area separately. In October 2006, when the new model of network access was finally introduced, Germany was divided into 19 different market areas, still a large hurdle for the development of competition. This study describes the progress and setbacks in the reduction of market areas.

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The objective of this paper is to examine how relationships between IOCs and NOCs have changed in the development of LNG projects. In the 1960s “NOCs were kings” but the 1970s, 1980s and 1990s saw a greater role for IOCs with more LNG developments and technological challenges. The last ten years have seen the NOC role increase again, together with the involvement of other companies such as utilities, LNG shipping companies and service providers investing in parts of the LNG value chain which are new to them. The paper concludes with some high level actions which IOCs could pursue to maintain and enhance their position with respect to future LNG project developments.

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The Russian-Ukrainian gas crisis of January 2009, occurring three years after a similar dispute between Moscow and Kyiv had disrupted Russian natural gas supplies to Europe, led many European commentators to question the continued reliability of Russia as a supplier of natural gas. The role of Ukraine as an energy transit state was also put under the spotlight. The January 2009 crisis followed the conflict between Russia and Georgia in August 2008. This brief war had compelled governments in member states of the European Union (EU) to reconsider the wisdom of being dependent for over 40 percent of their gas imports from an increasingly emboldened and aggressive Russia. Attention has focussed more on developing projects which would supply natural gas to Europe from sources other than Russia along
routes which would bypass Russian territory. The so-called “fourth” or “southern” gas corridor connecting the Caspian and Gulf regions and the Middle East to Europe (the other three corridors running to EU member states from Russia, Norway and north Africa), has been identified by the European Commission as Natural Gas (NG) Route Number 3 in the framework of the Trans-European energy networks (TEN-E).

There is much speculation among observers in Turkey that some form of “Grand Bargain” could perhaps be struck with Russia over energy. Supposedly, Ankara would allow Gazprom to construct the subsea section of South Stream across Turkey’s EEZ, and, in return, Moscow could allow the flow of Kazakh and possibly Russian crude along the planned Samsun- Ceyhan oil pipeline. The package could also include a deal to construct the so-called Blue Stream 2 gas pipeline connecting Russia and Turkey. This could provide Turkey with new trading opportunities if re-export clauses would be included in an agreement. At the time of writing, though, much still needed to be realised before this “Grand Bargain” could materialise. And, this arrangement would not reduce Turkey’s energy dependence on Russia.
Geography may be to Turkey’s advantage concerning the prospects for a fourth corridor, although security problems, especially with regard to the PKK, could yet cause further complications. A number of other issues remained unresolved at the time of writing, such as the disagreements between Turkey and Azerbaijan over gas pricing, the routing of gas to be produced in the second phase of Shah Deniz, and the question as to whether the CDC would be established. However, it does appear, with regard to Nabucco at least, that policy-makers in Ankara have been able to better coordinate their positions in recent months and the conclusions reached at the Prague Summit in May 2009 would suggest that the Europeans are also beginning to speak more with one voice on energy matters.

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Due to its gaseous form, and therefore low energy density, pipeline natural gas has traditionally supplied nearby regional markets which have been historically isolated from each other. Regional markets have traditionally had their own supply-demand balances, contractual structures and gas price formation mechanisms. This model is now under threat. With the growth of liquefied natural gas (LNG) supply which is increasingly flexible in terms of destination, regional markets are becoming progressively more connected. A decade ago, when the LNG industry was based exclusively on long-term take-or-pay contracts and the number of market players was limited, the impact of price signals, if any, was weak.
The liquidity of the ‘flexible’ LNG market has increased in tandem with the growth in the number of LNG producing and consuming countries, the appearance of some uncommitted volumes of LNG and development of arbitrage activity. LNG arbitrage is a new pattern of gas trade still in an embryonic stage of development. Few outside the LNG industry or even outside LNG trading circles understand the term ‘LNG arbitrage’ let alone the specific mechanisms. One of the goals of this paper is to establish a clear
definition of LNG arbitrage and distinguish it from other trading activities which superficially appear similar.
Historical gas price data for different markets suggests that price differentials have created opportunities for LNG arbitrage to take place. However, the scale of this type of trading has been  constrained to date and has not led to demonstrable gas price convergence between markets. The second aim of the paper is an analysis of the main barriers to the growth of the LNG arbitrage market.
Research for this paper has enabled a framework of barriers and conditions for LNG arbitrage to be developed. According to this framework there are four necessary conditions for an arbitrage transaction to take place. Barriers, which deter arbitrage, can be divided into four groups. Analysis of the barriers has shown that some constrain arbitrage on the global level while others are more locally focussed. Some barriers strongly preclude arbitrage activity while others merely make it more challenging.

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The disruption in natural gas supply to South Eastern Europe during the January 2009 Russia-Ukraine crisis revealed serious shortcomings in the security of supply architecture in the region. The adequacy of electricity, gas and district heating infrastructure has deteriorated over recent years. During periods of high demand, supplies and infrastructure operate at full capacity and countries become vulnerable to supply disruptions. At their current level of economic development, the countries in this region have considerable energy infrastructure and should be able to ensure security of supply in other circumstances similar to those of the January 2009 crisis.

Comprehensive short, medium and longer term energy security planning is still lacking. The crisis created momentum for better regional cooperation, but whether this can grow into useful and mutually beneficial action, capable of withstanding similar future events, remains to be seen. One such initiative is the Western Balkans Gas Ring (promoted by the World Bank) and accompanied by the NETS initiative for better coordination between gas transmission system operators (promoted by MOL of Hungary). These initiatives have yet to be coordinated with investment options for power generation, district heating systems and energy efficiency and solutions for vulnerable social groups, to form some kind of regional energy development agenda. They will then need to be implemented.

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In this paper, we have analyzed the situation regarding the market value of natural gas in the Asian region. As noted in the text, crude oil prices have fluctuated wildly in 2008, and the energy market is going through a major transition. Internationally, strengthened measures against global warming are being discussed, and the resulting shift to nuclear power and renewable energy sources, and accelerated development of clean coal technologies could change the role of natural gas in long-term energy supplies. Nevertheless, over the next 20–30 years, natural gas will undoubtedly continue to grow as a core energy source in the Asian region.
While the use of natural gas is thus expected to develop further in Asia, the irrationality of the present system of LNG pricing must be recognized, and the time has undoubtedly come for the majority of all players involved in the LNG chain, to consider a more appropriate and logical pricing solution.
In the present analysis, it has only been possible to discuss some of the most basic issues in relation to the future direction of pricing. The key point to note, however, is that a discussion of LNG pricing in the Pacific typically commences with the traditional price formula, and is deeply immersed in the debate on the coefficients and intercepts of the formula. It is important that all those involved in the LNG business take a step back from the position of negotiations between buyers and sellers to begin discussion of logical pricing of LNG, and it is hoped that this report makes its own small contribution to that debate.

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The gas dispute between Russia and Ukraine in January 2009 was by far the most serious of its kind. The two sides failed to agree a price for Russian gas supply to Ukraine and a tariff for the transit of Russian gas to Europe before previous agreements expired on 31 December 2008. Russian exports to Ukraine were cut off on 1 January. Exports to 16 EU member states and Moldova were drastically reduced on 6 January and cut completely from 7 January. Deliveries to both Ukraine and other European countries restarted on 20 January following the signing of two new ten year contracts. The most seriously affected countries in the Balkans experienced a humanitarian emergency, with parts of the populations unable to heat their homes. Significant economic problems, but not of a humanitarian kind, were also caused in Hungary and Slovakia.
The crisis has far-reaching consequences. Russia’s reputation as a supplier to Europe and Ukraine’s reputation as a transit country, are seriously damaged. European consumers’ efforts to diversify away from Russian gas, which have previously been discussed, but hardly acted on, may be expected to intensify. Projects that diversify transit away from Ukraine, such as the North Stream and South Stream pipelines, are likely to be prioritized. Further restructuring of the Ukrainian gas sector may also be expected.
This paper outlines the background to, and immediate causes and course of, the crisis. It offers an interpretation of the two sides’ willingness to allow the dispute to damage their relationship with European consumers. It discusses the role of political and economic factors in the crisis, and surveys the likely consequences of the dispute.

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After over a decade of politically sensitive regulatory development regarding third party access tariffs, cost-reflectivity became the European tariffication principle and entry–exit the structure of choice. The Netherlands and the UK are often cited as examples of good implementation of European regulation. This paper analyses the three key regulatory questions that need to be answered:

• which costs are reflected
• how are they reflected in the total revenue requirement
• how is this revenue requirement allocated to shippers

This paper then establishes that these questions are answered very differently in the Netherlands and in the UK. If the advanced implementation of the same set of EU regulations can lead to two different systems in two different countries, the EU regulation clearly fails to streamline regulation. Depending on the regulatory objectives pursued, streamlining regulation may be necessary and renewed regulatory efforts are required. In doing so, the way in which the three key questions are answered is vital.

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