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GAS MARKET INTEGRATION:
GLOBAL TRENDS AND IMPLICATIONS FOR THE EAS REGION
University of Western Australia
DISCUSSION PAPER 11.20
Natural gas as a source of cleaner fuels is important in many economies and will increasingly be so important globally. However, many gas markets in the world are either under-developed or fragmented. As trade in gas led by LNG trade increases, market integration as occurred in other sectors has been promoted in various regions of the world. The objective of this document is to review trends in the world’s major gas markets, examine the status of market integration and draw policy implications for gas market integration in the East Asia Summit (EAS) area. The rest of the paper begins with a brief review of global gas markets, in particular gas consumption and trade in the EAS area. This is followed by an examination of gas market integration in the United States (US) and European Union (EU) which are the world’s two largest gas consumers. Subsequently gas market development in individual EAS member economies is explored. Finally implications and recommendations for gas market integration in the EAS area are discussed.
The latest statistics show that in 2010 global gas production of 3193 billion cubic metres (bcm) and consumption of 3169 bcm were almost balanced with a small surplus. Europe and North America account for the lion’s share of total consumption though the shares of the Asia Pacific and Middle East regions are increasing over time (Figure 1). Among the regions, Europe, North America and the Asia Pacific are the net importing regions. In 2010, about 30.8% (975 bcm) of the total volume of natural gas consumed were traded through either pipelines (21.4%) or LNG trade (9.4%).2 As gas resource distribution is geographically unbalanced, the top five traders accounted for about a half of the market share. Specifically, the top five exporters (Russia, Norway, Qatar, Canada and Algeria) provided more than a half of the traded gas. The top importers were in turn the US, Japan, Germany, Italy and the UK which also purchased about 50% of the gas traded internationally (Table 1).
Figure 1. World Gas Consumption by Region, 2010
Note: Data are drawn from BP (2011a).
Table 1. Major Gas Traders, 2010
Note: Data are drawn from BP (2011a).
As both the US and Germany also exported natural gas, Japan was effectively the world’s largest net gas importer in 2010.3 Apart from Japan, other important gas importers in the EAS area include South Korea, China and India.4 In 2010, the largest gas exporters in the EAS area were Indonesia, Malaysia and Australia (Table 1). In absolute terms, EAS importers and exporters (with the exception of Japan) are not yet compatible with the top players in the world. But this situation may change in the coming decades. China’s and India’s gas imports will continue to grow and become key buyers in the global markets. Australia has the potential to become one of the world’s largest gas exporters.
In the past decade (2001-2010), global demand for natural gas has increased steadily with an average rate of growth of 2.8% per annum (BP, 2011a). The share of natural gas in primary energy consumption was about 24% in 2010.5 By 2030 world primary energy consumption is projected to increase by 39% with an annual rate of growth of 1.7% (BP, 2011b). More than half (57%) of the projected growth
in energy consumption will originate from power generation. The shares of gas and non-fossil fuels are expected to gain at the expense of coal and oil. Among the fossil fuels, natural gas consumption is projected to grow fastest, with an annual rate of 2.1% (Table 2). This growth rate projection is slightly higher than the average annual rate of 1.8% during 2008-2035 forecasted by IEA (2011). Non-OECD economies would contribute 80% of the increase in gas consumption (BP, 2011b). By 2030 natural gas, oil and coal could converge to market shares of approximately 26% each in primary energy consumption, with the remaining 22% being equally divided among the major non-fossil fuels, namely, nuclear, hydro and renewables (BP, 2011b). Similar projections are also reported by IEA (2011) in which the predicted shares of coal, oil and natural gas in primary energy consumption are 22%, 27% and 25%, respectively. The driving forces for the growth in natural gas consumption are the increased use for electricity generation (with a growth rate of 2.6% per annum) and industrial activities (2.0% per annum) (Table 2). Part of this consumption growth would be met by increased LNG supply, which is projected to expand at the rate of 4.4% per annum during 2010-2030. If this growth target is reached, the LNG share in global gas supply would increase from 9% in 2010 to 15% in 2030 (BP, 2011b).
Table 2. Projected Average Growth Rates (%)
Note: Data are drawn from BP (2011b) and IEA (2011).
The largest increase in gas consumption would be from the EAS region. Demand is expected to grow at the annual rate of 4.6% during 2010-2030 in Asia excluding Japan (BP, 2011b). Growth in gas consumption would be particularly fast in the two emerging giants, namely China (7.6% per annum) and India (4.7% per annum). Natural gas consumption would amount to 9% of China’s primary energy consumption in 2030. In 2010, 4% of Chinese energy consumption was natural gas. Growth would also be strong in ASEAN. This is confirmed by IEEJ (2009) which predicts that ASEAN as a group would enjoy a rate of annual growth of 4.5% during 2010-2020 and 5.5% during 2020-2030.
The growth in demand for LNG is projected to be around 8.2% per annum in Asia excluding Japan. More than 74% of the increased LNG demand would be from China and India (BP, 2011b). Australia is expected to overtake Qatar to become the world’s largest LNG exporter around 2020. In the aftermath of the Fukushima nuclear power plant accident in Japan, many countries’ policy makers will revisit their nuclear energy programs. This could lead to even more consumption of natural gas in electricity generation in the coming decades.
For decades, gas markets or pipeline gas markets mainly exist locally or regionally. Trade in gas has been limited due to geographic distance. As the oil price increases and the world’s environmental condition deteriorates, natural gas as a cleaner energy becomes more affordable and increasingly a tradable good. Market integration, both sub-regionally and globally, then emerges as a goal to be pursued in many parts of the world. The economic rationale for market integration is well documented in the literature (Williamson, 1996 and Majone, 1996). Specifically, there are several factors which are driving gas market integration in the world. The first factor is the increasing demand for gas consumption due to rising world energy prices and hence increasing affordability to consumers. As a result, numerous local or national gas markets have emerged in the world. In the midst of global economic integration, policy makers in the world economies are keen to promote the link and integration between various gas markets as it has occurred in other economic areas such as the manufacturing sectors and telecommunications. Second, the expansion of LNG trade has made it possible for the emergence of a global gas market where gas can be sold at spot prices or with long term contracts. In 2010, LNG accounted for 30.5% of total gas traded (BP, 2011a). Third, market integration is promoted as a measure to provide the security of gas supply and hence the stability of gas prices.
Various initiatives towards gas market integration have been proposed or implemented so far. In particular the two major gas-consuming regions, namely, the United States (US) and European Union (EU), are leading the world in the promotion of market liberalization and integration. In the United States, gas market regulation began in 1938 when the Natural Gas Act was enacted to guide interstate gas transmission and sales. However, it was in 1978 when the Natural Gas Policy Act was promulgated that gas market liberalization began. The implementation of the Natural Gas Policy Act helped create a single national natural gas market, equalize supply with demand and let market forces establish the wellhead price of natural gas. In 1985, the Federal Energy Regulatory Commission (FERC) issued Order No. 436 which changed how interstate pipelines were regulated and provided pipeline customers more flexibility in purchasing natural gas and making transportation arrangements. The era of open access began (and hence Order No. 436 is also called the Open Access Order). Later, under FERC Order No. 636 (1992), interstate pipeline services were further restructured. Under FERC Order No. 436, pipeline unbundling was voluntary. Order No. 636 made unbundling mandatory. That is, interstate pipelines are required to 'unbundle' their services; essentially separating the sales of natural gas from its transportation.
Due to production deregulation and open access to the interstate gas pipelines, active spot markets for wholesale natural gas throughout the pipeline network emerged rapidly. Through these markets, a large number of gas consumers buy gas directly from a large number of gas sellers on a short-term basis. The spot market share over total gas consumption in the US increased dramatically from 5% in 1983 to 70% in 1987 (Sutherland, 1993). Cuddington and Wang (2006) provide empirical evidence of market integration in the East and Central regions during the 1990s. These authors also argue that limited physical connectivity between the West and other regions made it impossible to create a single national market at that time. To deepen the reforms, the open access order was strengthened by the circulation of two more documents, Order No. 637 and Order No. 639 in 2000. After almost three decades of deregulation, gas market in the US is now the world’s largest and most integrated single market. This is confirmed by empirical findings (Siliverstovs et al., 2005 and Mohammadi, 2011).
The history of gas market liberalization and integration within the European Union (EU) is much shorter than that in the US. As part of the EU economic integration drives, gas market liberalization and integration programs were initiated in the late 1990s. The implementation process began with the introduction of the European Gas Directive in 1998, which was further strengthened by the release of the EU Acceleration Directive in 2003 (EC, 1998 and 2003). These initiatives have brought fundamental changes in the natural gas sector across many European countries. As such, the natural gas industries have transformed from vertically integrated monopolies to more competitive structures (Haase, 2008; Harmsen and Jepma, 2011). However, among EU members, the progress of liberalization is very different. For example, gas market liberalization in the UK started much earlier than in other EU members, and has become the best practice model in the EU. In 1986 the British government privatized the then publicly-owned, vertically integrated gas transporter and supplier in the UK, namely British Gas. At the same time the gas sector was deregulated to allow for competition in the wholesale and contract markets for large consumers while retailing and pipelines were still monopolized. Competition was eventually introduced into the retailing sector (residential and small consumers). Further deregulation led to the break-up of British Gas into several separated entities in the 1990s. Though limited, the initial reform was very successful. According to Juris (1998), during 1986-1995 residential and industrial gas prices fell by 24% and 47% in real terms, respectively, and gas consumption increased by 38% in the UK. Through several reviews and subsequent regulatory interventions and adjustments, deregulation in the UK gas sector has created one of the most liberalized markets in the world. There is now genuine competition at all levels of the gas supply chain in the UK although many more amendments to the Gas Code can be anticipated in the future (Heather, 2010). Natural gas has recently overtaken oil to become the largest source of primary energy in the UK with a share of 39.16% in 2009 in comparison with those of oil (37.41%) and coal (14.93%) according to Heather (2010).
However, gas market deregulation was initiated much later in continental Europe than in the UK. Only in the last decade has market liberalization and regional integration been accelerated in some economies.6 The reform progress in others is slow, but is catching up quickly, for example in Germany, Luxemburg and Sweden. Haase (2008) introduced a scoring method to rank the EU states in terms of gas industry regulatory function and competencies. The former covers issues such as market opening, network access conditions and unbundling. The latter refers to competencies, capacities and degree of autonomy of the regulators. The combined score gives a measure of regulatory comprehensiveness in an economy. According to Haase (2008), the UK was ranked number one in 2005 followed in turn by Demark, Spain, the Netherlands and Italy with France, Sweden, Germany and Luxembourg in turn at the bottom of the ranking list. Since 2005, many countries have moved forward in gas market liberalization. For example, the German Energy Law (Energiewirtschaftsgesetz) was introduced in 2005 with the aim to speed up gas market reforms in Germany (Growitsch et al., 2009).
The experience of the world’s two largest gas consumers, US and EU, shows that gas market integration undergoes a common trajectory, which consists of several steps including the creation of intra-country regional markets, formation of a integrated national market, deregulation and international integration. The implementation of this last step involves the standardization of the gas sector, harmonization of members’ regulatory systems and removal of cross-border trade barriers. EAS members can learn from the experience and lessons in the US and EU and develop a plan for gas market integration in coming decades.
According to the stage of market and regulatory development, we can broadly devide the natural gas markets in the EAS area into three groups: the mature markets, the developing markets and the fledgling markets (Table 3). Relatively more advanced gas markets or the “mature markets” exist in some EAS countries, namely, Australia, Japan, New Zealand and Singapore. A gas market is yet to be created (and hence the term “fledgling markets”) in other countries including Brunei, Cambodia, Laos, Myanmar, the Philippines and Vietnam. Those which stand between the “mature” and “fledgling” market categories are classified as the “developing markets” and include China, India, Indonesia, Malaysia, South Korea and Thailand.
The “mature markets” refer to economies with relatively well-developed gas infrastructure, a large share of natural gas over total energy consumption and a liberalised or partially deregulated domestic gas sector. Among the sixteen EAS members, Australia, Japan, New Zealand and Singapore fall in this category. These economies set the best practice standards within the EAS area and are also in the process of catching up with international best practice.
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