An Overview of International Regulatory Experience

Abstract

As part of our study, we looked at the evolution of natural gas markets in five selected countries that experienced significant increases in gas demand over the last few decades.

* This chapter was overseen by Jigang Wei from the Development Research Center of the State Council and Taoliang Lee from Shell Eastern Trading Corporation. It was jointly completed by Yaodong Shi, Zifeng Song, Ren Miao from the Energy Research Institute of the National Development and Reform Commission and Cindy Wang from Shell China. Other members of the topic group participated in discussions and revisions.

As part of our study, we looked at the evolution of natural gas markets in five selected countries that experienced significant increases in gas demand over the last few decades. In general, these five markets liberalised their natural gas systems in phases, allowing increased competition in the upstream and downstream segments, ensuring fair access to midstream infrastructure such as pipelines and LNG terminals, and striving to ensure that market changes supported overarching energy goals and benefited end users. To varying degrees, the experience of the United States, the European Union, the United Kingdom, Japan, and South Korea shows that natural gas market liberalisation plays a key role in developing and maintaining well-functioning natural gas markets.

Three key factors that determine the development and evolution of natural gas markets are: fundamentals, market regulation and ancillary policies:

• Market fundamentals: The fundamentals of the natural gas market include demand for natural gas in the economy, the availability of sources of supply, and the extent to which sources of supply compete.

• Energy market regulation: Natural gas market regulation is a crucial factor in the development and evolution of natural gas markets. A clear and consistent regulatory framework requires a strong and independent market authority and includes key provisions for the regulation of natural monopolies, safety and environmental rules, particularly for exploration and production, security of supply and market transparency, where competitive markets can exist.

• Ancillary policies: These include policies and regulations that affect natural gas markets indirectly, for example, air quality and climate change legislation that influences the cost-competitiveness of substitute fuels for power generation, policies to encourage and support greater energy access for low-income households, and subsidies for energy-related research and development.

Market fundamentals, energy market regulation and ancillary policies interact to determine market composition. In addition, the entire energy system and even other sectors in the national economy can influence natural gas market regulation and ancillary policies. Likewise, the market fundamentals can be influenced by technological development or by geopolitical events that reduce the relative costs of indigenous and foreign sources of supply.

Turning for a moment to natural gas regulations, these generally have three goals:

• Affordable supply: Providing economical natural gas to end users.

• Secure supply: Making gas delivery more secure, especially in the segments of the natural gas value chain where natural monopolies exist.

• Secondary benefits: Formulating policies that provide knock-on benefits for society as a whole, for example, restricting air pollution and carbon emissions, and providing energy to poor families.

The market liberalisation of natural gas can achieve these three goals. First, market liberalisation can provoke competition, which helps to reduce consumption costs and thus provide affordable energy to end users. Second, market liberalisation opens the market to a more diverse range of suppliers, which can improve security of supply. Third, because market participants will react promptly to any incentive measures contained in secondary policies, the entire natural gas value chain will be able to respond more flexibly to fulfil these policy objectives.

However, market liberalisation also brings greater risks to investment. For example, under free market conditions, domestic natural gas enterprise buying power could be reduced in international markets. Market liberalisation will also make it harder for poor families to obtain energy. Case studies show that governments often use targeted market liberalisation that is restricted or controlled, so as to rein in these adverse influences.

Natural gas market development does not solely rely upon regulation, though. The fundamentals of a market, such as the ready availability of natural gas supplies and the level of natural gas demand, are primary forces in natural gas market outcomes. For example, regardless of the regulatory regime, a country like Japan, with negligible indigenous production, will always have different natural gas market fundamentals than the United States with its large indigenous production. At the same time, competition between natural gas and other fuels will also influence development of natural gas markets, as will a wide variety of other factors such as air quality, climate change, energy sufficiency and electricity market structure, all of which will influence natural gas market development.

International experience suggests there is a core set of actions required to deliver competitive natural gas market outcomes, across a range of different market fundamentals and ancillary policy priorities. The analysis of gas market evolution in different countries seeks to draw general lessons for natural gas market liberalisation, noting contrasts in each region that force different regulatory approaches. The Chinese context will be different again, but the common core of actions across the case studies is likely to be relevant to China, although modified for the country’s unique characteristics. In short, international experience offers important guidance to China as it designs the composition and operation of its natural gas market.

The political sequencing of regulatory reforms is as important to successful market liberalisation as correct implementation. Natural gas market regulation impinges on a number of politically important issues, in particular energy affordability, the funding model for national infrastructure and energy security. When political momentum is supportive of liberalisation, regulatory reform has delivered competitive markets within 10–15 years; for instance, in the United States starting in the late 1970s or the United Kingdom starting in the late 1980s. When political momentum is not supportive, the process of regulatory development could require decades.

In countries with significant domestic natural gas resources, such as Norway, The Netherlands, the United Kingdom, and the United States, market liberalisation has driven increased competition and greater development of these resources. At the same time, the experience of these countries shows that the course of market liberalisation requires favourable upstream licensing, fiscal or environmental policies. In the United States, private ownership of land and the resources underneath it enabled rapid development of shale natural gas exploration and production. Where resources are owned by the government, such as on the outer continental shelf of the North Sea in Norway, The Netherlands and the United Kingdom, processes are in place to enable effective and competitive leasing of exploration and production rights.

Another lesson emerging from the case studies is that interactions between ancillary policies are often unpredictable, such as environmental and technology policies on the one hand and liberalised gas markets on the other. Environmental policies—relating to carbon emissions and local air pollutants—can increase the costs of emissions-intensive coal relative to natural gas. While ambitious policies on climate change and air quality favour natural gas over coal in electricity generation, the design of these policies could produce some unintended consequences. This has been the experience in the European Union, where the interaction between the two has undermined environmental objectives and led to the coal-renewables “energy paradox”. Similarly, the United States has supported energy-related research and development programmes for decades, such as on unconventional natural gas and microseismic fracture monitoring, which eventually proved instrumental in driving the US shale natural gas boom of the last decade.

In summary, market fundamentals, energy market regulation and ancillary policies interact, and shape a country’s natural gas market over time. International experience has shown that technical developments and geopolitical events can affect domestic and international supply costs, and can influence the market fundamentals. Likewise, the market fundamentals have an influence on natural gas market regulation and ancillary policies, and together they all form the natural gas market. Natural gas market liberalisation is thus ultimately dependent on the history of the natural gas market, geography and the political environment, and these major influences are pivotal in the formation of natural gas markets. For example, natural gas market regulation and ancillary policies are determined by political trends and events. This chapter will introduce international experiences from natural gas market regulation, market liberalisation and other perspectives, analysing case studies of foreign natural gas market liberalisation in depth in the hope of providing a reference point for, and insight into, China’s natural gas market liberalisation reforms.

1 Regulatory Reform

1.1 The Reasons for Regulation

Policymakers regulate the natural gas value chain in order to balance three major policy goals:

• Economic supply: Providing affordable heating to households and competitive natural gas prices for power generation and energy-intensive industries.

• Security of supply: The maintenance of a high-quality supply of natural gas to end users. Policymakers also often consider natural gas supply infrastructure to be part of critical national infrastructure required for the functioning of the country and the delivery of the essential services.

• Safe and clean supply: This objective presupposes that natural gas supply should pose minimum risk to public health and safety. It also captures the notion that increased natural gas supply can replace alternative fuels that have a higher direct environmental impact and higher greenhouse natural gas emissions.

These policy goals can conflict on multiple levels, and are often referred to as the energy policy “trilemma”. For example, within economic supply, ensuring affordable natural gas prices for end users has often led countries to subsidise end-user prices, either through cross-subsidisation of one class of users by another or directly from the state budget. Further, delivering economic supply may not always be compatible the with goals of safe and clean supply.

Liberalising natural gas markets can help deliver across the energy trilemma objectives, but may need to be supplemented by a broader policy framework to manage some of the remaining trade-offs. For example, market liberalisation increases competition, which in turn helps to drive down costs for consumers over the long term, delivering an economical supply. It also opens the market to a diverse range of suppliers, increasing security of supply. Finally, policies to encourage natural gas use and increase its share in the energy mix can reduce the risk to public health and safety, for example by reducing indoor and outdoor air pollution and greenhouse gas emissions caused by coal use.

However, liberalisation can also make investment riskier, and fragmented domestic natural gas firms can face reduced buying power on international markets. It can also raise costs in the near term, reducing the ability of low-income households to access energy, unless other policies are put in place to compensate. The five case studies below demonstrate that gas market liberalisation is often limited, or complemented by other policies, in order to manage these impacts.

1.2 The Process of Market Liberalisation Across the Natural Gas Value Chain

Liberalisation refers to the process by which competitive market outcomes are delivered: providing end users with the greatest choice at the lowest price. This can be achieved either by opening markets to competition or through regulatory measures to limit or cap prices where natural monopolies exist. To achieve the goal of natural gas market liberalisation, the structure and economics of the natural gas value chain need to be considered (Fig. 18.1). With the exception of some segments where natural monopolies exist, market competition exists throughout the value chain.

Fig. 18.1

The natural gas value chain. Note Natural monopolies, where markets fail, are mainly in the midstream segment

The natural gas value chain can broadly be divided into three segments—upstream markets, midstream infrastructure and downstream markets. The upstream segment refers to domestic exploration and production of natural gas. The midstream segment refers to infrastructure for the transport of natural gas—domestic and imported—through transmission pipelines, LNG terminals and local distribution networks.¹ The downstream segment refers to wholesale and retail markets supplying gas to end users.

Competitive markets can exist at many places across the natural gas value chain. Competition in the upstream segment can drive greater efficiency and innovation in exploration and production of natural gas, as a way to drive down costs and develop greater volumes and sources of domestic supply. For example, before the liberalisation of natural gas markets in the European Union, vertically integrated and state-owned natural gas companies had little incentive to improve the efficiency of their operations, leading to increases in natural gas prices. Similarly, greater competition in the downstream segment can increase choice and reduce the price paid by the end users of natural gas, for example by increasing competition in the shipping and sales of natural gas. These segments can be opened to competition, within a regulatory oversight framework to ensure and support competitive markets and without the need for further regulatory interventions.

Opening markets to competition is typically not desirable and can fail in the midstream segment. Midstream infrastructure, such as pipelines, are highly capital-intensive. For example, in 2013, onshore oil and natural gas pipeline construction in the United States cost $4.1 million per mile, while offshore pipelines cost $7.6 million per mile. High fixed costs and relatively low operation and maintenance costs point to large economies of scale: the costs of delivery decline rapidly with volume. This fits the definition of a natural monopoly, where the lowest long-run average costs are realised when production and ownership are concentrated in a single firm.

However, enterprises in positions of natural monopolies tend toward using their market position to harm consumers and will collect prices higher than those formed by market competition. In addition, natural gas transmission pipelines and other midstream infrastructure owners are generally vertically integrated, and they provide various services throughout the value chain. Such enterprises will generally take actions to restrict competition, for example collecting excessively high fees from third-party natural gas suppliers and shippers using the infrastructure so as to maintain their leading position in upstream sectors, or else raise their profits in downstream sales business. This results in US and European natural gas market regulatory bodies requiring transmission pipeline owners to open their facilities to third parties, or to regulate the fees collected from customers by the pipeline infrastructure owners. They also insist on the separation of transmission services and upstream or downstream business—this process is called deregulation.

Liberalisation of natural gas markets requires identifying the competitive and natural monopoly segments of value chain, and applying appropriate regulatory approaches. For example, between 1954 and 1978, the United States in effect treated the entire value chain as a natural monopoly, with prices from the wellhead onward fully regulated to protect consumers. As a consequence, US natural gas investment failed to respond adequately to the 1970s oil crisis. The recognition in 1978 that only pipelines are natural monopolies, requiring regulation to ensure open access, marked the start of a period of liberalisation. The reforms unbundled the natural gas industry, separating transportation and sales businesses, and ensured open access to interstate pipeline infrastructure for third parties. By 1992, after 14 years, the fundamentals for a competitive and efficient market had been established, and they supported a 40% increase in natural gas consumption from around 500 billion m³ in 1990 to 700 billion m³ by 2010.

A review of international case studies shows that a competitive, responsive, liquid natural gas market is characterised by:

• Critical mass: Many players that compete for substantial upstream business and access to midstream infrastructure, serving many buyers with large volumes and financed by responsive investors.

• Competitive pricing: Competitive price formation at the wholesale and retail levels.

• Open access: Non-discriminatory open access to natural monopolistic midstream infrastructure, as well as regulated tariffs.

Overall, a competitive market can optimally allocate resources in many stages of the value chain, within an oversight framework to ensure well-functioning competitive markets. However, pipelines are natural monopolies and require more direct regulation. Getting the right combination of competitive markets, regulatory oversight and direct market regulation is essential for unlocking the benefits of liberalisation.

2 Market Liberalisation

2.1 Core Initiatives for Liberalisation

Market regulation is crucial to achieving and securing the liberalisation of natural gas markets. A regulatory framework, codified in law, defines the principles of regulation along the natural gas value chain. It determines which segments of the value chain should be opened to competition and establishes the institutional arrangements to ensure free and fair competition. It also determines which infrastructure is to be treated as a natural monopoly and sets the basis for access to the infrastructure, as well as the level of unbundling for vertically integrated players. The regulatory framework also includes rules around safety, security of supply and environmental standards, which apply throughout the value chain. Implementing the framework requires a strong, independent regulatory authority.

The natural gas market liberalisation experience of the United States, the European Union, the United Kingdom, Japan and South Korea has lessons that might be relevant to China. Each country has different characteristics. For example, the United States has by far the greatest indigenous supply, while the European Union is the biggest importer (Table 18.1). Understanding these differences can help identify experiences that best fit China’s circumstances.

Table 18.1 Market traits of five natural gas markets plus China

The case studies suggest five core actions for liberalisation that can deliver a competitive outcome in the natural gas market, as shown in Fig. 18.2. Creating institutions allows for a fundamental natural gas legal framework and a strong, independent regulatory agency. Enabling open access focuses on assuring fair and reasonable access to infrastructure owned by a natural monopoly. Deregulating prices enables market forces to determine prices and provides clearer signals about supply and demand. Setting standards and ensuring transparency offers regulatory mechanisms to ensure fair market practices. And finally, protecting end users safeguards the interests of commercial and residential natural gas users and seeks to manage any negative consequences of market liberalisation.

Fig. 18.2

Five steps to successful natural gas market liberalisation. Source Vivid Economics

These measures take into account the broader context of natural gas market liberalisation: the need to balance the positives and negatives of liberalisation; interactions with fundamentals and ancillary policies; the importance of natural monopolies in the value chain; and the legacy of state intervention in the natural gas market.

• 1. Creating institutions

Institutions, including a natural gas law and a strong, independent regulator, form the fundamental building blocks of liberalised natural gas markets. Regulators are most effective when they have statutory independence from political, government and industry influence to ensure appropriate decision-making and equal treatment of market participants, as well as to avoid a myopic approach to long-term infrastructure investment decisions. The regulator’s authority and tasks should be laid down in a regulatory framework codified in law.

The case studies below underscore the importance of regulatory institutions being independent of political influences and operating transparently. They illustrate that decisions should be made in a consultative and transparent manner by involving stakeholders, publishing evidence and final decisions, and allowing appeal in court. The regulator should have access to adequate financial and human resources to carry out its tasks satisfactorily.

The US Federal Energy Regulatory Commission (FERC) is a classic example of a natural gas market system foundation operating well. FERC was established in 1997 and is charged with overseeing industries including electricity, hydroelectricity, oil and natural gas. In all of these industries, participants often hold significant market power. FERC regulates the markets to ensure that companies do not misuse their monopoly positions, and its regulatory objectives range from preventing discriminatory service and unfair pricing to promoting environmentally sound infrastructure. FERC’s main responsibilities in the natural gas industry are regulating the rates and services offered by interstate pipeline companies, certifying and permitting new pipeline construction, enforcing competition and preventing market manipulation where markets exist, and handling related environmental issues.

• 2. Ensuring open access

Owners of natural monopoly infrastructure, such as pipelines, have an incentive to misuse their market power, particularly when they are vertically integrated across the natural gas value chain. Regulatory action is generally required in five specific areas:

• Third-party access: This requires owners of networks with natural monopoly characteristics to grant access to their assets to interested third parties. (A detailed review of third-party access experience is presented in Sect. 19.2.)

• Regulating network charges: To prevent monopolistic pricing of transportation services, the tariffs that a network owner and operator can charge for transportation should be regulated. The allowable tariff should be set at a level that encourages investment, but does not price shippers out of the market.

• Unbundling ownership: A vertically integrated company that has natural gas extraction, sales and transportation businesses has an incentive to engage in anti-competitive behaviour, such as charging excessive rates for transportation services, to prevent third parties from competing with its upstream extraction, downstream sales units or both. To enable non-discriminatory open access to networks, the interests of any extraction or sales business should be separated from the transportation services business. This is ideally achieved by unbundling or separating businesses operating in different segments of the natural gas value chain. (A detailed review of unbundling experience is presented in Sect. 19.3.)

• Transparency on capacity availability and the terms and conditions of infrastructure use: Open access and unbundling alone are not sufficient to deliver liberalised markets, and provisions to ensure transparency around midstream transport infrastructure use are vital in enabling competition, both upstream and downstream.

• Release parts of dominant players’ business: Dominant players tend to have long-term contracts with suppliers and customers. The regulator should intervene to break up these contracts so that sufficient market volume is available for entrants.

Granting open access to networks is often initially attempted through negotiated third-party access or voluntary arrangements, leaving network owners free to negotiate terms and conditions for access. All five jurisdictions that were reviewed adopted this approach at first. However, negotiated agreements consistently fall prey to market power abuse by network owners that are vertically integrated with interests throughout the value chain, for example in production, import capacity or local distribution. Such firms have a clear incentive to use their power to prevent entry of competitors.

Third-party access should be regulated carefully, with provisions for allowable network use charges that provide incentives for investment, terms and conditions of use, and transparency around capacity availability, tariffs and terms of use. Even with regulated third-party access, incumbent market supply dominance may need to be proactively broken by the regulator. For example, the United Kingdom regulator forced British Gas, the dominant incumbent in the UK natural gas market, to release parts of its long-term supply contracts in the 1980s so that new entrants could start to compete and serve the market instead.

In terms of establishing fee rates, regulatory bodies should satisfy the requirement to permit open usage of gas transmission infrastructure while also ensuring that gas transmission infrastructure is able to receive ample investments. There are essentially two methods of establishing fee rates: one is the sum of costs method, setting total revenue as equivalent to investment and operating costs plus a reasonable return. Another approach is the incentive-managed pricing utilised by the European Union and United States in recent years, in which pipeline operator costs and permitted revenue are separated and, based on cost baselines or cost analysis models, a baseline revenue is established, along with an additional permitted revenue to incentivise supply quality and other set goals. Together with these two goals, the controlled rates of return always promote investment as an important factor, with set levels both encouraging investment and also not leading to excess investment or insufficient investment. Sometimes, in order to encourage investment, infrastructure need not be required to provide open usage, for example with LNG terminals in the United States and Britain.

Unbundling is a key element in ensuring non-discriminatory access to infrastructure. Owners of pipelines have an incentive to offer favourable terms to their own upstream extraction and downstream sales businesses over other third parties. Authorities observed this anti-competitive behaviour by incumbent firms in the United States in the 1930s and in the United Kingdom in the 1980s. The response in both countries was to require significant unbundling in addition to open access, which facilitated the entry of gas shippers and brokers into wholesale and retail markets. The European Union allows for different forms of unbundling. It allows member states to keep networks under incumbent vertically integrated ownership, with strict arrangements to ensure independent decision-making about transmission system operations. This reflects the desire of EU member states to retain control over who owns and operates vital infrastructure and to maintain a certain degree of buyer power with major import sources. It also reflects the reality that some member state markets may be too small to achieve real competition, and the costs of liberalisation could outweigh the benefits.

Provisions to ensure transparency around midstream transport infrastructure use are vital in enabling competition. Open access and unbundling, even when required by law, are not in themselves sufficient to deliver liberalised markets. In the 1980s, the liberalised United Kingdom natural gas market was slow to attract entrants and generate competition because market participants were not able to acquire essential information on capacity availability and the terms and conditions of infrastructure use. Since then, the United States and United Kingdom have mandated that information about storage availability and capacity and rates for pipeline transport be published on bulletin boards. Compliance is monitored and enforced by the relevant market regulators and competition authorities.

In Japan, open access to LNG terminals has not yet resulted in third-party use, partly because market participants do not have sufficient information. Moreover, following the Fukushima nuclear plant disaster, liberalisation lost momentum in Japan as the country moved to secure increased LNG imports. Japan now encourages collective LNG purchasing by its natural gas importers to protect the economy against volatile LNG prices, although the debate around further natural gas market liberalisation, including third-party access to LNG terminals, resumed in 2014. Similarly, in South Korea, winter peak natural gas demand concerns and volatile LNG prices have led to the protection of its vertically integrated and publicly owned monopoly supplier, Korea Gas (KOGAS), to sustain its buying power on global markets.

Finally, it is important to recognise and address any existing long-term contracts held by the incumbent that create barriers to entry by limiting available capacity and restricting access to midstream infrastructure. These legacy contracts are generally long-standing, reducing capacity available for third parties and therefore preventing competitive forces from taking effect. Regulators can intervene to break up long-term contracts incumbents may have with suppliers and end users, to reduce incumbents’ market share, and to open the market for new entrants. Breaking up existing long-term contracts was a key step in liberalising markets in the United States and United Kingdom: dominant market players were forced to release capacity from contracts to enable market entry and competition.

• 3. Deregulating prices

Prices should be deregulated where conditions exist for the establishment of competitive markets, for example in upstream exploration and production and in the downstream wholesale and retail markets. Deregulating prices is necessary to ensure that economic signals about supply and demand fundamentals are transmitted between market participants. Markets tend to fail when they exhibit natural monopoly characteristics, and in these stages of the value chain—namely transmission and distribution—prices need to be regulated. Elsewhere, however, participants are able to allocate resources efficiently when prices are left to respond freely to changes in supply and demand fundamentals.

Wholesale prices are key transmitters of economic signals because they form the link between upstream exploration and production and the rest of the value chain. Achieving a competitive natural gas market involves a phased liberalisation of wholesale prices. The United States evolved from cost-plus wellhead prices, using netback² and oil-linked contracts, to a system in which spot and futures contracts are the dominant types, traded by a diverse set of participants. The UK market evolved from a price-setting single buyer—British Gas—linking contracts to substitute fuels and inflation to regulated caps and, finally, to more competitive hub-based trading. The end point of price deregulation in these markets has been a liquid and responsive wholesale market.

These market-based prices imply a move away from long-term contracts, which tie the price of natural gas to that of another commodity, or regulated prices, which are set by the government. This has been changing as the volume of natural gas traded, particularly LNG trade, has expanded. In the United States, natural gas is now almost entirely based on market prices, whereas in the European Union it is split evenly between market-based prices and long-term oil-indexed contracts.

Long-term contracts linked to prices of substitute fuels, spot markets prices or other indices offer a degree of certainty for investors to support upstream development. For example, when combined with netback pricing, a take-or-pay clause, which provides a penalty payment if natural gas deliveries are cancelled, can ensure a steady income stream for decades and enable investment in exploration and production. Such clauses are common in the contracts for the Groningen natural gas in The Netherlands. However, long-term contracts may lead to low spot market liquidity and price uncertainty. Moreover, as discussed previously, breaking up existing long-term contracts is crucial to ensure open access, enabling greater third-party access to midstream infrastructure and market entry and competition in the upstream and downstream segments.

Reaching a stage of highly liquid wholesale spot markets can also support upstream development. For example, in the European Union, once natural gas hubs gained sufficient liquidity, contracts were increasingly linked to natural gas spot markets rather than oil prices. In the United States, shale development relied on the existence of liquid spot markets. Developers of US shale plays depended on spot markets because they were unable to secure attractive long-term contracts because of the high uncertainty around field production.

• 4. Setting standards and ensuring transparency

To enable new entrants to enter the market, transparency around market rules is essential, as is a regulator with appropriate legal authority and independence from political parties, government branches and industry in order to enforce transparency requirements. This includes transparency around the terms and conditions for third-party access to networks and disclosure of available capacity on networks. It may also include measures to enhance competition and increase market liquidity in the upstream and downstream segments and, as a result, improve transmission of economic signals between market participants. For example, the regulator can increase upstream competition through the design and implementation of licensing and fiscal regimes using measures such as allowing trade in upstream licences or setting beneficial fiscal terms for exploration and production. The regulator can also standardise trading arrangements in downstream wholesale markets, for example through a network code or other guidelines that help build trust among market participants, or by standardising contracting arrangements to support the creation and development of a natural gas hub.

The regulator can also promote the use of market centres, such as in the case of Henry Hub in the United States and the National Balancing Point (NBP) in the United Kingdom. In the United States, FERC has supported the development of market centres by requiring market players to provide certain services and by standardising trade arrangements. In the United Kingdom, a virtual hub, the NBP, emerged as a result of the Network Code in 1996, which required a location where its balancing mechanism could be implemented by the regulator. The Code was complemented by a set of natural gas trading arrangements that established contract standards, allowing parties to trade natural gas with confidence in contracts.

• 5. Protecting end users

To maintain a competitive natural gas market, regulatory oversight needs to include a competition authority and provisions for managing impacts on end users. A competition authority would be responsible for ensuring well-functioning markets that provide end users with the greatest choice of suppliers at the lowest price. It could also protect consumers, power generators and industrial users that may be disproportionally or inequitably affected by any market reform or resulting market outcome.

Consumer and end-user protection requires the appropriate legal, financial and political support. In the United States, from the 1950s until the late 1970s, consumer protection and, by extension, welfare distribution influenced price setting for natural gas. However, policies to protect consumers and other end users should be disconnected from the gas market liberalisation process. In the long term, liberalised markets generate competition that drives down costs for consumers and delivers sustained low prices. During the transition period, as natural gas markets liberalise, social welfare and equity considerations may result in additional support being provided to the most exposed sections of society and sectors of the economy. The most economically efficient approach would be to allow natural gas markets to liberalise, including price deregulation, and to provide income or other support separately to consumers and end users, for example using social welfare payments or lump sum subsidies. Such an approach would not interfere with the efficient functioning of the natural gas market, while ensuring that the most vulnerable businesses and individuals are protected.

2.2 Political and Economic Factors of Market Liberalisation

The sequencing and timing of liberalisation is significant, and international experience suggests a sequence of reforms that includes key milestones and potential points of tension (Fig. 18.3).

Fig. 18.3

The sequence of five regulatory reforms and potential market reactions. Source Vivid Economics

Initially, vertically integrated incumbents tend to supply all or most natural gas, acting as the monopoly producer and supplier of natural gas. Supply and demand are unresponsive as there is no free price formation that enables transmission of economic signals. The first step of the liberalisation process is to create a natural gas law and establish a natural gas regulator to implement market reforms, including open access to the existing infrastructure and networks for third parties.

Alongside measures to encourage new entrants and facilitate greater competition in the upstream and downstream markets, the liberalisation process requires that a start is made on deregulating prices to that they reflect market supply and demand conditions, for example wholesale markets moving from simple cost-plus pricing to more responsive approaches, such as netback pricing. For midstream infrastructure, network charges need to balance increased third-party access with incentives to invest in maintenance and new network capacity. In the initial stages of liberalisation, incumbents tend to battle to retain their market power, by putting up barriers to entry, contesting regulatory interventions and retaining their long-term contracts. They may also withhold crucial information from the market, such as the capacity available on their networks and information on terms and conditions of third-party access.

The next step in the liberalisation process is to increase market transparency, for example by requiring network owners to disclose network capacity and the terms and conditions for access. In addition, at this stage the regulator may intervene to break up long-term contracts held by incumbents with suppliers and customers. A mature market is one with a strong regulator that can ensure and secure competitive market outcomes and a diverse set of players across the value chain. These players include some integrated firms, but also new entrants, such as pure natural gas shippers, marketers and brokers. If liberalisation is extended to cover distribution networks, natural gas retailers may also emerge to compete for smaller end users. Building on this, the next step would be the establishment of standardised trading arrangements, a balancing mechanism and service requirements to support the development of market centres or hubs as platforms to trade short-term contracts. This allows market liquidity to build and economic signals to be transmitted between the demand and supply sides of the market.

As the market matures, the emphasis of regulatory oversight shifts to end-user protection and the competition authority takes on the role of ensuring fair competition. The focus of policy also shifts to mitigating undesirable impacts of the reforms on end users.

However, a key observation from the case studies is that the reform of natural gas markets is a lengthy and difficult process and is likely to fail if the political context, fundamentals and ancillary policies are not aligned favourably. The United States in the 1970s and 1980s exemplifies a context conducive to natural gas market reform. At the time, there were many upstream producers and network infrastructure was well developed. In addition, there was strong political pressure to make the market more efficient, especially downstream wholesale and retail markets, following the failure of natural gas supply to respond during the 1970s oil crisis. Similarly, in the United Kingdom in the 1980s, the political and market context were conducive to reform. The conservative government of Margaret Thatcher strived to resolve poor government finances by privatising publicly owned industries, including vertically integrated electricity and natural gas companies. Further, the government allowed natural gas to be used in power generation, an opportunity for investors because of the emergence of cost-effective combined-cycle natural gas turbine technology.

On the other hand, liberalisation processes in the European Union, Japan and South Korea provide examples of protracted and incomplete efforts to open up the natural gas value chain. Even today, the European Union faces political opposition in its attempt to liberalise continental natural gas markets, a process that began in 1998. Opposition focuses on concerns over supply security as a result of greater import dependence, as well as over ownership of infrastructure that is in the national interest. Increased global tension centred on Russia, Europe’s main natural gas supplier, and the Ukraine illustrates the risk. Recently announced proposals for a European Energy Union seek to balance these concerns while continuing to push for greater liberalisation of natural gas markets.

Similarly, in Japan, energy security considerations following the 2011 Fukushima nuclear disaster have caused a setback to the liberalisation process, driving towards more co-operation, rather than competition, among the regional monopoly suppliers in securing long-term LNG contracts. However, in 2014, further liberalisation appears to have returned to the agenda. South Korea has also faced difficulties over the past two decades as it tried to liberalise its natural gas markets, largely because of the power of the KOGAS labour union and reluctance by KOGAS to give up its buying power on world LNG markets.

2.3 The Impact of Market Liberalisation on Domestic Mining

The experience of countries with significant domestic natural gas resources, such as Norway, The Netherlands, the United Kingdom and the United States, has been for market liberalisation to drive greater development of these resources. These countries have tended to liberalise earlier and more comprehensively than countries without significant domestic natural gas resources. Before liberalisation, upstream exploration and production tended to be dominated by state-owned vertically integrated monopoly producers. Opening the sector to competition helped drive greater efficiency and innovation in exploration and production of natural gas, reducing costs and facilitating the development of greater volumes and sources of domestic supply, as seen in the European Union. In addition, access to midstream infrastructure and competitive wholesale and retail markets have attracted new entrants and fostered greater competition in upstream exploration and production. With such access, new upstream entrants can be confident of being able to transport natural gas to wholesale and retail suppliers, and eventually to end users.

Liberalisation of the natural gas value chain has also been supported by favourable upstream licensing, fiscal or environmental policies in these countries. In the United States, private ownership of land and the resources underneath it enabled rapid development of shale natural gas exploration and production. Where resources are owned by the government, such as on the outer continental shelf of the North Sea in Norway, The Netherlands and the United Kingdom, processes are in place to enable effective and competitive leasing of exploration and production rights. For example, licensing arrangements in the United Kingdom are designed to encourage exploration and production and penalise hoarding; UK licences can be taken away if companies do not follow the work programme proposed in their bid for exploration and production rights. The Netherlands developed its large Groningen natural gas field through a 50:50 public-private partnership arrangement, which provides a steady income stream to encourage new entrants and greater investment in upstream exploration and production, while also ensuring that the investments were economic and competitive. Specific fiscal incentives and other support policies are also provided, such as in the United Kingdom, to incentivise exploration and production in more-challenging areas.

2.4 Market Liberalisation and Ancillary Policies

There are many interactions between liberalised gas markets and ancillary policies. Ancillary policies, relating to the environment or to technology development, affect the evolution of natural gas markets. Analysis of the case studies shows that while some of these interactions have been anticipated, others have been unpredictable.

Environmental policies—such as the US Clean Air Act Amendments in the 1990s, the more recent US Environmental Protection Agency carbon emission standards, the European Union’s emission trading system to price in carbon emissions, and the EU air quality directives and regulations—can increase the costs of emissions-intensive coal relative to natural gas. While ambitious policies on climate change and air quality favour gas over coal in electricity generation, the design of these policies could produce some unintended consequences. This has been the experience in the European Union, where the interaction between climate policy and energy markets has undermined environmental objectives and led to the coal-renewables “energy paradox”.

While the European Union has an overall target to reduce greenhouse gas emissions by 20% by 2020 over the 1990 level, it also has a separate target for a 20% share of renewables in the energy mix by 2020. The separate renewables target and the large subsidies provided to achieve it have dampened wholesale energy prices because of the low—and at times negative—marginal cost of renewables. This has, in turn, reduced incentives to invest in back-up fossil fuel capacity, which is required to compensate for the potential of intermittent supplies from renewable sources. Moreover, flaws in the design and implementation of the EU Emissions Trading Scheme—the European Union’s primary mechanism for meeting its overall greenhouse gas emissions target—combined with recent weak economic conditions and the relatively low price of coal, have shifted the energy mix towards coal and renewables at the expense of natural gas.

These unintended consequences of energy and climate policies have undermined the profitability of power suppliers and destabilised their business models. The problem is illustrated by the challenges faced by companies like E.ON and RWE in Germany, whose marginal cost pricing-based business model has been put at risk as subsidised and distributed sources of renewable energy of significant size enter the energy mix. Going forward, Europe renewables are likely to remain a significant part of the energy mix to 2030 if Europe is to meet its climate policy ambitions, and electricity market regulation will need to evolve alongside climate policies. In turn, this will have knock-on impacts for natural gas demand and markets.

The natural gas market has also benefited from ancillary interventions, such as energy-related research and development support and subsidies. This has been particularly significant in the context of US shale natural gas development. Various research and development programmes related to unconventional natural gas were set up by the US Energy Research and Development Administration in the 1970s and continued by the Department of Energy. These programmes, along with other research and development programmes, such as those centred on microseismic fracture monitoring, have proved instrumental in driving the US shale natural gas boom of the last decade.

3 Case Studies of Natural Gas Market Liberalisation

Careful study of individual national natural gas markets makes clear the precise nature of the market liberalisation that has occurred as the natural gas value chain has developed. Each market’s liberalisation has its own characteristics, but the ultimate goal is always to establish a more vibrant natural gas system that supports the nation’s strategic goals. Understanding the development of these markets can provide valuable reference points as China formulates its energy system objectives.

3.1 Case Study 1: United States

The development of a dynamic and competitive natural gas market in the United States (Fig. 18.4) reveals three main phases of regulation. These phases are set against a backdrop of events, such as the shale natural gas boom and key regulatory changes, as well as varying levels of gas supply and gas prices between 1960 and 2013.

Fig. 18.4

Phases, development and key regulations in the establishment of a liberalised natural gas market in the US, 1978–1992. Note Nominal natural gas prices paid at power plant, national currency converted to average GDP purchasing power parity. Source Vivid Economics, based on IEA data

The pre-liberalisation phase was marked by gradually increasing levels of regulation over 15 years, which began as early as 1938 and reached full wellhead price regulation in 1954. These price controls were justified on the basis of the perceived natural monopoly characteristics of the natural gas value chain, warranting heavy state intervention to protect consumers from abuse of market power. These interventions echoed earlier interventions in the oil value chain to counteract the anti-competitive practices of Standard Oil and other companies. The price controls suppressed investment and led to significant supply shortages, particularly during the 1970s oil crisis, which were only ameliorated by the subsequent recession.

In response, a new market authority, FERC, was established and several orders to reform the market were enacted from 1978, marking the start of a period of liberalisation. The reforms unbundled the natural gas industry, separating transportation and sales businesses, and ensured open access to interstate pipeline infrastructure for third parties. By 1992, after 14 years, the liberalisation programme had largely been completed. The post-liberalisation phase saw the enactment of various orders to refine the unbundling and open access arrangements, but the fundamentals for a competitive and efficient market had been established and they supported a 40% increase in natural gas consumption from around 500 billion m³ in 1990 to 700 billion m³ by 2010.

• 1. Before market liberalisation

The natural gas market in the United States started in the early 1900s. Before then, natural gas produced from coal was used locally. In the early 1900s, the discovery of large natural gas basins in the Southwest triggered the construction of large-scale natural gas transmission networks to reach the population and industrial centres of the United States. Vertically integrated companies started selling natural gas from basins in the Southwest to end users on the East Coast, the Mid-Atlantic Coast and the West Coast.

A 1935 Federal Trade Commission investigation found high levels of market concentration and abuse of market power by vertically integrated companies in the exploration, production and transportation of natural gas. In response, the Gas Act of 1938 established the Federal Power Commission (FPC) to regulate interstate pipelines and ensure “just and reasonable” wholesale prices. Regulation of intrastate pipelines was left to state regulators. Any purchase of natural gas for interstate transport and sale to a local distributor now required a certificate from the FPC, which set a maximum price for the natural gas. This price allowed pipeline companies to recover some of the costs incurred in pipeline construction and operation. The exploration and production of natural gas remained exempt from federal regulation: wellhead prices remained unregulated. The final sale price to end users was also unregulated. The FPC further gained authority to approve the construction and operation of facilities and the provision of services used in interstate natural gas transmission.

The industry defended deregulated wellhead prices provided for under the 1938 Gas Act. However, by the 1950s, consumer groups were championing a system of regulated prices for both producers and pipelines based on the perceived natural monopoly characteristics of natural gas supply and fear of market power abuse among vertically integrated companies. This debate culminated in the Phillips Decision, which established full wellhead price control by extending the powers of the FPC to “the rates of all wholesales of natural gas in interstate commerce, whether by a pipeline company or not and whether occurring before, during, or after transmission by an interstate pipeline company.”

Throughout the 1950s and 1960s, the FPC struggled to find a satisfactory methodology for setting wellhead rates. Following the Phillips Decision, the FPC initially aimed to establish a cost-of-service rate for wellhead natural gas for each producer. It was administratively challenging and a large backlog developed, complicated by the wide variety of producers, contract types and cases. In 1960, the FPC adopted an averaged approach based on a regional pricing strategy, setting provisional price ceilings based on the average costs of exploration and development in 24 producing regions. There were many hurdles, including a wide variety of production cost profiles within the established regions, and as a result the process was protracted and it was not until eight years later, in 1968, that the first permanent price was established.

This approach to setting prices led to significant natural gas shortages in the 1970s. Rising energy prices, particularly during the oil crisis, led to increased demand for comparatively inexpensive natural gas. Unfortunately, as a result of wellhead price regulation, there was no incentive to invest in exploration and production and, as a result, the supply response was very limited. Significant shortages prevailed by the mid-1970s, and often supply was curtailed for some customers and new customers were refused connections. The Southern states were the exception to these shortages: consumers in these natural gas-producing states remained able to source the natural gas they wanted because these intrastate markets were not subject to interstate wellhead price controls.

• 2. Market liberalisation

The Natural Gas Policy Act of 1978 sought to improve the functioning of natural gas markets by phasing out price controls and establishing a new natural gas market regulator, FERC. The United States had found itself vulnerable to the oil crisis, partly because of the way it regulated upstream wellhead and interstate pipeline prices of natural gas. The new act sought to increase security of supply by improving incentives to invest in indigenous natural gas production. It also aimed to establish a single national natural gas market, with producers allowed to choose their own wellhead prices. Producer market power would be addressed through competition within this new single market.

The act also established a complex transitional system of escalating wellhead price ceilings across more than 30 categories of “old” and “new” natural gas. To encourage new supply, but prevent producers of already-committed natural gas from benefiting from increasing prices, the act established higher initial price ceilings and an accelerated schedule of wellhead price decontrol for new contracted natural gas, which did not apply to old natural gas supplies. The act scheduled the full phase-out of all price controls by the end of the century. But after just 10 years, regulators reviewed the wisdom of market and regulated prices coexisting for such a long period, and the Gas Wellhead Decontrol Act of 1989 hastened the phase-out schedule, dictating that all price ceilings were to be removed by January 1, 1993.

A single market required a single price, so the differential inter- and intra-state pricing had to be ended. The act replaced the FPC with FERC, which was granted authority over interstate natural gas trade (see box “Overview of the US Federal Energy Regulatory Commission”).

Overview of the United States Federal Energy Regulatory Commission

The US Federal Energy Regulatory Commission (FERC) was created under the 1977 Department of Energy Organization Act as a government agency independent from political party influence or affiliation, other branches of government and industry participants. It has a staff of about 1500 and an annual budget of $300 million. It is governed by five commissioners, nominated by the president and confirmed by the US Senate. Each commissioner serves a five-year term, and no more than three can come from the same political party. The commission operates by majority rule.

In a testament to FERC’s independence, the commission’s decisions are reviewed by a court, rather than Congress or any other branch of government, and private discussions during case proceedings are prohibited. In addition, there is a clear distinction between FERC authority, comprising interstate business and infrastructure, and authority held by state governments on intrastate business and infrastructure.

FERC oversees electricity, hydro power, oil and natural gas. Its activities centre on ensuring that companies with natural monopolies do not misuse their market positions, and its regulatory objectives include:

• preventing discriminatory or preferential service;

• preventing inefficient investment and unfair pricing;

• ensuring high-quality service;

• preventing wasteful duplication of facilities;

• acting as a surrogate for competition where competition does not or cannot exist;

• promoting a secure, high-quality, environmentally sound energy infrastructure through the use of consistent policies;

• where possible, promoting the introduction of well-functioning competitive markets in place of traditional regulation;

• protecting customers and market participants through oversight of changing energy markets, including mitigating market power and ensuring fair and just market outcomes for all participants.

The primary responsibilities of FERC in the natural gas industry are regulating the rates and services offered by interstate pipeline companies, certifying and permitting new pipeline construction and handling some closely-related environmental issues.

The 1978 Natural Gas Policy Act led to rising prices, and an increase in long-term take-or-pay contracts. This moved FERC to intervene in 1984 as market conditions drove natural gas prices down, but left buyers paying high prices under long-term contracts. Natural gas contracts in the 1970s were typically multi-year purchasing agreements with take-or-pay clauses obliging buyers, including interstate pipelines and local distribution companies, to pay for a contract volume, whether or not they took the natural gas. The contracted sales allowed upstream companies to recover their investments in exploration and production and provided buyers with a hedge against further expected price increases as a result of shortages.

For a few years following passage of the act, many contracts tied prices to the escalating regulated price ceilings. This became problematic in the early 1980s, when natural gas demand and petroleum market prices declined under prevailing market conditions, diverging from the price ceilings. As a result, some buyers were locked into long-term contracts under which they were paying prices far above spot market prices. In 1984, FERC Order 380 alleviated the burden of take-or-pay contracts by eliminating minimum bill obligations for local distribution companies. The minimum bill represented the amount of natural gas that had to be paid for whether or not the natural gas itself was received. However, although local distribution companies were released from this requirement, pipeline companies remained locked into take-or-pay contracts with natural gas producers.

In 1985, FERC moved to unbundle pipeline and sales services with Order 436, introducing voluntary third-party access to interstate pipelines. This unbundling of transportation and sales services enabled alternative sales arrangements to the merchant package, or the sale of natural gas plus its transportation, which had traditionally been offered to local distribution companies. The order provided incentives to interstate pipeline companies to offer standalone transportation services, in the form of blanket certificates that allowed them to engage in new activities such as opening new facilities without prior authorisation from FERC. Third-party access to pipelines remained voluntary and was to be offered on the basis of negotiated rates. The order did not address open access to other services, such as storage facilities. The changes to voluntary third-party access did not resolve the high cost of take-or-pay contracts of the 1970s, which still haunted pipeline companies. These were addressed by FERC two years later, by Order 500, which allowed interstate pipeline companies to shift some of the take-or-pay liabilities to other businesses in the value chain, leading to the voluntary renegotiation of most remaining liabilities.

FERC Order 636 of 1992, known as the Restructuring Rule, marked the final stage of natural gas market liberalisation, fully implementing the third-party access regime. The order required interstate pipeline companies to unbundle their sales and transportation services, ensuring that natural gas of other suppliers could receive the same level of service as previously enjoyed by the pipeline company’s own natural gas sales. It diminished the market power of pipeline companies and increased competition among natural gas sellers.

The major provisions of Order 636 were:

• A requirement that interstate pipeline companies provide open access to transportation and storage services that are equal in quality, regardless of whether the natural gas is purchased from the pipeline company or elsewhere. This included a provision for companies to create an internal firewall to prevent exchange of information between marketing and transportation divisions. It also included provisions for legal unbundling, requiring companies operating pipelines, storage and LNG facilities to restructure production and marketing branches as arm’s-length affiliates and cease all-merchant services.

• Encouragement of market centres where several pipeline systems interconnect, including mileage-based rather than fixed-tariff or “postage stamp” rate setting for natural gas transportation.

• Establishment of a capacity release market in transportation and storage, with a requirement for pipeline companies to maintain electronic bulletin boards to provide information about availability of services on their systems.

• Redesign of regulated rates for pipeline transportation, shifting all fixed-cost recovery onto firm customers with a daily capacity reservation and not onto interruptible customers without a daily capacity reservation. Variable costs were to be recovered through a usage fee based on the natural gas transported. This was intended to eliminate any distortions in purchasing behaviour in response to the previous design, which allocated certain fixed costs to the usage fee.

• Requirement for pipeline companies to offer “no notice” firm transportation services to local distribution companies, allowing customers to receive natural gas on demand up to their maximum contract level.

Order 636 represented a watershed moment in US natural gas market development. It introduced competition among natural gas suppliers and greater efficiency in the use of natural gas industry infrastructure. The industry restructuring which began with voluntary third-party access under Order 436 and led to mandatory unbundling under Order 636 fundamentally changed natural gas transportation rates and patterns. According to the US EIA, the higher level of flexibility and resulting increased competition among natural gas suppliers “has contributed to changes in regional production, transportation, and consumption patterns, and to greater efficiency in the use of the natural gas industry infrastructure.”

As a result of the new regulatory regime, entities purchasing at the wellhead can negotiate for spot, short-term and long-term contracts at various rates. The market can operate with firm and interruptible delivery of spot natural gas on a contract-by-contract basis rather on the previously prevailing long-term contract obligations. The electronic bulletin boards facilitate offers and bids for natural gas and for pipeline space. Marketers and brokers trading on spot and futures markets collectively clear the market, with higher prices leading to increased wellhead and pipeline capacity supply.

• 3. The impact of market liberalisation

Liberalisation of the US natural gas market has created a system with unique characteristics.

In the upstream market, regulation of exploration and production is mostly within the jurisdiction of states, and therefore highly diverse. At the end of 2013, the United States had 9.3 trillion m³ of proved natural gas reserves, and a wide range of state regulatory provisions covering licensing, ownership and safety and the environment of exploration and production across the country.

Key elements of upstream regulation in the United States are:

• Ownership of resources resides with ownership of land. In the United States, land is mostly owned by private entities. Onshore and offshore resources owned by the federal government are governed by the Department of the Interior and the EPA, which control and administer leases, revenues, land use planning and environmental standards.

• States generally have regulatory commissions that deal with all aspects of the energy value chain within the state. Development of privately owned and federal resources needs to comply with state regulations on safety and the environment to ensure that resource development is safe and environmentally responsible and therefore in the public interest.

• Exploration and production rights for federal resources are auctioned to private entities on an open and competitive basis once land use planning has been determined. Prospective lease holders bid for exploration and production rights. They pay an initial bonus, and then rent for the right to develop the resources. Leases are valid for 10 years or as long as there is at least one producing well.

In terms of regulation of midstream assets, FERC has continued to refine the regulatory framework since 1992 to promote market efficiency and increased levels of competition. Notable further improvements in setting rates and regulating unbundling include:

• In 1999, FERC published a cost-of-service manual, listing transparent guidelines for FERC’s determination of allowable project cost recovery by pipeline companies on the basis of a reasonable rate of return, operating and maintenance costs, depreciation charges and tax recovery mechanisms. This rate of return regulation is a general model for the treatment of natural monopoly utilities, including pipelines.

• The 2000 FERC Order 637 refined and updated pipeline transport regulations relating to rates, including the suspension of price caps on capacity release sales of less than one year, to achieve a greater transparency and efficiency in the use of pipeline services.

• FERC’s Hackberry Decision of 2002 established that LNG import terminals would be exempt from open access requirements to encourage more LNG site development. It allowed the owner of the Hackberry LNG terminal to agree to terms of use with its affiliates rather than under regulated cost-of-service rates. This effectively defined LNG terminals as an upstream supply source, part of the competitive sector, rather than part of the natural monopoly transportation chain, with individual project approval depending on FERC assessment of the general need for the project as well as its economic and environmental impacts.

• The 2003 FERC Order 2004 introduced new functional unbundling regimes applicable to both electricity and natural gas industries, requiring that marketing, transmission and affiliated energy employees of electricity and natural gas companies function independently. The order established the Office for Market Oversight and Investigations to monitor the implementation of functional unbundling, which has since been absorbed into FERC’s Office of Enforcement.

• The 2008 FERC Order 717 further reinforced functional unbundling. It included specific provisions for the physical separation of facilities and staff, for example the separation of occupational functions, which meant that employees can be responsible for work on marketing or on transport, but not both.

Downstream policy is generally subject to local regulations, and remains inconsistent across states. For example, intrastate natural gas commerce is subject to state regulation, and retail unbundling is at the discretion of the state regulator. Only four jurisdictions—New Jersey, New York, Pennsylvania and Washington, DC—have unbundled retail markets. Unbundling is delivered by means of natural gas residential choice programmes in these four jurisdictions. The residential choice programmes allow consumers to purchase the components of natural gas supply separately, rather than relying on the bundled products offered by a single local distribution company.

The regulatory framework has ensured that pipeline companies transport natural gas, but no longer buy and sell it, so they cannot abuse market power based on the natural monopoly characteristics of pipeline infrastructure. This has enabled the construction of 305,000 miles of transmission pipelines and the establishment of a high number of competing market participants. The US interstate and intrastate transmission network comprised more than 210 separate pipeline systems (Fig. 18.5). This system is supported by ancillary infrastructure, including 1400 compressor stations, 24 hubs or market centres, 400 underground storage facilities, 49 pipeline import and export locations, eight LNG import facilities, and 100 LNG peaking facilities. This has also enabled competitive markets in the upstream and downstream segments. It has led to 6300 natural gas producers producing from more than 480,000 wells, including 21 companies considered major producers. There are 160 different pipeline companies, 123 storage operators and 1200 local natural gas distribution companies.

Fig. 18.5

US natural gas transmission pipelines. Note Data for 2009. About two thirds of the length is interstate transmission pipelines. Source US EIA

The liberalisation process, particularly the 1992 FERC Order 636, created the conditions for the rapid growth of natural gas trade through market centres such as Henry Hub as pipeline infrastructure improved and competition increased. Henry Hub, a physical trading hub in south Louisiana, has emerged as the most prominent market centre, with spot and future contract prices based on competitive natural gas pricing rather than oil indexing. It was established by Sabine Pipe Line LLC, a subsidiary of Chevron, in 1989. In 1990, the NYMEX selected Henry Hub as the basis of its natural gas contracts because of its central location and liquidity. Henry Hub now sets the benchmark price for the entire North American trading area. It has emerged as the most liquid natural gas market in the world, trading more than 100,000 natural gas contracts a day, compared to 918 contracts on its first trading day. The scope of NYMEX futures contracts has extended from terms of up to three years in 1997 to up to 10 years at present.

Other hubs have emerged since, such as Opal in Wyoming, where price differentials compared to Henry Hub are determined by regional disparities in production and transport costs. The arbitrage opportunities between regional hub prices drive investment in pipeline capacity. Notably, the recent shale natural gas boom has led to trade volumes shifting to hubs that are closer to shale natural gas fields, such as the Dominion South hub, a key supply point in the Marcellus shale in southwest Pennsylvania. This could result in a fundamental shift of the main price reference point in the United States away from Henry Hub.

The liberalised regulatory framework has enabled the market to transmit economic signals, and encouraged the rapid expansion of shale natural gas production once extraction technology became competitive. On the supply side, price signals led to a surge in shale natural gas production since the mid-2000s. Once drilling and hydraulic fracturing technologies were cost-effective, many firms adopted the technology and secured acreage. Economic growth and price hikes of substitute fuels led to rising natural gas prices in the 2000s and, in response, heavy investment in shale natural gas drilling by incumbents and new entrants alike. On the demand side, market liberalisation coincided with increasing levels of natural gas consumption throughout the economy (Fig. 18.6). The increase was greatest in electricity generation, where natural gas competes directly with alternative fuel inputs, especially coal, but also nuclear and renewables. Increased shale natural gas supply and falling natural gas prices led to a rapid increase in natural gas use for electricity in the last decade.

Fig. 18.6

US natural gas consumption before, during and after the period of market liberalisation. Note Excludes transport, non-energy use, energy industry own use and losses; non-power transformation includes CHP and natural gas to liquids plants; other includes the services, agriculture and fishing sectors. Source Vivid Economics, based on IEA data

• 4. Ancillary policies

The natural gas market has not only benefited from the regulatory framework directly governing it, but also from ancillary intervention, including research and development subsidies and environmental policy.

On the supply side, various research and development programmes related to unconventional natural gas were set up by the US Energy Research and Development Administration in the 1970s and continued by the Department of Energy. These have been important for shale natural gas development. Other research and development programmes, such as those centred on microseismic fracture monitoring, have also contributed to shale natural gas development. Fiscal incentives including tax credits for the production of unconventional fuels under the Crude Oil Windfall Profits Tax Act of 1980 further enhanced the financial viability of shale natural gas extraction.

On the demand side, the competitiveness of natural gas compared to substitute fuels—mainly coal—is a key driver. Emission standards, such as those imposed under the Clean Air Act Amendments (“CAAA”) of 1990, improved the competitiveness of natural gas relative to coal. With effect from 1995, 110 power plants were required to surrender CAAA emissions allowances. The programme was extended in 2000. More recently, in June 2014, the EPA proposed a new plan to cut carbon emissions from power plants, which is likely to further improve the competitiveness of gas.

3.2 Case Study 2: Europe

Liberalisation of the natural gas market in the European Union began as part of the creation of an internal energy market with the First Gas Directive in 1998. Regulatory efforts in the European Union have evolved over decades, passing through various milestones (see Fig. 18.7).

Fig. 18.7

Phases, development and key regulations in the establishment of a liberalised natural gas market in Europe, 1971–2013. Note Nominal natural gas prices paid at border, national currency converted to average GDP purchasing power parity; the average German import price and United Kingdom NBP prices have followed similar paths, apart from a more pronounced drop in the United Kingdom price as a result of the 2008–09 economic recession; TPA Third-party access. Source Vivid Economics, based on IEA data

In 1988, the European Union articulated the goal of creating an internal energy market. It then took a decade for the European Commission (EC) to draft legislation that was acceptable to member states. The First Gas Directive passed by the European Parliament in 1998 included requirements for third-party access and unbundling, although these provisions had been much diluted in negotiations during the preceding decade. The Second Gas Directive, adopted in 2003 and complemented by further regulation in 2005, focused on implementation of third-party access and unbundling provisions introduced in the First Gas Directive. This was achieved through strengthening market oversight across all member states, allowing market authorities to establish cost-of-service tariffs for monopolistic infrastructure, and other mandates. The Third Gas Directive, commonly known as the Third Package, was passed in 2009 and focused on incentivising infrastructure development, providing for stricter unbundling, network planning and supply security. Despite the provisions of the Third Package, the European natural gas market—apart from the United Kingdom market—is not yet fully liberalised.

• 1. Before market liberalisation

Similar to the US experience, before liberalisation most EU member states had blanket regulatory regimes that treated the entire natural gas value chain as a natural monopoly. The natural gas industry structure in each country was similar across the bloc, with the upstream segment of the value chain often dominated by one or a few state-owned, vertically integrated natural gas companies engaged in exploration and production as well as transportation and sales. The downstream segment was dominated by local distribution companies, which controlled distribution and retail monopolies.

As state-owned enterprises, these vertically integrated national natural gas companies had little incentive to improve the efficiency of their operations, which led to increases in natural gas prices. Natural gas markets were governed by national law and were generally exempt from EU competition law, which granted special status to public natural gas companies on the basis that application of competition rules might obstruct the supply of natural gas. The national laws governing public natural gas companies within member states were generally based on similar principles, including exclusive rights to build and operate networks, prohibition of entry, vertically integrated operations, compensation on the basis of historical costs and a high degree of central planning.

• 2. Establishing energy policy objectives

The EC established the creation of an internal energy market as a policy goal in 1988. The internal market is a foundational principle of the EU, codified in the 1986 Single European Act, and aims to facilitate the free movement of goods, persons, services and capital, with competitive markets in all sectors. Although not explicitly part of the Single European Act, a competitive energy sector was deemed a pivotal element in a well-functioning internal market: a competitive energy sector, and the associated energy cost reductions, contributes directly to improved competitiveness of European industries. This position was elaborated in a 1988 EC green paper, The Internal Energy Market, which set out procedures for the creation of an internal energy market, including harmonisation of rules and technical norms, the opening up of public procurement markets and the removal of fiscal barriers.

The EC then set out to develop several directives³ targeting a common carrier system, under which consumers could purchase natural gas from any supplier, regardless of the ownership of pipeline infrastructure. However, the directives faced strong opposition in the Council of Ministers, and the EC had to change its approach to a more staged, bottom-up approach. Complex negotiations ensued, and in 1993 the European Parliament took an active role in finding a compromise that was acceptable to both the EC and the Council. The development of the first Electricity Directive was given priority over a directive covering natural gas. The Electricity Directive was adopted in 1996, with provisions for electricity market liberalisation.

• 3. The beginning of market liberalisation

The First Gas Directive was adopted in 1998. It established a framework for liberalisation for member states, with provisions for third-party access and account unbundling. The directive sought to create a single internal market for natural gas in the European Union, but was a significantly diluted version of the initial EC proposals for a common carrier system. Member states were left free to choose their preferred pace and regulatory measures for natural gas market liberalisation.

The directive required owners of natural monopoly infrastructure, including transmission networks, storage and LNG facilities, to provide open access to third parties. However, member states could still choose between negotiated and regulated third-party access.⁴ Vertically integrated companies were required to separate the accounts of natural monopoly infrastructure and sales businesses, but not necessarily to realise full functional unbundling. The directive further provided that power generators and end users consuming more than 25 million m³ of natural gas a year should be able to choose their suppliers.

The concessions made for political reasons in the First Gas Directive hindered the opening of natural gas markets. The Madrid Forum, an annual meeting of natural gas market stakeholders, was established in 1999 with a remit to identify further harmonisation needs. With 9 out of 15 member states planning to open their natural gas markets fully by 2008, the EC moved to adopt the Second Gas Directive in 2003 and complementary regulations in 2005, establishing requirements for cost-of-service calculations and market oversight by regulatory authorities to expedite the creation of an internal energy market. This time, a new electricity sector directive was adopted alongside the Gas Directive.

The main provisions of the Second Gas Directive were:

• Stronger unbundling: Mandatory functional and legal unbundling for the transportation and distribution sectors and voluntary functional and legal unbundling for storage and LNG facilities, to address issues associated with lenient account unbundling in the First Gas Directive and sluggish development of the third-party access regime.

• Stronger third-party access: A right of third parties to non-discriminatory access to networks and LNG facilities, with the aim of enabling new suppliers to enter the market and providing consumers with a range of suppliers to choose from.

• National regulatory authorities: Mandatory establishment of regulatory authorities in all member states, with responsibility for compliance with non-discriminatory network access principles, ensuring appropriate levels of transparency and competition, setting tariffs and the methodology for calculating them, and settlement of disputes. Establishment of the Agency for the Co-operation of Energy Regulators, which co-ordinates the implementation of Gas Directive provisions by national regulators.

• Principles of network tariff calculation: The establishment of the principles of tariff calculation for natural monopoly networks. These principles should allow pipeline transmission companies to recover costs and receive a return on investments while at the same time providing incentives to maintain existing infrastructure and construct new infrastructure.

• Exemptions for new infrastructure: An exemption for interconnectors, LNG and storage facilities from third-party access requirements and cost regulation, subject to various conditions, in order to reduce and mitigate risks associated with new infrastructure build.

• 4. The Third Package

The 2009 Gas Directive, known as the Third Package, further developed unbundling and open-access arrangements. It sought to create a competitive, secure and environmentally sustainable market in natural gas. To achieve these goals, the Third Package offered member states a choice between ownership unbundling on the one hand and setting up an independent system operator (ISO) or becoming an independent transmission operator (ITO) on the other. The ISO and ITO models are essentially less stringent forms of unbundling. Unlike ownership unbundling, setting up an ISO or ITO would let the transmission network remain under the ownership of vertically integrated firms. Under an ISO model, the transmission networks remain under the ownership of vertically integrated energy companies, but an ISO would be responsible for operation and control of day-to-day business. Investment decisions would be jointly made by the ISO and the owner of the infrastructure. Under an ITO model, vertically integrated energy companies retain ownership of their transmission networks. The ITO would be a legally independent joint stock subsidiary operating under its own brand name, with strictly autonomous management and under stringent regulatory control. Investment decisions would be made jointly by the parent company and the regulatory authority.

The directive recommended ownership unbundling as “the most effective tool by which to promote investments in infrastructure in a non-discriminatory way, fair access to the network for new entrants, and transparency in the market”. Nonetheless, it also stated that setting up an ISO or ITO that is independent from supply and production interests should enable a vertically integrated company to maintain ownership of network assets while ensuring an effective separation of interest. The Third Package thereby implied that there is more than one way to achieve the necessary alignment of incentives along the gas value chain to deliver gas at least cost while still maintaining investment.

In addition, the Third Package further strengthened the independence of regulators from private or public interests to achieve equally effective regulatory supervision across member states. It set out various roles and responsibilities for regulatory authorities, including setting tariffs, ensuring that tariffs are non-discriminatory and cost-reflective, and issuing binding decisions and penalties in relation to natural gas undertakings.

Finally, the Third Package and complementary regulations focused on providing incentives for investment in natural gas infrastructure and ensuring security of supply. The Third Package upheld the exemption from third-party access requirements and cost regulation in the Second Gas Directive for particularly risky new infrastructure, such as cross-border pipelines and LNG terminals. It also introduced new requirements for long-term infrastructure planning, in terms of 10-year network development plans to be developed by transmission network owners and operators. These plans are to be developed at the national as well as European level. National-level plans are binding, and investments by independent transmission operators over a three-year horizon can be enforced by national regulators. The package also allowed member states to impose public service obligations on entities operating in the natural gas sector, mainly in the areas of security of supply, regularity and quality of service, price, environmental protection and energy efficiency. These entities can refuse access to their systems if it compromises their ability to meet these obligations.

In 2010, EU regulations further strengthened security of supply considerations within the context of the internal market. The aim of these regulations was to ensure trade and supply even under extreme and emergency conditions. The regulations put emphasis on infrastructure development to increase internal natural gas flows and external LNG imports. They provided for increased co-operation among member states, introduced supply obligations for companies and established minimum supply and infrastructure standards.

The European Union gas directives weakened state ownership rights in the natural gas value chain, especially in terms of wholesale and retail, as well as promoting transnational pipeline development. Even though the European Union’s natural gas is in the process of being liberalised, and some countries such as The Netherlands and the United Kingdom have already privatised the natural gas wholesale business, nonetheless the majority of infrastructure is still in the hands of the state so as to ensure undifferentiated treatment of third-party access. In contrast to this are the independent company operations by natural gas shippers in The Netherlands and the United Kingdom. In France and other countries, natural gas transmission is operated by vertically unified company subsidiaries, and natural gas transmission companies are very active among the transnational pipelines.

The relationship between the distribution and retail business is becoming increasingly slack. With regard to transmission, the British distribution network is operated by independent companies, while France’s is operated by vertically unified company subsidiaries. Vertically unified companies were traditionally the companies building and controlling reserve capabilities, but after market liberalisation took its first steps, all private entities within Europe began developing underground reserve equipment. In addition, Europe’s various merchants have begun developing LNG facilities.

At the same time, the European Union’s natural gas market liberalisation and natural gas infrastructure planning has been extended, resulting in higher natural gas prices and reduced natural gas consumption volumes. Through strong natural gas network development and the expansion of transmission infrastructure measures and plans, the European Union has stimulated increases in trade with neighbouring regions, as well as the construction of transnational pipelines and LNG terminals.

• 5. The impact of market liberalisation

Since the 1970s, the European Union’s natural gas consumption volumes have grown fivefold. However, in the first 10 years of the 21st century, growth stagnated (Fig. 18.8). The recent drop-off in gas consumption has been as a result of the recession and subsequent low economic growth rates, increasing competition from coal and renewables in power generation, particularly linked to EU climate policies, rising natural gas prices since the onset of liberalisation, and diversion of LNG shipments to Asia as demand rose following the Fukushima disaster.

Fig. 18.8

European Union natural gas consumption volume and structure. Notes Excludes transport, non-energy use, energy industry own use and losses; non-power transformation includes CHP and natural gas to liquids plants; other includes the services, agriculture and fishing sectors. Source Vivid Economics, based on IEA data

The European Union has a well-developed natural gas network, with plans to expand the transmission infrastructure to ease increased trade with neighbouring regions, including cross-border pipelines and LNG import terminals (Fig. 18.8). The EC natural gas directives have led to reduced public ownership within the natural gas value chain, particularly at the wholesale and retail levels, and increased cross-border pipeline development. The European Union has good natural gas networks, and plans to further expand its gas transmission network to promote natural gas trade development with regions surrounding the European Union. This includes cross-border pipelines and LNG import terminals (see Fig. 18.9). The natural gas directives issued by the European Union have reduced the proportion of state-owned assets in the natural gas industry, especially in the wholesale and retail segments, which has greatly accelerated the development speed of transnational pipelines.

Fig. 18.9

European Union transnational pipelines and LNG terminal distribution. Source Euronatural gas

As the European Union’s largest natural gas producers, Norway and The Netherlands complemented the liberalisation and increased access to midstream infrastructure with upstream policies to increase competition. At the end of 2013, Norway had confirmed natural gas reserves of 2 trillion m³, while The Netherlands had 900 billion m³.

Norway developed its reserves by mandating a 50% stake for publicly owned Statoil in each exploration and production licence. The partnership arrangement enabled Statoil to acquire exploration and production capabilities to complement its operational capabilities. Statoil was partly privatised in 2001, and the partnerships transferred to Norway through a new state-owned company, Norway Oil and Gas Revenue Management Company. In 2003, Norway began a series of licensing rounds for new producing areas and further exploration in mature areas on its continental shelf. This has introduced a new set of players to the upstream exploration and production segment.

The Netherlands developed its large Groningen natural gas field through a 50:50 public-private partnership. The state expected this ownership structure to lead to rapid development of the reserves, while maximising the benefits to society. The partnership was based on netback pricing, with natural gas prices regulated at 65–85% of the price of a basket of fuel oils. This arrangement provided a steady income stream to encourage new entrants and greater investment in upstream exploration and production, while also ensuring that the investments were competitive compared to alternative fuel sources.

• 6. Ancillary policies

To achieve the energy trilemma goals of energy affordability, security and sustainability at the same time as employing liberalised energy markets, Europe has a relatively well-developed set of climate and environmental policies.

Under the Kyoto Protocol, in 1997 the European Union-15⁵ committed to reducing greenhouse gas emissions by 8% by 2008–2012 from 1990 levels. (Actual reductions were between 12 and 15%.) Since then, it has since adopted a 20% reduction target by 2020 and a 40% target for 2030. In addition, wider environmental policies, such as European clean air policies, have played a significant role in shaping the energy mix in the power sector. The recently proposed air policy package sets ambitious air quality objectives for 2030.

However, the design and implementation of climate policies interacts with electricity markets, affecting the outlook for gas-powered generation. While ambitious policies on climate change and air quality favour gas over coal in electricity generation, the design of these policies could produce some unintended consequences. For example, by setting a separate 2020 target for renewable energy, the EU Renewable Energy Directive has dampened wholesale energy prices, since the marginal cost of renewables has been low, and even negatives at times. This has, in turn, reduced incentives to invest in back-up fossil fuel capacity, which is needed to compensate for the potential of intermittent supply from renewable energy sources. Moreover, flaws in the design and implementation of the EU Emissions Trading Scheme, the European Union’s primary mechanism for meeting its greenhouse gas emissions target, combined with recent weak economic conditions and the relatively low price of coal, has led to the “energy paradox”: a shift of the energy mix towards coal and renewables at the expense of natural gas.

These unintended interactions between energy market and climate policies have undermined the profitability of power suppliers and destabilised their business models. The problem is illustrated by the challenges faced by companies like E.ON and RWE in Germany, whose marginal cost pricing-based business model has been put at risk as subsidised and distributed sources of renewable energy of significant size enter the energy mix. Going forward, Europe renewables are likely to remain a significant part of the energy mix to 2030 if Europe is to meet its climate policy ambitions, and electricity market regulation will need to evolve alongside climate policies. In turn, this will have knock-on impacts for natural gas demand and markets.

3.3 Case Study 3: United Kingdom

From 1986 to 2002, the United Kingdom implemented natural gas market liberalisation, contributing to the “dash for gas” in the power sector in the 1990s. The process comprised three distinct phases: pre-liberalisation, liberalisation and post-liberalisation (Fig. 18.10).

Fig. 18.10

Phases, development and key regulations in the development of the British natural gas market. Note Nominal natural gas prices paid at power plant, national currency converted to average GDP purchasing power parity. Source Vivid Economics, based on IEA data

The UK natural gas market took off in the late 1960s, when domestic coal gas started to be replaced by natural gas from North Sea basins. At that time, the newly formed Conservative government had just come to power and was facing a weakened economy in 1979. They formulated policies to privatise state-owned industries, using this approach to promote investment without requiring actual financial support from the government. By selling assets, the revenues could be used to prop up government finances, to invigorate business and to weaken the influence of unions.

In the 1980s during the asset sales, the first set of sales included a vertically unified company—British Gas. After the implementation of the Gas Act 1986, British Gas began a process of privatisation, opening access to its pipelines for its competitors, and establishing a natural gas regulator, Ofgas. With the new third-party access agreements, the privatised British Gas was forced to abandon a portion of the content of its existing natural gas supply contracts, unbundling the company’s business to independent subsidiaries and providing space for entry into the market by competitors. The Gas Act 1995 made further progress by promoting retail competition. In 1996, the Network Code was implemented, fine-tuning third-party access rules while building a system for managing daily settlements and national balancing points. In 2002, the newly established settlement mechanisms entered their final stage. In that same year, British Gas sold its transmission business to achieve complete ownership rights spinoff. As an independent British transmission operator, Britain’s National Grid established a national gas transmission network. Following market liberalisation, because of excessive exploration in the North Sea natural gas fields, domestic natural gas production volumes in Britain declined. Further changes after market liberalisation primarily consisted of alterations to the terms of third-party access, improved settlement agreement efficiency and improved supply security.

• 1. Before market liberalisation

In the 1970s, as natural gas supplies continued to increase, the United Kingdom established a state-owned natural gas company. In the late 1960s, self-produced North Sea Basin natural gas gradually replaced domestic coal gas, and the United Kingdom’s natural gas market began to flourish. The Gas Act of 1972 merged the 12 existing area natural gas boards and the Gas Council to create the British Gas Corporation. British Gas was the sole buyer of natural gas produced in and around the United Kingdom. It also held a statutory monopoly on the supply of natural gas to end users. The company relied on flexibility in its long-term natural gas purchasing contracts to provide reliable balancing of input and output volumes on its network. Natural gas purchase prices varied greatly as British Gas negotiated individual contracts with producers. Downstream pricing was based on the weighted average cost of these natural gas purchase prices, a margin to cover transportation and distribution costs, and a profit margin.

In the 1970s, in face of high inflation and unemployment rates, the United Kingdom applied for loan financing from the International Monetary Fund. Poor labour relations and rising oil prices led to the Winter of Discontent in 1978–79, a period of widespread strikes. Margaret Thatcher was elected prime minister of a new Conservative government in 1979. She immediately faced difficulty funding the nationalised energy sectors, which needed to invest to secure supply. The government developed plans for the privatisation of the nationalised industries, to generate income and enable new investment by the new private entities. At the time, privatisation was not driven so much by a desire to increase competition as by the immediate challenge of government finances that could not support the necessary investments in energy infrastructure.

A first move towards privatisation of the natural gas sector was made with the Oil and Gas (Enterprise) Act of 1982, which removed British Gas’s statutory right of first refusal on purchases of upstream natural gas. This effectively opened the market to third parties, although in reality it remained challenging for new entrants to purchase, transport and eventually sell natural gas.

• 2. Market liberalisation

The Gas Act 1986 introduced real competition by sanctioning the privatisation of British Gas and requiring third-party access to transmission and distribution networks. The privatisation of the British Gas Corporation led to the formation of the similarly named British Gas Plc, and the new entity lost its monopoly to supply the largest customers: those using more than 25,000 therms (around 730 MWh) of natural gas a year. The act also obliged the newly incarnated British Gas to grant third-party access to its pipeline infrastructure. Finally, the act established the first natural gas regulator, the Office of Gas Supply or Ofgas.

Competition was slow to develop under the new arrangements. In 1988, a Monopolies and Mergers Commission inquiry found that British Gas’s practices were anti-competitive and that price discrimination prevailed. This led to the recommendation that company be barred from purchasing more than 90% of new natural gas on the market. The company was also instructed to publish prices charged to industrial and commercial customers. The government viewed the initial stages of natural gas market liberalisation to be a political success, and used it as a template for the power sector privatisation that followed in 1989 and 1990.

Competition in the natural gas sector was subject to close government scrutiny in subsequent years, leading to British Gas being asked in 1992 to further reduce its market share to 40% of the natural gas market by 1995. The threshold for British Gas’s large consumer supply monopoly was further reduced to 2500 therms. British Gas also undertook to release some of its natural gas under existing contracts by selling it to other suppliers. Further inquiry into the company by the Monopolies and Mergers Commission in 1993 resulted in the recommendation that British Gas unbundle its divisions into separate subsidiaries. This took place in 1994. It led to the creation of Transco, which had responsibility for transport and storage.

The Gas Act 1995 started a phased introduction of full competition in the natural gas market, including retail competition, which established complete supplier choice in the market. The act established a new licensing system for designated pipeline operators, wholesale companies or shippers, and retail companies. As a result, British Gas lost its majority market position. In October 1990, British Gas controlled all of small-firm supply and 93% of large-firm supply, but by June 1996 these had shrunk to 43% of small-firm supply and 19% of large-firm supply.

The 1996 Network Code established the rules and procedures for third-party access to pipelines and introduced a regime for daily balancing. Transco gained responsibility for securing the physical balance of the system, capacity planning, the forecasting of demand and distribution arrangements, and the overall operation of the system. The code also created the NBP as a virtual location where the transmission system operator could balance the system on a daily basis. The NBP quickly became the United Kingdom’s most liquid natural gas transmission system, and was adopted by traders for nominating their buys and sells on a standardised basis. This was followed by the introduction of natural gas trading arrangements in 1996, which simplified natural gas trading procedures. Further significant reforms in 1999 introduced an on-the-day commodity market to help with balancing and to incentivise to Transco to minimise overall balancing costs. In 1998, an interconnector pipeline between Belgium and the United Kingdom was opened, for the first time allowing natural gas to flow between grids in Britain and continental Europe.

British Gas was restructured several times. In 2000, it broke up into two companies: BG Group, holding upstream assets, and Centrica, encompassing a mixture of upstream and downstream assets. Transco was sold to National Grid in 2002. These combined businesses make up the United Kingdom’s independent transmission system owner and operator for natural gas and electricity markets (Fig. 18.11). In addition, National Grid owns and operates four distribution networks, as well as the Grain LNG import terminal and the Avonmouth LNG storage facility.

Fig. 18.11

National Grid completely owned and operated British transmission networks. Source National Grid

• 3. After market liberalisation

The end of the liberalisation phase in 2002 was marked by full unbundling of the natural gas business. It also signalled the successful transition to competitive and liquid wholesale markets: daily balancing by shippers, with penalties for out-of-balance portfolios, and a role for the transmission system operator to maintain safe balance in the transmission system. In 2005, the Uniform Network Code replaced the Network Code, adding clarity and detail to enable shippers and the transmission system operator to balance more effectively. This included identifying types of capacity held along the natural gas value chain and obliging owners of that capacity to provide stock data to the transmission system operator. The Uniform Network Code has continued to be updated and amended over time to improve practices and ensure the safe and efficient functioning of the United Kingdom’s natural gas supply.

More recently, security of natural gas supply has emerged as a key priority in the United Kingdom. This is governed by several additional codes, including:

• the Fuel Security Code (2007), which grants the Department of Energy and Climate Change the option to instruct power stations to use alternative fuels;

• the National Emergency Plan for Gas and Electricity, which sets out the response to emergency situations—such as supply deficits, storage safety breaches, transportation constraints and the loss of supply to more than 50,000 customers—and describes the roles and responsibilities of market participants; and

• the Transmission Network Planning Code, which is maintained by the National Grid and identifies weaknesses in the UK natural gas transportation system, based on long-term demand and supply forecasts. The code requires a security margin to cover uncertainties in forecasts and a design margin for maximum demand, subject to approval to the regulator.

• 4. The impact of market liberalisation

The liberalisation of the UK natural gas market triggered the “dash for gas” in power generation during the 1990s (Fig. 18.12). The power sector had access to new combined-cycle natural gas turbine technology, which was relatively quick to build. The liberalisation of the natural gas and electricity sectors, along with abundant supply and a lifting of the ban on use of natural gas for power generation, drove a rapid rise in gas consumption as the number of combined-cycle turbines used by power generators increased. The decline in natural gas use in power generation in recent years has been the result market forces which have made natural gas less competitive compared to coal.

Fig. 18.12

UK natural gas consumption by sector, 1960–2012. Note Excludes transport, non-energy use, energy industry own use and losses; non-power transformation includes CHP and natural gas to liquids plants; other includes the services, agriculture and fishing sectors. Source Vivid Economics, based on IEA data

Upstream regulation in the United Kingdom is based on principles of transparency and open access. The United Kingdom had 200 billion m³ of proven natural gas reserves at the end of 2013. The Petroleum Act of 1998 sets out the rules around upstream natural gas exploration and production. Natural gas resources are owned by the state, and the Secretary of State of the Department of Energy and Climate Change is responsible for granting licences for exploration and production rights.

As exploration and production efforts on the United Kingdom’s continental shelf have become increasingly difficult, licensing tenures have lengthened. The Department of Energy and Climate Change assesses bids, focusing on policy objectives including environmental risk and infrastructure quality. If the winner of a licence does not keep up with the agreed work programme or does not meet safety and environmental standards, the department may revoke the licence.

3.4 Case Study 4: Japan

Vertically integrated businesses delivered all aspects of Japanese natural gas supply until liberalisation began in 1995. The development of Japan’s natural gas market has gone through three distinct phases, with liberalisation still incomplete (Fig. 18.13).

Fig. 18.13

Phases, development and key regulations in the development of the Japanese natural gas market. Note Nominal LNG cost, insurance and freight (CIF) import prices converted to US$. Source Vivid Economics, based on IEA data and BP Statistical Review of World Energy 2013

From 1954 to 1995, prior to Japan’s natural gas market being liberalised, it was managed through the 1954 “Natural Gas Business Law”. Under this law, the natural gas industry was monopolised by vertically unified entities. Beginning in 1995, Japan’s government began to implement natural gas sector market liberalisation gradually. Powerful opening up of user rights systems in natural gas transmission, including functional spin-off and outside access of controls, permitted large clients to choose suppliers. LNG infrastructure incorporated negotiated third-party access systems.

In 2011, the Fukushima nuclear disaster had a massive impact on Japan’s energy systems, causing the re-nationalisation of the nation’s major LNG importer, Tokyo Electric Power, in 2012. This marked the end of the Japanese government’s liberalisation plans for the energy market. However, in public debate, natural gas market reforms are continually a focus, and the government has been forced by this pressure to add energy sector competition. After the rise in oil prices due to the Fukushima disaster, because demand grew, and LNG price fluctuations were significant, the Japanese government was forced to change policy to weaken controls on long-term contracts linked to oil. The government has also taken other measures weakening the influence of oil markets on natural gas, including proposing the construction in 2015 of a LNG futures market. The futures market would determine natural gas prices based on domestic demand factors.

• 1. Before market liberalisation

Prior to liberalisation, Japan’s natural gas market was governed by the 1954 Gas Utility Act. Under this act, the natural gas industry was regulated as a vertically integrated monopoly. Companies wishing to enter the natural gas market needed licences from the Ministry of Economy, Trade and Industry. The vertically integrated natural gas companies were responsible for importing LNG, and the city natural gas companies were responsible for distribution. Tokyo Gas, Osaka Gas and Toho Gas were major vertically unified natural gas companies responsible for the import of natural gas, operation of LNG terminals, the storage of LNG, operating natural gas transmission distribution networks, as well as retail business. The smaller-scale city natural gas companies also provided distribution and retail services, reselling natural gas purchased from the vertically integrated companies. Power generators were allowed to import LNG for their own use, including large users such as Tokyo Electric Power (TEPCO) and Kansai Electric Power.

• 2. Market liberalisation

The Japanese government gradually introduced liberalisation in transmission, distribution and LNG facilities beginning in 1995. Natural gas prices in Japan have long been higher than the average in OECD countries, and the Japanese government sought to reduce prices by introducing competition, with open access to infrastructure and unbundling. The first two phases of liberalisation, in 1995 and 1999, focused on the transportation and distribution sectors.

People believed that these two stages were not successful. Since 2003, oil prices have remained high and, compared to oil products, natural gas has become more attractive, with subsequent rises in natural gas demand. Therefore, beginning in 2003, the government started to implement more unbundling measures. Although there not a complete opening of LNG infrastructure to third-party access, nonetheless this stage began to implement open access.

The Gas Utility Act of 1995 attempted to introduce negotiated third-party access and unbundling, but was unsuccessful. The act introduced mandatory negotiated third-party access, allowing large natural gas consumers with an annual natural gas consumption of more than 2 million m³ to buy natural gas from non-incumbent natural gas suppliers. Tokyo Gas, Osaka Gas and Toho Gas were required to unbundle their services. However, almost a decade later these three companies still accounted for more than 70% of domestic sales (Fig. 18.14).

Fig. 18.14

Japan natural gas market sales volume, 2012. Source Osaka Gas (2012)

This regime was not considered successful in opening the natural gas market as terms and conditions for access were not sufficiently standardised and transparent. The companies using or seeking access to other companies’ pipeline complained of entry barriers and non-transparency in the wheeling system which moves natural gas from one system to another. Many of the complaints related to the lack of information on the available capacity of pipelines, non-transparent standards and procedures for assessing fees, and other compensation mechanisms.

The Gas Utility Act was revised in 1999 to introduce regulated third-party access, expanding from the three largest vertically integrated companies to include a fourth, Saibu Gas. The threshold for eligible consumers was reduced by half, to 1 million m³ in natural gas consumption a year. Natural gas companies were also required to publish the terms and conditions for use of their transportation and distribution pipelines.

When the first phase of liberalisation did not achieve an effective open-access regime, further unbundling and market transparency measures were adopted from 2003 onwards. High oil prices provided added impetus, making natural gas more attractive compared to oil products and substantially raising demand. In 2003, account and functional unbundling were introduced to separate natural gas transportation businesses from sales businesses by requiring separate filings of accounts and a separation of day-to-day management. The reforms also sought to open LNG terminals. The threshold for customers to be eligible for third-party access was further reduced to 500,000 m³ a year in 2003 and again to 100,000 m³ in 2007 (Fig. 18.15). By 2007, 61% of the natural gas market by volume was deregulated, and this was unchanged in 2013.

Fig. 18.15

Japan’s natural gas market liberalisation progress. Source Osaka Gas

In addition, open access was extended to all natural gas companies with eligible customers. Natural gas companies were required to prepare standardised third-party access contracts with terms and conditions for transportation services that were to be approved by the energy authority.

Japan does not have a well-developed long-distance natural gas transportation network. There are no cross-border natural gas pipelines and the high-pressure transmission natural gas pipeline length is only around 2500 km (Fig. 18.16), compared to 500,000 km in the United States. Although there are around 43 main interconnection points between areas, the trunk line networks are not necessarily connected to each other as they have separately developed around LNG terminals. The lack of interconnection between regions may limit the scope for competition through third-party access.

Fig. 18.16

Japan LNG terminals and high-pressure pipelines. Source IEA (2013)

Starting in 2003, there were calls in Japan to delay the development of national high-pressure natural gas pipeline networks, on the grounds that managed third-party access terms could reduce the incentivising effect of natural gas infrastructure investment, and hinder energy security.

In 2003, there were natural gas legal reforms, with LNG infrastructure sectors implementing negotiated third-party access plans.

The need for open access in LNG infrastructure was included in the 1999 US-Japan Third Joint Status Report under the Enhanced Initiative on Deregulation and Competition Policy, an offshoot of economic co-operation efforts between the two countries. The issue was particularly relevant as LNG terminals are the entry points for imported natural gas, and without free access to LNG terminals and storage facilities, only a limited degree of competition, if any, would be possible in Japan. In response, the Japanese government amended the Gas Utility Act in 2003 and introduced an open-access scheme for LNG facilities. Under this scheme, natural gas companies were to define preconditions for negotiated access. Further transparency requirements related to the capacity information for LNG storage and facilities were also applied. However, by 2012, no third-party access had been effectively granted to any company at a Japanese LNG terminal.

• 3. Prospects for continued liberalisation post-Fukushima

After the Fukushima nuclear disaster in 2011, the appetite for further liberalisation in natural gas markets in Japan diminished further. The renationalisation of TEPCO, a significant LNG importer, in 2012 epitomised the change in momentum regarding energy sector liberalisation that followed the Fukushima disaster. However, in 2013, a plan for reforms to deregulate the electricity market was passed, signalling a renewed interest in energy sector reform. The electricity sector is particularly important to Japan’s natural gas market because it accounts for about two-thirds of the country’s total natural gas consumption and that share has grown rapidly since the Fukushima disaster (Fig. 18.17).

Fig. 18.17

Major components of Japanese natural gas consumption. Note Excludes transport, non-energy use, energy industry own use and losses; non-power transformation includes CHP and natural gas to liquids plants; other includes the services, agriculture and fishing sectors. Source Vivid Economics, based on IEA data

Japan’s 10 regional electricity utilities have sought to increase regulated electricity tariffs paid by end users to help cover their costs. Since 2012, the Ministry of Economy, Trade and Industry has approved tariff increases of between 7 and 11% for six utilities. In 2013, the first of three electricity market reform packages was passed, to reduce LNG procurement costs through competition between electric utilities. The measure established an Organization for Cross-Regional Co-ordination of Transmission Operators to promote the development of electricity transmission and distribution networks and to enhance the nationwide function of adjusting the supply-demand balance of electricity. The second reform measure would fully liberalise entry to the electricity retail business and the third would require legal unbundling of the transmission and distribution sector.

As Japan depends heavily on LNG imports to meet its electricity generation needs, the government has sought to ensure diversified LNG supply based on cost-efficiency and energy security. The key elements of Japan’s overall energy security policy are diversifying its long-term supply contract portfolio, ensuring contractual flexibility to increase imports in an emergency and using voluntary commercial LNG stocks in industry. Japan’s largest natural gas supplier, Australia, represented just 21% of total imports of the country in 2013, illustrating the diversity of Japan’s natural gas suppliers (Fig. 18.18).

Fig. 18.18

Four major country suppliers of LNG gas imports to Japan since 2000. Source Vivid Economics, based on IEA data

In recent years, Japan’s proportion of imports from Malaysia and Indonesia has dropped, while import proportions from Australia and Qatar have increased.

• 4. Focus: Japanese natural gas pricing

Traditionally, Japan’s natural gas contracts have been linked to oil prices, but the government has already begun to weaken the influence of crude oil prices. In the 1970s and 1980s, long-term LNG import contracts were closely linked to international crude oil prices. These contracts are about to expire, and importers are being forced to renegotiate contracts or else lock into shorter-term supplies. Crude oil price increases have led to dual increases in cost and electricity prices in obtaining LNG.

Japan’s METT encourages electricity companies to negotiate in order to obtain LNG at prices the same or lower than previous contracts, as a prerequisite to collecting higher fuel fees from electricity consumers. Japan’s natural gas and electricity companies also carry out negotiations for LNG contracts, and these contracts are not restricted by crude oil prices that are lower than natural gas market prices in the United States. For example, Kansai Electric Power came to a long-term agreement in 2012 with British Petroleum, and this agreement was governed by the US Henry Hub price. In 2012, Japan’s government proposed establishing a LNG futures market in March 2015, with the futures market determining natural gas prices based on domestic demand factors. Japan released its latest strategic energy plans in April 2014, encouraging natural gas and electricity companies to carry out targeted loosening of LNG long-term contract terms. Beginning in 2012, many companies were already carrying out US upstream liquefaction projects, and this will account for 20% of Japan’s total natural gas demand.

Furthermore, Japan’s LNG importers have formed partnership relationships with the region’s other LNG purchasers in order to increase negotiating power and reduce purchase prices. For example, Tokyo Electric Power formed a full alliance in October 2014, covering the entire energy supply chain, with Chubu Electric Power. Their co-operation incorporates a wide arrange of activities, whether it be in upstream investments and procurement of fuel for power plants, or carrying out a series of joint projects, including natural gas upstream investment on a global scale, construction of new thermal power plants and procurement of LNG.

3.5 Case Study 5: South Korea

Since 1997, South Korea’s efforts to liberalise the natural gas sector have led to partial unbundling and open access, but progress has been slow in the wake of political resistance that began in the early 2000s (Fig. 18.19).

Fig. 18.19

Phases, development and key regulations in the establishment of a liberalised natural gas market in Korea. Notes Index of wholesale prices is the natural gas sub-index of the producer price index; 2010 = 100. Source Vivid Economics based on IEA data

Prior to market liberalisation in 1997, KOGAS (a state-owned corporation) was the exclusive owner of LNG infrastructure and natural gas transmission facilities. In 1997, the government attempted to break KOGAS’s import monopoly. Even though some large-scale natural gas users could directly import natural gas for their own use, KOGAS still maintained its substantive monopoly in LNG, transmission and wholesale supply. In the first 10 years of the 21st century, after the natural gas supply crisis, market liberalisation progress halted. Moreover, California’s major power cuts not only increased worries about the compatibility of electricity market liberalisation and energy security, but also weakened political determination. Finally, opposition from trade unions at KOGAS further impeded the implementation of government reform plans.

• 1. Before market liberalisation

Before liberalisation began in 1997, the state-owned utility, KOGAS, was the sole owner of LNG infrastructure and natural gas transportation facilities. KOGAS is a vertically integrated state-owned natural gas company formed by the Korea Gas Corporation Act in 1982. Similar to the vertically integrated regional monopolies in Japan, KOGAS was primarily an import-oriented company, given the lack of indigenous natural gas production in South Korea, and it controlled and operated LNG terminals, storage and natural gas transportation pipelines.

The City Gas Business Act of 1983 established city natural gas companies and introduced a regulatory framework comprising licensing requirements for the supply of natural gas, the construction of natural gas facilities and the terms and conditions of natural gas supply. The main business of the city natural gas companies was to buy natural gas from KOGAS or liquefied petroleum natural gas from oil companies and distribute it to customers. This local distribution system has remained largely in place, and there are 30 privately owned city natural gas companies, each of which enjoys exclusive retail sales rights within its areas.

• 2. Market liberalisation

In response to the 1997 Asian financial crisis, the South Korean government announced plans to liberalise the natural gas sector by introducing competition and privatising KOGAS. The 1997 National Energy Plan set the main framework for natural gas liberalisation and privatisation, but did not specify detailed regulatory changes. In 1999, the South Korean government developed the Basic Plan for Restructuring the Gas Industry. The assets and staff of KOGAS were to be divided into two groups: infrastructure, including receiving terminals, pipelines and storage infrastructure; and import and wholesale functions. KOGAS would retain ownership of the infrastructure group, while the import and wholesale divisions were to be further split into three natural gas supply subsidiaries by the end of 2001. Of these three trading entities, one would remain a subsidiary of KOGAS and the other two would be independent.

The government succeeded in partially privatising KOGAS, and 39% of the equity was sold by the government by the end of 1999. However, the plan to further privatise and unbundle KOGAS was not completed because of fierce opposition from the company’s labour union. Additionally, the country faced a domestic natural gas supply crisis at the time when detailed privatisation plans were being discussed. Natural gas demand from the residential, industrial and power sectors rose sharply, raising concerns over energy security (Fig. 18.20). The electricity blackouts in California further fuelled concerns about whether liberalisation and energy security were compatible. These factors together undermined the political appetite for electricity and natural gas sector liberalisation.

Fig. 18.20

Korean natural gas consumption by sector. Note Excludes transport, non-energy use, energy industry own use and losses; non-power transformation includes CHP and natural gas to liquids plants; other includes the services, agriculture and fishing sectors. Source Vivid Economics based on IEA data

Although the 1999 Restructuring Plan stalled, a voluntary service unbundling initiative and a negotiated third-party access regime were introduced for KOGAS infrastructure. In 1999, the City Gas Business Act abolished part of KOGAS’s monopoly on importing LNG and operating LNG infrastructure. The act set out a regulated third-party access regime, but it lasted only a short time before being suspended in 2000.

Despite the reform efforts, third-party access to LNG storage facilities, the transmission network and LNG terminals owned by KOGAS has been limited. In 2002, KOGAS remained the dominant natural gas player, even while large users like Pohang Iron and Steel Company operated their own LNG import terminals and imported LNG for their own use (Fig. 18.21).

Fig. 18.21

Korean natural gas industry structure. Source Asia Pacific Energy Research Centre

Energy security concerns over LNG market volatility and meeting peak winter demand have hampered progress in natural gas market liberalisation. The importance of diversified LNG supply sources, ensuring LNG supply on the basis of long-term contracts, and expansion of storage capacity to meet high seasonal demand are perceived to outstrip the potential benefits of liberalisation. The government promotes the participation of KOGAS in upstream natural gas production abroad and strives to preserve its position on world LNG markets, where KOGAS is the single largest buyer of LNG. For example, the Tenth Long-Term Gas Supply and Demand Plan, published in 2010, proposed that KOGAS secure oil-indexed long-term contracts with improved flexibility and conditions from 2015. This makes it unlikely that plans to privatise KOGAS will be revived soon, and the government is likely to continue to exert a direct, commanding influence on South Korea’s natural gas sector.

KOGAS owns and operates Korea’s national pipeline network and three quarters of the country’s LNG terminals. Korea currently has no transnational natural gas pipelines. Its national transmission pipelines stretch for 3588 km (Fig. 18.22). According to plans announced, this will be extended to 4928 km by 2027.

Fig. 18.22

Korean LNG terminals and pipeline networks. Source IEA (2011)

The majority of Korea’s contracts are linked to the price of crude oil. KNGC has signed mid-term and long-term contracts linked to crude oil for the import of 80–90% of its LNG, with the remainder being through spot market purchases. In 2012, Qatar was the largest supplier of natural gas to Korea, followed by Indonesia, Oman, Malaysia and Yemen (Fig. 18.23). Among the 10 long-term natural gas supply and demand policies announced in 2010 was the proposal that, beginning in 2015, KNGC should ensure that oil-linked long-term contracts increase their degree of flexibility and terms. Further co-operation between Korea and its LNG importing neighbours (such as Japan) could improve buying power as part of new long-term contract agreements.

Fig. 18.23

Major importers of natural gas to Korea, 2012. Source Vivid Economics, based on IEA data (2012)