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Weekly Updates1. INTRODUCTION
According to the U.S. Energy Information Administration (EIA), Russia is the largest natural gas supplier, with dry gas production in 2006 of 23.2 trillion cubic feet (tcf) representing over 20% of global output. Russia could also significantly expand production. The Oil and Gas Journal (OGJ) reported Russian proved natural gas reserves of 1,680 tcf in 2007, and the United States Geologic Survey (USGS) reports a mean estimate of undiscovered, technically recoverable natural gas resources of 1,168 tcf and an additional 358 tcf of potential reserve growth in existing fields, yielding a total of more than 3,200 tcf of recoverable natural gas resource.
In 2006, Russian exports, primarily to Europe, equaled 7.8 tcf. Europe as a whole now relies on Russia for about one-quarter of its natural gas supply with the reliance of some countries even higher. For example, Russia supplies over one-third of Germany's requirements, and East European and Baltic countries, which were closely integrated with Russia in the Communist era, are even more dependent.
Gazprom produces more than 80% of Russia's natural gas and controls access to Russia's domestic natural gas pipeline system. While renegotiating export prices to Ukraine in the winter of 2006, when demand in both Ukraine and Western Europe was high, Gazprom temporarily reduced supply to Ukraine. (1) While the principal motivation may have been a desire to raise Ukrainian prices closer to European netback parity, the move was widely interpreted as an attempt to interfere in Ukrainian politics. In addition, the event substantially raised energy security concerns among European consumers.
Concern is also mounting over Russia's ability to meet its future contractual commitments. Although Russian natural gas production was about 10 percent below 1992 levels by 1997, it was above 1992 levels by 2005. Nevertheless, strong growth in domestic demand and exports has required Russia to increase its imports of gas from Caspian states. This, however, may not be sustainable, and prompted the Ministry of Industry and Energy to state in October 2006 that Russia could face a natural gas shortage as early as 2010.
Growth in domestic production requires new investments, but Gazprom is restricted in its ability to use external capital. In addition, Gazprom has difficulty generating internal investment funds since more than 70% of its production is sold domestically at highly subsidized prices (currently approximately $0.80 per thousand cubic feet (mcf) according to EIA (2008)).
In late 2006, the Russian government proposed a gradual increase in natural gas prices to market-based levels and in May 2008, the government approved tariff increases of up to 28.6% in 2008, followed by 19.9% in 2009, 28% in 2010, and 40% in 2011. Fearing the inflationary consequences, the government has stopped short of the original goal of complete liberalization by 2011, at least for the industrial sector.
Even with price increases, gas production may not be sufficient to satisfy demand in the short-term. In addition, a commitment to raise future prices may perversely discourage production in the near term. To the extent that Gazprom can sell less natural gas domestically at current low prices (for example, through quantity rationing or by ceding market share), it will have more gas to sell at future higher prices.
Russian natural gas production in 2006 was 2.4 percent above 2005 output, but Gazprom's share declined from 85.9% to 83.9%. Novatek, Lukoil, and Rosneft collectively had total production capacity of about 6.4 tcf per year in 2006, or about one-third of Gazprom's output. The production share of independent producers is expected to increase in coming years as the Ministry of Industry and Energy has stated that Russian independent producers are expected to supply more than half of the country's industrial needs by 2015 (Blagov (2007)). However, growth of output from these independents may require investments in pipeline capacity, and, perhaps more importantly, full access to Gazprom's existing pipeline infrastructure. (2)
Over half of Gazprom's production comes from mature fields in West Siberia that are declining at an average rate of 0.7 tcf per year according to a recent International Energy Agency report (IEA (2006)). Gazprom therefore needs to develop new fields. According to Glazov (2007), total domestic production must increase substantially by 2030 to meet projected domestic demand and contracted exports. This will have to come from a combination of Gazprom's own production, the production of independents, and imports from Caspian states.
In 2005, Gazprom entered a joint venture to construct the offshore pipeline Nordstream to transport gas through the Baltic Sea from Russia to Germany.3 Gas supply is projected to come from the Yuzhno-Russkoye oil and gas reserve in the Yamal Peninsula, and the Ob-Taz bay and Shtokmanovskoye fields.4 In 2007, Gazprom also announced plans to develop two other fields in the Yamal peninsula to supply existing pipelines through Ukraine and Belarus and financed partly by projected revenues from the price increases to those countries. Finally, Gazprom has also announced plans to upgrade production and transmission systems in Eastern Siberia with a goal of exporting to China (Gazprom (2008)). Despite these announcements, the projects are not much beyond the planning stage and, therefore, the future of Russian gas exports remains uncertain.
In this paper, we use the Rice World Gas Trade Model (RWGTM) to compare the behavior of the world natural gas market in a Reference Case with corresponding outcomes under three scenarios for disruptions to Russian production and exports:
Scenario 1: Yamal peninsula and Kara Sea resources remain undeveloped
Scenario 2: Russian exports are severely, but only temporarily, reduced in 2010, perhaps for political reasons
Scenario 3: Asian pipeline infrastructure from Russia remains undeveloped
2. THE RICE WORLD GAS TRADE MODEL
The RWGTM is a dynamic spatial equilibrium model of the world natural gas market grounded in geologic data and economic theory (see Hartley and Medlock (2006) for more detail).5 The RWGTM proves and develops reserves from existing fields and undiscovered deposits, constructs pipelines and LNG delivery infrastructure, and calculates prices to equate demands and supplies while maximizing the present value of producer rents within a competitive framework.
The resource data underlying the model is based on the USGS World Resource Assessment 2000 and data for existing reserves from the OGJ database. Capital and operating costs for resource development were derived using data from the National Petroleum Council (NPC (2003)). The costs of constructing new pipelines and LNG facilities were estimated using data for past projects available from the EIA, IEA and various industry reports.
Demand for natural gas varies exogenously with economic development, population growth and the price of competing fuels, and responds endogenously to the equilibrium price of natural gas. Data used in estimating the demand relationship were obtained from the EIA, the IEA, the World Bank, the United Nations, and the Organization of Economic Cooperation and Development.
The model has over 290 demand and 180 supply regions. Regional detail varies based on data availability and a country's size and likely influence on the global natural gas market. For example, large consuming and producing countries, such as China, the U.S., India, Russia, and Japan have extensive sub-regional detail. (6)
Model output includes regional natural gas prices, pipeline and LNG capacity additions and flows, growth in natural gas reserves from existing fields and undiscovered deposits, and regional production and demand.
3. REFERENCE CASE
The Reference Case supply projections in Figure 1 indicate Russia will remain the largest single producer throughout the model time horizon.7 It remains the largest single supplier of natural gas to the European market, primarily by pipeline, but it does see a slightly diminished market share as LNG and other pipeline supplies compete into Europe. European consumers have supported the proposed Nabucco pipeline, carrying natural gas from the Caspian states to Europe via Turkey, as a way of lessening dependence on Russia. The Reference Case implies, however, that Turkey only becomes a significant corridor for natural gas imports to Europe once Iraqi supplies are developed. (8) The "East of the Caspian" group of countries (Kazakhstan, Turkmenistan and Uzbekistan) export gas primarily through Russia. Moreover, exports to western China via Kazakhstan do not appear economic, although the option is allowed in the model.
Figure 2 focuses on the Russian exports by source and destination. The figure indicates that most growth in Russian exports originates from Eastern Russia and is destined for Northeast Asia. Eastern Siberian natural gas begins flowing into Northern China at the beginning of the next decade and eventually flows into the Korean peninsula as pipeline capacity is developed. Incremental production in the west comes primarily from supply developments in the Yamal Peninsula, Kara Sea, and Barents Sea, and serves to replace declining production in the mature fields in West Siberia, the Russian Caspian, Volga Urals and Black Sea.
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Again referencing Figure 1, we see strong supply growth in the Middle East, with its share of world production projected to rise from about 12% to more than 18% by 2025 and more than 24% by 2035. The largest Middle East exporters are Qatar, the United Arab Emirates (UAE), Iran, and eventually Iraq. Although Figure 1 shows very strong supply growth in Iran, demand growth also is strong in part because Iran uses natural gas to assist with oil production thus mitigating Iran's ability to export natural gas. Nevertheless, Iranian natural gas is eventually exported as LNG from the mid 2020s, and longer term export growth comes largely via the development of a pipeline to Pakistan and India beginning in 2025. Flows from northern Iran to Azerbaijan, Armenia and Turkey are also expanded, but are highly dependent on developments in Turkmenistan. Iraq eventually becomes the dominant source of exports by pipeline from the Middle East, exporting natural gas produced in the northern and western provinces to Europe through Turkey.
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