A Close Look at the Natural Gas Industry Chain

Abstract

The previous section set out international experience in the development and evolution of natural gas markets. A key insight from the five country case studies is that liberalisation requires different regulatory approaches for different parts of the natural gas value chain.

* 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.

The previous section set out international experience in the development and evolution of natural gas markets. A key insight from the five country case studies is that liberalisation requires different regulatory approaches for different parts of the natural gas value chain.

This section draws from international experience and takes a closer look at regulatory efforts at specific points of the value chain. In the upstream segment, countries have encouraged exploration and production by increasing competition, including through fiscal and licensing regimes, to encourage new entrants into the industry. In the midstream segment, where natural monopolies exist, third-party access to transmission and distribution infrastructure has been crucial. In addition, some degree of unbundling of companies integrated across the value chain has been essential, both to reduce anti-competitive behaviour with respect to midstream infrastructure and to encourage competition across the natural gas value chain. In the downstream segment, countries have encouraged greater competition in the wholesale and retail markets supplying end users. Countries with significant domestic natural gas resources have liberalised their wholesale markets by encouraging greater competition and the establishment of natural gas hubs.

1 The Upstream Segment: Fiscal Policies and Licensing Systems

In addition to furthering a government’s fiscal objectives, these regimes have important implications for the development of a country’s oil and natural gas resources, the natural gas regulatory environment, the relationship between various levels of government and various agencies, and the overall nature of the oil and natural gas industry.

Upstream fiscal and licensing regimes play a critical role in the development of a country’s oil and natural gas resources. The two of them work in unison to offer benefits by incentivising investments and strengthening market competitiveness. Through an analysis of the experiences of the United States, Australia, Argentina and Mexico, this section carries out an in-depth exploration of natural gas upstream sector financing and taxes, permit system arrangements, and co-ordination and contact between various levels of government, all of which can be useful as references as China formulates similar policies.

1.1 International Taxation and Licensing Systems Regulating Upstream Production

Our analysis of international experience in fiscal and licensing regimes to regulate the upstream produced four overarching observations.

• Unconventional resources: International experience in crafting fiscal and licensing regimes shows that policy makers need to consider the fundamental differences between the exploration and development of conventional natural gas reserves and that of unconventional reserves. Unconventional natural gas developments have an ongoing need to explore, develop and produce on order to find the most productive areas, the so-called “sweet spots”. These are characterised by shorter plateaus and more rapid depletion of reserves than conventional natural gas wells. As a result, unconventional operations require ongoing capital expenditures, whereas the majority of capital costs for conventional operations occur at the start of a development. Moreover, unlike conventional operations, unconventional natural gas developments typically require significant quantities of water, potentially affecting water availability for other users in the area, as well as water quality from the run-off and discharge of water used in processes such as hydraulic fracturing. This requires appropriate policy frameworks and processes to manage and minimise these impacts.

• Co-ordination across government tiers: Fiscal and licensing regimes should also take account of the interplay between national and regional authorities. Each level of government has an important role to play in the development of a country’s energy resources, in terms of taxation and wider policy development. A review of experiences in the United States, Australia and Argentina shows that national and regional governments typically share the revenues generated, both directly and indirectly. Co-ordination between national and regional authorities is also required in terms of regulatory policies. For example, in the United States and Australia, access to midstream infrastructure—essential for encouraging competition in the upstream and downstream segments—requires policy co-ordination and alignment between the national and state governments.

• Looking across the value chain: Fiscal and licensing regimes have a direct impact on promoting upstream developments, but they are just one part of an overall energy approach. Efforts to stimulate other parts of the value chain, especially demand, can have a profound influence on upstream activities. In Australia, for example, regulatory support for a switch to natural gas in power generation created momentum for greater domestic exploration and production.

• Balancing the need for foreign investment and expertise with domestic interests: Investment in upstream exploration and production is often supported by foreign direct investment (FDI). However, at times, increased FDI can also create tensions with national oil companies or concerns that national interests are being neglected. The experience of Mexico and its Bid Round Zero illustrates how countries can balance these interests, providing opportunities and safeguards for domestic companies while bringing in foreign funding and capabilities.

1.2 Case Study 1: The United States—Leasing, Taxation and Development of Information Sharing

Under the United States federal system, most regulations for the oil and natural gas industry are enacted and enforced by the individual states. The US upstream investment regime uniquely is underpinned by ownership of mineral resources by the owner of the land. This means that onshore ownership of the resources is by private individuals, and private leases can be negotiated without a licensing authority. The exception to this norm concerns federal and state land, where the relevant government authority issues leases through tenders. For federal land, the Bureau of Land Management is responsible for issuing leases (Fig. 19.1). For federal waters—typically beyond three miles of the coastline—the Bureau of Ocean Management is responsible for issuing leases. Federal leases typically have a term of 5–10 years and can be renewed as long as production attributable to the lease continues.

Fig. 19.1

US federal public land surface and underground levels. Source US Bureau of Land Management

With regard to the mining of natural gas, federal and state governments in the United States primarily use a tax and royalty regime. Onshore rates range from 12.5 to 30%, while the offshore rate is 18.75%. Most states also charge a severance tax, with its structure and level varying by state. For example, the Texas severance tax is 7.5% of the market value of the natural gas, while in neighbouring Louisiana, the severance tax is set each year based on NYMEX Henry Hub settled prices and on spot prices in the state. In 2014, this was 16.3 cents per thousand cubic feet.

The regime in the United States is also characterised by significant information sharing around the development of tight and shale natural gas, often cited as a reason behind the country’s successful development of unconventional oil and natural gas resources. Data on permits, drilling, testing and production is required to be made available in a timely manner, although the details vary from state to state. Interested parties can obtain the information directly from the state or from consulting companies that collect such data. In addition to legal disclosure requirements, companies also have incentives to disclose information—occasionally including details on individual wells—to support their share price and their efforts to raise capital. Publicly traded companies are also required to submit detailed quarterly and annual reports to the federal government, which are publicly available. In addition, several federal government agencies, including the US Geological Survey, the Department of Energy and the Energy Information Administration, monitor and publish key statistics weekly, quarterly and annually. Adding to the data flow, industry associations, technical and business journals, investment reports and conferences provide a platform for upstream companies, investment banks, academics and government to exchange information.

1.3 Case Study 2: Australia—Licensing, Finance and Taxation, and Third-Party Access

According to forecasts, in the near future Australia will become the largest LNG exporter in the world. It has liquefaction capacity of about 26 million metric tonnes a year in operation, and is expected to add about 62 million metric tonnes in additional capacity over the next several years. The new projects include three projects in Queensland, primarily using coalbed methane to produce LNG. A diverse range of companies are involved in onshore Queensland natural gas production, including PetroChina, Sinopec and the China National Offshore Oil Corp. (CNOOC).

Australia’s domestic natural gas system comprises the East Coast market, covering Queensland, New South Wales, South Australia, the Australian Capital Territory and Victoria, and the Western Australian market, covering the rest of the country. Australia does not have an extensive pipeline network, especially compared to Europe or the United States, because demand is highly concentrated in the various state and territory capitals and because supply has historically come primarily from two basins, Cooper and Gippsland (Fig. 19.2).

Fig. 19.2

Australia’s natural gas basins and major transmission pipelines. Source Australia Energy Regulator

Alongside fiscal and licensing measures to stimulate upstream exploration and production, Australia also provided demand incentives to increase the share of natural gas in the energy mix. The Queensland Gas Scheme illustrates the success of such measures in driving coalbed methane production. Introduced by the Queensland government in 2005, the scheme required all electricity retailers to acquire 15% of the power they sold from natural gas-fired generation plants. Accredited power producers generated Gas Electricity Certificates (GEC) for each MWh of eligible natural gas-fired electricity they produced. These GECs are then sold to the electricity retailers, providing an alternative revenue source for power producers to offset the higher cost of natural gas-fired power generation compared to coal. The scheme ended in 2013 when the state government declared that its goals of promoting the state’s natural gas industry and reducing greenhouse natural gas emissions had been achieved. During this time, natural gas-fired power generation had gone from 5% of total power in 2005 to 20% in 2013, and the state’s unconventional natural gas production had grown from 1 billion m³ in 2004–05 to 6 billion m³ in 2010–11 (Fig. 19.3).

Fig. 19.3

Natural gas production in Queensland, Australia. Source Queensland Department of Natural Resources and Mines

Australia has three levels of government—federal, state or territory, and local—and has a concessionary fiscal regime. The federal government and state and territory governments share jurisdiction over petroleum resources, and there are no private ownership petroleum resources.

State and territory governments manage the licences for development onshore and within 3 miles of the coastline. They collect royalties of between 10 and 12.5%, based on the wellhead value of the petroleum resource. Licences in Queensland are issued and managed by the Department of Natural Resources and Mines, and the published royalty rate is 10%.

The federal government manages licences for offshore development beyond 3 miles of the coastline. It levies a Petroleum Resource Rent Tax of 40% for both onshore and offshore oil and natural gas, with state and territory royalties deductible from the amount due.¹ In addition, the federal government levies a corporate tax of 30%. It also levies a value added tax, known as a Goods and Services Tax, of 10% on most transactions, with receipts redistributed to the state and territory governments.

The three levels of government in Australia co-ordinate to develop natural gas resources and markets. The Council of Australian Governments is the main intergovernmental forum that promotes policy reforms with national relevance or those that require co-ordinated action at all levels. Members of the council are the prime minister, the premiers or chief ministers of each state or territory respectively, and the president of the Australian Local Government Association. In addition, the Standing Council on Energy Resources (SCER) was founded in 2011 and comprises federal, state and territory ministers responsible for energy and resource matters. The council’s responsibilities include oversight of the natural gas and electricity markets, energy laws and regulations, energy security and emergency management, and promoting the economic development of Australian resources.²

Companies developing new upstream infrastructure may be granted exemptions from third-party access requirements if they satisfy criteria outlined in the legislation.

Access to third-party infrastructure is established under the federal Competition and Consumer Act. The National Competition Council (NCC) is established through consensus by the SCER and is responsible for recommending regulations on third-party access to monopoly infrastructure, including natural gas transmission pipelines. Factors taken into consideration include whether access would increase competition in a market, the economics of developing competing infrastructure, and whether the infrastructure is already subject to an effective access regime.

For example, 15-year exemptions have been granted to cover the pipelines being built to transport natural gas from the three Queensland LNG projects to the liquefaction plants in Gladstone. The NCC concluded that third-party access “would not promote a material increase in competition in any likely dependant market”.³ Even though the developers can obtain a waiver, nonetheless the Australian Competition and Consumer Commission (which also has jurisdiction beyond energy) and the Australian Energy Regulator (AER) both carry out significant oversight, strictly executing energy market rules and providing protection for competition and consumers.

1.4 Case Study 3: Argentina—The Special Licensing System and Encouraging Investment

Argentina is a significant producer and consumer of natural gas. According to data from the US Energy Information Administration, the country’s technically recoverable shale natural gas reserves are second only to those in China, and its shale oil resources are the world’s fourth largest, after Russia, the United States and China. According to forecasts, Argentina’s natural gas demand will have been 44 billion m³ in 2015, accounting for 45.7% of its energy structure. Currently, the domestic shortfall is met by LNG purchased primarily from the spot market and imported through two floating regasification and storage units. Natural gas prices are regulated and subsidised below cost, but prices have begun to be deregulated—mainly through bilateral negotiations—to encourage upstream investment and to raise revenues for the government.

Argentina’s concession-based licensing system replaced a system based on risk service contracts. State-controlled Energía Argentina S.A. (ENARSA), which is 35% publicly owned, owns all unlicensed federal offshore exploration acreage more than 12 nautical miles from shore. Any activity in these blocks must be done in partnership with ENARSA. Provincial governments issue tenders for onshore projects.

All licences are subject to royalties, income tax, provincial sales tax and other signature bonuses and rentals, as well as possible export duties on oil and natural gas. The Oil and Gas Law, passed in 2014, centralises implementation of the royalty system and licensing, but leaves the administration to provincial regulators. Before this law was enacted, provincial governments had jurisdiction on oil and natural gas licensing and operations, and many provincial governments took equity interests in licences. From this it is clear that provincial-level governments can become involved in relevant licensing matters through their various oil and natural gas departments (Figs. 19.4 and 19.5).

Fig. 19.4

Argentina’s primary basins and LNG receiving stations

Fig. 19.5

Argentina’s natural gas production and consumption. Source Energy Information Administration, International Energy Statistics

Due to growing energy needs, governments have begun to focus on stimulating investment. In October 2014, the Oil and Gas Law was passed. This contained a series of measures providing incentives for investment in unconventional oil and natural gas exploration and production, including:

• distinguishing between conventional and unconventional resources, for example by providing unconventional assets with an exploitation period of 35 years compared to 25 years for conventional resources (exploration periods are 13 years);

• plans to allow higher prices for natural gas produced using unconventional means;

• creating an unconventional production licence, providing five years for a pilot project to become commercially viable, with royalties to be dropped by 25% for unconventional projects after the pilot phase is completed; and

• allowing 20% of production to be exported.

However, obstacles remain to building an unconventional natural gas industry in Argentina, including a shortage of trained labour. The opening of the Unconventional Fields Technology Center in Neuquén Province is a step forward, but more is needed to build capabilities in shale natural gas technology. In addition, current regulations do not address environmental concerns adequately, which could become problematic for unconventional developments near population centres.

1.5 Case Study 4: Mexico—Reopening the Market and Round Zero Tender

Mexico’s oil industry is one of the world’s oldest; oil was first discovered in Mexico in 1904. By 1921, Mexico’s oil production had reached 530,000 bod, accounting for 25% of the world’s oil production. Following labour disputes, international oil company assets in Mexico were nationalised in 1938, which led to the creation of the national oil company Petróleos Mexicanos (Pemex). Pemex held exclusive rights to the country’s oil and natural gas fields.

In the following decades, Pemex largely ran its own oil and natural gas operations, aided by international service companies. As a state monopoly, its budget and financial management were heavily controlled by the Ministry of Finance and Public Credit, leading in part to its gradual stagnation. Its production volume continually dropped, beginning in 2004 (Fig. 19.6). Its production volume peak was between 2004 and 2005, with approximately 2.6 million barrels/day, as well as 3 billion ft³ of natural gas. Rapid further decline is projected for the coming years.

Fig. 19.6

Oil and natural gas production in Mexico. Source Wood Mackenzie

In an attempt to halt production declines, in 2013 the political party known as PRI began implementing energy reforms after 71 years. President Enrique Peña Nieto proposed an Energy Reform Act in August 2013. The act was eventually passed in December 2013, allowing international oil companies and other investors to invest once again in Mexican oil and natural gas businesses through three possible legal arrangements: service contracts, production- or profit-sharing contracts, or licences.

To protect the national interest in Pemex, the government ran a unique tender in 2014, Bid Round Zero. Under the tender, Pemex had to submit applications for which fields and blocks it wanted to keep and relinquish the rest. The submission had to demonstrate technical, financial and operational capabilities to operate productive assets, and, for exploration acreage, Pemex had to show it had either drilled exploration wells, conducted sub-surface studies or both. The Energy Secretary and the Comisión Nacional de Hidrocarburos (National Hydrocarbons Commission) made the final decisions on the applications.

As a result of Bid Round Zero, Pemex retained about 83% of proven and probable oil and natural gas reserves (Fig. 19.7) and 21% of the prospective resources, based on commission estimates (Fig. 19.8). Pemex was also allowed to invite foreign investors to join in the exploration, development and production of assets it retained.

Fig. 19.7

Pemex reserves analysis after bid round zero

Fig. 19.8

Pemex unconfirmed resources, 2014. Information source HIS, PFC Energy

A measure like Bid Round Zero could be an attractive option for China. Such a tender would allow existing state oil companies to nominate assets they would like to retain, freeing up other assets for new entrants. The move could attract greater energy investment and accelerate the development of unconventional shale natural gas production. Increased domestic production would reduce the country’s dependence on foreign natural gas, which rose from zero in 2005 to 32% of domestic consumption in 2013.

In late 2014, the National Hydrocarbons Commission began Bid Round One, which will be a staged tender and include shallow water exploration, shallow water development, onshore projects, enhanced production for the Chicontepec field, unconventional oil and natural gas, and deepwater projects (Fig. 19.9).

Fig. 19.9

Suggested timeline for a new round of tenders

Without question, the most important factor in these events has been the speed and determination of the Mexican government in taking clear and transparent steps toward energy reform, including the 20%+ of discovered oil/natural gas fields provided to international oil companies following the final Round Zero Tender. It is worth considering which of these measures could suit China’s situation, especially in the accelerated exploration and development of unconventional natural gas and shale natural gas, as well as in attracting suitable international oil companies and private investors to accelerate the trials in this process. It is also worth considering whether Mexico will continue on its path of open policies after the six-year term of President Enrique Peña Nieto.

2 The Midstream Segment: Building Infrastructure and Managing Access

Midstream assets—transmission pipelines, LNG regasification terminals and storage facilities, and distribution networks—are natural monopolies. They have high fixed capital costs of investment but low, and decreasing, marginal costs of operation. As a result, it is economically more efficient if fewer of these assets are built and fully utilised, rather than assets being duplicated and dividing volumes among them through competition.

Natural gas pipelines—both transmission and distribution—have more significant natural monopoly characteristics than LNG terminals or storage facilities. The economies of scale for LNG terminals and storage facilities are not as great as those for pipelines. Hence, for a given market size, the optimal number of facilities required will be greater compared to the number of pipelines required to serve a market of similar size. Moreover, LNG terminals and storage facilities can compete with other similar assets once they are connected through a pipeline network.

In the United States, LNG receiving stations are viewed as upstream assets, because they are seen as extensions of upstream wells. However, in Europe, LNG receiving stations are midstream assets. The difference in perception depends on the degree of competition in the market. In the United States, LNG receiving stations compete with domestic products, and thus they seen as comparable to domestic wells. In Europe, the majority of competition comes from imported natural gas, and thus LNG receiving stations are viewed as part of the transmission network. If LNG receiving stations are seen as upstream assets, then regulatory measures will be different, and there will be fewer concerns about the monopolistic nature of the receiving stations. In China, there is uncertainty regarding the character of LNG receiving stations, because development is lacking in competitive natural gas markets.

The natural monopoly characteristics of midstream infrastructure mean that government oversight and regulation is required to prevent access being restricted and monopoly rents being charged. A monopoly owner of midstream infrastructure has an incentive to charge very high prices to maximise its profits, reducing pipeline utilisation in the process. It may therefore be necessary to unbundle midstream assets from vertically unified companies. Examples of the options for accomplishing this can be found by looking at the international experiences seen in the case studies.

Even if midstream assets do not belong to a given vertically unified company, if no oversight is implemented, there is still the possibility of problems arising. On the one hand, independent owners need upstream and midstream participants to use their midstream assets. On the other hand, independent owners also have an incentive to collect the highest price possible to maximise their profits. Regulation is the solution, to ensure that usage rights to midstream assets are available to all parties (in other words, third-party access).

Regulatory institutions will often need to unbundle and re-establish third-party access. In practice, even if there are rules for third-party access, there are still many means to exclude third parties, such as lack of transparency over pricing. Using regulatory institutions to implement strict regulation of third-party access can prevent such anti-competitive behaviour. At the same time, many regulatory institutions believe that through unbundling such motivations can be eliminated, which is an effective supplement to third-party access rules.

In a growing market in need of investment, such as China, regulatory frameworks should ensure that investments can receive sufficient profits, encouraging capital investment. Regulation of the collection of usage right fees can help asset owners to recover their capital. Regulation of fee collection can employ either a “regulated return” system or a “regulated tariff” system. These two methods are very similar, but have differing risk allocations in terms of midstream asset users and owners. Under a “regulated return” oversight approach, the owner of the midstream is authorised to receive a high enough rate of return to act as a motivation for future pipeline construction. Under the “regulated tariff” regime, such tariffs should likewise be sufficiently high to provide an incentive for future asset investments.

The challenge therefore faced by government departments is to achieve a balance between making usage rights available and encouraging investment in midstream assets. This balance can be achieved through a precisely designed regulatory framework, which will need to include the following key factors: rules for liability and standards, a consensual pricing framework for third-party access and a mechanism to assure returns for investors. In some frameworks, when regulatory institutions solve downstream market structure or legacy issues, these mechanisms can be used to balance out two different goals.

When a country’s regulatory mechanisms reflect various domestic factors, such evolutions and influences can be referenced by China. We examine three case studies below: the third-party access arrangements of the United Kingdom in the North Sea; Singapore and Japan’s LNG experience; and Shell’s IPO of its Shell Midstream Partners enterprise in the United States. These case studies yield five primary lessons:

• if it is to promote usage rights and investment, regulation must strike a balance between the economic interests of midstream asset users and owners;

• regulatory frameworks must be stable, reliable and clear, thereby facilitating general risk minimisation and stimulation of investment;

• mechanisms based on rules can provide a means of resolution for this;

• at the same time as generating revenue, regulations such as mandatory third-party access requirements can ensure that midstream assets are used efficiently;

• even while balancing usage rights and investment, regulatory institutions can also consider market structure in addition to the value chain. Current regulatory policy will influence future economic opportunities.

2.1 Balancing Third-Party Access and Investment Incentives

Third-party access needs to be balanced against incentives for further investment in midstream infrastructure, especially in growing markets such as China. While allowing for third-party access, the regulatory framework also needs to provide adequate incentives—and returns—on future investment in the midstream. For example, access charges can be regulated to enable asset owners to recover fixed costs.

Regulated charging regimes can be of two types: either regulating the rate of return achieved by midstream infrastructure owners or regulating the tariff charged for access to midstream infrastructure. Under a regulated return regime, the owner is granted a rate of return on its midstream asset value that is high enough to provide incentives for future investment in maintaining and extending the infrastructure network. Under a regulated tariff regime, the tariff is set at a level that provides incentives for future asset investment. Both approaches are similar, but vary in the distribution of risk among the users and the owners of midstream assets.

While an individual country’s regulatory regime reflects a variety of domestic factors, a review of the evolution and impact of these regimes can offer insights for China in achieving a balance between returns to investment and access to midstream assets. The oversight of natural gas infrastructure reflects a country’s experience in the realm of natural gas market liberalisation, as well as its systemisation and government and policy priorities. There is no single oversight system that can be transplanted from one jurisdiction to another. In fact, if residual issues, systems and political factors are not taken into consideration, replicating another country’s oversight structure will result in failure (United Nations Economic Commission for Europe 2012). However, it is possible to learn by comparing existing oversight frameworks that the key is to balance the attainment of public and private goals.

Regulatory institutions often need to unbundle third-party access. In reality, even if there are third-party access rules, there are still many means by which to exclude third parties—for example, a lack of transparency over pricing of capacity. Regulatory institutions can prevent such anti-competitive behaviour by rigorous oversight of third-party access rules, but many regulatory institutions believe that unbundling is an effective solution that eliminates the incentive for anti-competitive behaviour.

In growing markets in need of investment, such as China, regulatory frameworks should also allow for sufficient profits, thereby providing momentum for future midstream investment. Using a “regulated return” system, owners of midstream assets are allowed sufficiently high rates of return that there is an incentive for future piping construction. Under a regime of “regulated tariffs”, such tariffs should likewise be sufficiently high to provide an incentive for future asset investments.

The challenge for government departments is therefore to achieve a balance between midstream asset usage rights and investment, as shown in Fig. 19.10. Within a carefully designed regulatory framework, it is possible to achieve this goal. Many countries have achieved such success, and the regulatory mechanisms that may be of interest to China as precedents include:

Fig. 19.10

The balance of factors needed in the regulatory framework

• Rules: Regulators establish and enforce rules on liability and standards.

• Prices: Regulators provide a framework for investors and users to agree on prices in both third-party-access and regulated-return regimes.

• Mechanisms to reduce risk: Regulators minimise risk for investors and users.

2.2 International Experience of Managing Midstream Asset Access

The case studies provide five overarching insights:

• Regulation balances the economic interests of users and owners of midstream assets to facilitate access and investment. Economic opportunities drive demand for access to and investment in infrastructure. However, demand by itself is an insufficient condition for access and investment, as users and owners often cannot agree terms, often because of the asset owner’s natural monopoly power. Thus, players require a strong regulatory framework that grants access to the midstream and provides incentives for investment. For example, experience in Singapore and the United Kingdom in establishing third-party access shows that strong regulation can assist users of assets in their negotiations with midstream operators.

  The experience of the United States and Japan has shown that in terms of risk/reward for investors, oversight is beneficial in creating investment opportunities and encouraging more funds to be channelled to the construction of midstream infrastructure.

• Regulation can ensure that the midstream asset is used efficiently. Regulation, such as mandatory third-party access requirements, can ensure that players upstream and downstream can access the pipeline and that the fees charged and returns made by the owner of the midstream asset are fair. Regulation can take various forms, such as negotiated or regulated access, but all forms of regulation are aimed at increasing access while ensuring reasonable returns to the asset owner and supporting sufficient investment to maintain energy security.

  Controls implemented according to specific circumstances can utilise agreement negotiations or controls to achieve third-party access. The British North Sea owner and user negotiations successfully implemented third-party access, with new companies able to develop small-scale gas fields without needing to invest in the construction of new piping. Midstream asset owners can obtain revenue from amortised assets, and the government can obtain relevant oil and natural gas production taxes related to asset development.

  However, in the rapidly growing market of China, the experience from the North Sea is of limited use. There is very little need for new investment in piping in the North Sea, and this made it easier for midstream facility owners and users come to an agreement. This is not the case in China, and the facility owners tend to look to use their position to collect monopolistic lease amounts. As a result, China’s rapidly growing emerging market should give greater consideration to using mandatory third-party access systems to stimulate investment in midstream facilities by promoting recovery of capital and reasonable risk returns.

• The regulatory framework should be stable, credible and clear to minimise risk and encourage investment. The success of the master limited partnership in the United States has been in large part the result of government providing a statutory basis for partnership treatment: federal rules on qualifying income and assets gave all parties the necessary certainty to proceed. In the United Kingdom, the combination of a statutory, rules-based framework and the threat of arbitration ensures that when negotiating third-party access, parties have similar expectations and incentives, with it being very rare that events end in disagreement. The regulatory layers collectively help to reduce uncertainty for participants (see Fig. 19.11). In contrast, the absence of enforcement has meant that third-party access rules are not credible, and midstream infrastructure is for the most part not open to third parties.

  Fig. 19.11

  

  The three layers of agreements supporting North Sea usage rights

• Regulators should take into account market structures along the value chain when balancing access and investment. The nature of competition along the entire value chain influences regulatory choices. For example, Japan has a fragmented market where all natural gas is imported by LNG shipments and there is limited interconnection between regional markets. This means that competition is hard to achieve and brings few benefits, and as a result third-party access is limited.

  In the United Kingdom, the natural gas market was originally created upstream, with competitive downstream markets only starting in the 1980s, and thus its regulatory framework design focus is on the promotion of midstream usage rights.

  In Singapore, private funding for an open-access LNG terminal fell through as a result of sufficient pipeline gas supply to meet demand and liberalised downstream markets, which favoured cheaper pipeline gas over more expensive LNG imports. The government stepped into develop the LNG terminal as a means of diversifying sources of supply and enhancing energy security. Ownership is deliberately separated from operation of the multi-user LNG terminal, and the government has developed a framework to open the terminal to third-party access. At the same time, the government has also sought to secure downstream demand for LNG by restricting new pipeline imports (Table 19.1).

  Table 19.1 The influence of the nature of competition on midstream infrastructure regulation choices

• The regulatory framework a country pursues affects the set of available policy choices. The regulatory legacy can affect the level of utilisation of infrastructure, the level of activity by new entrants and the form of private contracts. The private sector’s capacity to identify and develop economic opportunities is a function of how a country’s regulatory regime and its infrastructure have evolved.

  In the first years of development of North Sea gas, large companies obtained permits from the government and independently invested to develop the oil and gas fields. In the past 12 years, because of drops in yields, these oil and gas fields have seen reduced rates of return, and there is less interest from large companies. However, the amortised assets that they possess can be transferred to smaller enterprises to develop small-scale oil fields that pay the larger companies for usage of their assets. Therefore, from the 1960s to the 1990s, the United Kingdom’s regulation system has increased the opportunities today.

  In Japan, even though on the surface LNG receiving stations seem to be accessible, regulators have chosen to use negotiated approach a third-party access, rather than making it mandatory. This approach gives facility owners a powerful negotiating position. Combined with a lack of competition upstream and downstream, there is a push for suppliers and upstream facility owners to sign long-term supply agreements. Without reliable access systems, new entrants to the market generally build new LNG receiving stations in order to take advantage of downstream business opportunities.

2.3 Case Study 1: The UK North Sea—The Framework for Negotiated Third-Party Access

The United Kingdom’s North Sea experience illustrates one approach to arranging access to midstream infrastructure. In particular, it focuses on the government’s efforts to develop a regulatory framework that grants new entrants access to the pipelines built by earlier North Sea field developers.

Several key lessons emerge from this experience:

• A liberalised market with clear rules encourages new investment. Output from the North Sea was declining and costs were rising. However, new firms that specialise in declining fields were able to enter the liberalised market, which has provided asset owners with new business and the government with greater tax revenue.

• Users of assets have been favoured over owners to some extent. As midstream assets were already in place as a legacy of past exploration of the North Sea, and faced declining utilisation, new users seeking access had greater bargaining power as asset owners had few alternative customers. In addition, by encouraging access, the government could benefit from greater hydrocarbon production tax revenues associated with resource development.

• Where interests between midstream asset owners and users are broadly aligned, a voluntary agreement on access provision between the parties is feasible. The United Kingdom had a layered regulatory framework to access. Parties were encouraged to reach voluntary agreements, with clear rules for dispute resolution and, ultimately, a legal framework if voluntary agreements could not be reached. This system has worked well, with many parties reaching voluntary agreements, because interests are broadly aligned and the rules are clear and credible.

China faces a different gas market context than seen in the North Sea example. China’s natural gas market is growing rapidly, whereas output from the North Sea was declining. As a result, the economic pressures felt by UK asset owners that supported negotiated third-party access—specifically, existing assets with declining utilisation—would not be as prevalent in China, where limited midstream capacity gives asset owners more bargaining power. Nevertheless, the North Sea experience demonstrates how a credible regulatory framework can help achieve agreement and avoid disputes.

• 1. Background

The regulatory regime for natural gas exploration in the United Kingdom from the mid-1960s through to the 1980s was characterised by liberalisation and increasingly competitive markets. When the first licences were offered by government, major companies chose to develop oil and natural gas fields as stand-alone installations. Upstream pipelines and offshore processing facilities were usually built by field owners to process and transport output from specific oil and natural gas fields. However, since then, recovery rates—and returns—from these fields have fallen, and larger enterprises have been less interested in developing the remaining resources.

As spare capacity became available in pipelines and terminals, opportunities arose. The existence of their depreciated pipeline assets has allowed smaller players to enter the industry and exploit smaller fields, paying larger companies to use their assets to transport oil and natural gas to the mainland. A liberalised downstream market meant there was a ready market for small-field developers if they could access midstream assets. There were benefits to infrastructure owners, too, in terms of additional revenue from granting third-party access to new users and from deferring the costs of decommissioning these assets. The government saw opportunities in terms of additional job creation, maximising recovery of North Sea oil and gas resources, and continued production tax revenues.

The 1996 Network Code established the rules and procedures for third-party access to pipelines and introduced a regime for daily balancing, while the Petroleum Act of 1998 set out the rules around upstream exploration and production. By the early 2000s, liberalisation of the sector was complete, with the creation of the National Grid as a fully unbundled, independent transmission system owner and operator of the United Kingdom’s natural gas and electricity markets in 2002.

However, the legal framework by itself was insufficient and left room for commercial disputes between owners and users of the infrastructure. Through the 1990s, there were concerns that the tariffs to access infrastructure were too high compared to costs and risks of developing small fields. This led to a new process for negotiating access. The legislative and regulatory changes provided a statutory basis for a rules-based framework, including a process for arbitration of disputes, which helped co-ordinate activity and create common expectations.

• 2. The framework for negotiated third-party access

Working with government, the natural gas industry sought to develop voluntary frameworks for third-party access. The first industry offshore Code of Practice was introduced in 1996. It sought to establish a timely process for seeking, offering and negotiating third-party access to natural gas infrastructure in the North Sea. It also sought to ensure that access was easy and fair, with terms offered on a negotiated, non-discriminatory basis.

In 2004, market participants agreed to a strengthened code, the Infrastructure Code of Practice. The code outlined best practice and expected behaviour in conducting negotiations for access to infrastructure. According to the industry group Oil & Gas UK, the code was intended “to facilitate the utilisation of infrastructure for the development of remaining UKCS [United Kingdom continental shelf] reserves through timely agreements for access on fair and reasonable terms, where risks taken are reflected by rewards”. Its main tenets are:

• Parties uphold infrastructure safety and integrity and protect the environment.

• Parties follow the Commercial Code of Practice.

• Parties provide meaningful information to each other before and during negotiations.

• Parties support negotiated access in a timely manner.

• Parties undertake to settle disputes if needed through the Automatic Referral Notice process which involves the UK minister responsible for energy.

• Parties resolve conflicts of interest.

• Infrastructure owners provide transparent and non-discriminatory access.

• Infrastructure owners provide tariffs and terms for unbundled services, where requested and practicable.

• Parties seek to agree on fair and reasonable tariffs and terms, where risks taken are reflected by rewards.

• Parties publish key commercial provisions from the agreements.

Companies seeking access to infrastructure falling within the scope of the third-party access provisions of the Energy Act 2011 must apply first to the owners. However, the act also allows the government minister responsible to take the initiative and set the terms in cases where there is no realistic prospect of reaching an agreement. If the parties are unable to agree to satisfactory terms and conditions, the prospective user may apply to the minister to resolve the dispute. The minister can require access to pipelines, associated offshore production facilities, and onshore natural gas processing facilities, and dictate the appropriate terms. In most cases, these terms will be in line with those offered by infrastructure owners in a competitive environment. In such cases, the legislation stipulates that appropriate notices be issues to the parties to implement the terms. While a dispute resolution procedure exists and the minister can intervene to adjudicate, the third-party access framework is essentially self-enforcing and has rarely resulted in dispute.

A crucial factor in the success of the framework is that it reduces commercial risk by giving stakeholders guidance on tariffs and a variety of other terms. Terms of agreements tend to be quite specific with regard to liability, transparency and technical standards. Terms covered often include:

• the basis for modification of infrastructure, if necessary;

• the duration of service;

• identifying which party has ownership and risk exposure to the natural gas while it is within the infrastructure owner’s facility;

• capacity terms and the ability of the owner to change them;

• charges for providing the service;

• rights of both parties to terminate the agreement; and

• liabilities covering damage and loss relating to people, property and pollution.

Within the regulatory framework, both owner and user considerations are important in determining terms of access. Competition and other market forces, the user’s ability to pay and contract flexibility are all key considerations to be taken into account when agreeing the terms of access (Fig. 19.12).

Fig. 19.12

Analysis of regulatory frameworks

Owners and users have flexibility when negotiating access. For example, when agreeing to provide access, the infrastructure owner reserves capacity in its system for the shipper. The shipper gains certainty that the required capacity will be available, subject to normal operational availability, and the infrastructure owner will not market reserved capacity to others. In turn, the infrastructure owner will want to mitigate the risk of the user booking more capacity than required, such as through send-or-pay provisions, which guarantee minimum payment regardless of the extent to which the reserved capacity is used. In declining fields, such as in the North Sea, terms of access are often based on operating costs, plus a risk premium. This contrasts with the approach for newer fields, where the terms of access also tend to include operating costs, as well as capital cost recovery.

2.4 Case Study 2: Japan and Singapore LNG—National Power and the Influence of Oligopoly

Singapore and Japan have had entirely opposite experiences in the development and control of midstream infrastructure, especially in terms of LNG regasification receiving stations (Table 19.2). However, the experiences of the two countries highlight that for a balance to be struck between access to and investment in midstream infrastructure, both a streamlined industry chain and consideration of the influence of the market structure are necessary.

Table 19.2 Differing LNG management systems resulting from different market traits in Singapore and Japan

• 1. Singapore LNG: national power involved in influencing construction of infrastructure

Singapore has no domestic natural gas resources and is dependent on imports. Natural gas consumption grew rapidly in the 2000s, from 1.3 billion m³ in 2000 to 8.7 billion m³ in 2010.

Into the early 2000s, the island-state’s natural gas market was characterised by government ownership along the value chain through Singapore Power Group and SembCorp, limited or no unbundling in commodity and transportation activities, significant price controls on electricity, and generally homogeneous supply through pipelines deliveries from Malaysia and Indonesia. In 2004, the country began progressive liberalisation, resulting in a competitive midstream and downstream natural gas market, including regulated open-access networks, a significant number of primarily private market participants, unbundled commodity and transportation activities, and oversight entrusted to an independent energy regulator, the Energy Market Authority (Fig. 19.13). The government’s role is limited to ensuring fair access to infrastructure.

Fig. 19.13

Market diversification in Singapore, 2004 versus 2014

In 2006, the government decided to develop an LNG regasification terminal to enhance energy security by diversifying sources of supply away from existing pipeline gas. However, meeting the policy objective on energy security was not consistent with Singapore’s liberalised and competitive wholesale and retail markets. Singapore had a well-functioning domestic natural gas market, with sufficient supply from pipelines, and there was little market demand for an LNG regasification terminal, despite the energy security benefits it offered.

The country originally granted a licence to a private consortium of PowerGas and GDF Suez to make the necessary investment, but this arrangement collapsed in 2009 because of a funding shortfall. While the problem was linked to the 2008 global financial crisis, it also reflected the competitive nature of the downstream market, which dampened the commitment among potential customers of the LNG facility. The benefits of diversifying supply were outweighed by the risks of being a first mover to a more expensive and untested source, reducing the incentive for energy companies and end users to switch supply sources.

In 2009, the government announced it would take over the development and ownership of the LNG terminal. It established the Singapore LNG Corp. to develop and operate the terminal. The facility, which opened in 2013, was regulated by the Energy Market Authority. It was open access, with third-party access arrangements underpinned by a rules-based regulatory framework, including a dispute-resolution process, and public ownership of the infrastructure was deliberately kept separate from commercial operation.

The regulatory framework established by the government and the Energy Market Authority was designed to guarantee fair and transparent access to midstream infrastructure while reducing investor risk. It comprised three key elements:

• Aggregator: A private company, BG, was appointed natural gas aggregator to secure supplies. By pooling demand from large users, Singapore maximised its negotiating power on global markets and secured competitively priced supply.

• Framework: Terminal access rules agreed between BG and Singapore LNG provided a commercial framework for other third parties that sought access and enabled a greater degree of forward planning by energy companies.

• Support: The government offered a purchase agreement with any power-generation company that committed to LNG supply and a tariff structure that allowed companies to pass through the cost of LNG.

The terminal had the capacity to handle three times as much natural gas as the country consumed. While it initially opened with a 3 million tonnes per year capacity, the opening of its third tank in 2014 doubled capacity to 6 million tonnes. A fourth tank is expected to open by 2017, which would bring total capacity to 9 million tonnes. The terminal could eventually accommodate seven tanks, for a total capacity of 15 million tonnes.

Because capacity was planned to exceed domestic requirements, the government has also sought to secure downstream demand for LNG. To do this, the government introduced controls on new pipeline imports in 2006. These controls allow existing contracts to be honoured, but new contracts were subject to approval from the Energy Market Authority. The decision moved Singapore away from its free market approach and introduced a measure of uncertainty about the evolution of Singapore’s natural gas markets. While the moratorium on new pipeline imports is likely to be lifted, it remains unclear whether the government will continue to limit direct competition between pipeline natural gas and LNG.

Key lessons from Singapore’s experience of developing and regulating its midstream LNG infrastructure include:

• Markets can face challenges when investing to achieve policy objectives. Singapore had a well-functioning domestic gas market, with sufficient supply from pipelines. Given this, there was little market demand for an LNG terminal, despite the energy security benefits it offered.

• Regulation is needed to deliver policy objectives. As the market would not provide the investment, the government had to step in and invest in the LNG terminal itself. At the same time, the government also sought to secure downstream demand for LNG by restricting new pipeline imports. However, in recognition of the efficiency of market forces, the government operated the terminal as a multi-user access terminal to enable competition downstream between importers.

• Regulators have an important role in setting up the commercial framework for access. The terms of access were clear and credible, allowing private companies to make long-term plans despite the uncertainty that comes from an open access terminal, such as available docking times and capacity.

• 2. Japanese LNG: oligopoly restricting third-party access

Japan imports most of its natural gas, and its imports are exclusively LNG. The country has 30 operating LNG terminals, with a total capacity of 172 million tonnes a year, a level well above domestic demand. However, Japan remains constrained by how much LNG it can receive, based on berthing, ship size and other infrastructure limitations. Five additional terminals are currently under construction and expected to become operational by 2016, adding capacity of at least 7 million tonnes.

The majority of LNG terminals are near main population centres and manufacturing hubs around Tokyo, Osaka and Nagoya (Fig. 19.14). They are owned by local power companies, either alone or in partnership with natural gas companies, and the same companies own much of Japan’s LNG tanker fleet.

Fig. 19.14

Japanese LNG facilities and their proximity to large cities and manufacturing hubs. Note This document and any map included here are without prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries and to the name of any territory, city or area. Source IEA

Japan has unique energy fundamentals that make midstream assets particularly important. Japan has no domestic production of natural gas and few other domestic sources of energy.

The country also does not have a well-developed or integrated domestic long-distance natural gas transportation network, partly because its mountainous geography limits the development of a network. Instead, LNG regasification terminals have proliferated along the coastline and take the vital role of a transmission network. However, as a result of these conditions, downstream markets are fragmented and dominated by regional monopolies. Domestic natural gas transport and distribution infrastructure, including LNG terminals, is owned and operated by vertically integrated private natural gas and power companies. The natural gas market remains largely uncompetitive, with four companies supplying more than 70% of natural gas and almost all LNG terminals owned by a small number of companies and no actual third-party access.

Open access in LNG infrastructure was discussed in the US-Japan Third Joint Status Report under the Enhanced Initiative in 1999, an economic co-operation agreement between the two countries. In response, the Japanese government amended the Gas Utility Act in 2003 and introduced an open-access scheme that obliged natural gas companies to define preconditions for negotiated access. Further transparency requirements related to the capacity information for LNG storage and facilities were also introduced. The changes were intended to act as a guide for infrastructure users, but did not go far enough: third-party access to terminals was characterised as “desirable” and LNG terminals were not classified as “essential facilities”. As a result, while a mechanism for access exists, the regulatory framework does not promote ease of access. Users face a lengthy application process, the timing, flexibility and tariffs are unclear, and there is no arbitration or dispute resolution process.

Since the changes were introduced, no company has effectively negotiated third-party access. Incumbents have successfully argued against third-party access, claiming that regulated third-party access, such as in Singapore, may create disincentives for investment in natural gas infrastructure and hamper energy security. As a result, regulators have tended to promote investment over access. Lack of downstream competition has also led to LNG shippers and LNG terminal owners signing long-term supply contracts, which make it more difficult for newcomers to enter the market.

Natural gas market liberalisation in Japan has been ineffective. The country has rules in place for market liberalisation, such as retail price liberalisation for the non-household sector and third-party access rules. However, natural gas market reform has been piecemeal. Third-party access rules have not been complemented by mandatory unbundling or by other measures to increase competition in downstream retail markets. If the market were to be liberalised, reform is needed on all fronts: while effective third-party access facilitates competition, the lack of downstream competition has prevented third-party access from being effective.

Energy security remains the primary policy priority. Japan’s regulatory regime cannot focus on minimising costs as vigorously as that of countries with more favourable fundamentals, such as China, which has greater energy security and can build a national transmission network.

Key lessons from Japan’s experience of developing and regulating its midstream LNG infrastructure include:

• Japan has unique energy fundamentals that make midstream assets very important. The country had no domestic production of gas and few other domestic sources of energy, and its mountainous geography limited the development of a national transmission network. As a result, energy security was a high priority, and LNG terminals played the role of a transmission network by providing access at points along the coastline.

• Japan has experienced large investments in midstream assets. Japan has invested in a large number of LNG terminals, which were warranted from an energy security and geography perspective. Incumbents have successfully argued against third-party access, claiming that regulated third-party access, such as in Singapore, may create disincentives for investment in natural gas infrastructure and hamper energy security. As a result, regulators have tended to promote investment over access.

• Gas market liberalisation in Japan has been ineffective. Japan had rules in place for market liberalisation, such as retail price liberalisation for the non-household sector and third-party access rules. However, in practice the market remained uncompetitive, with four companies supplying more than 70% of natural gas and almost all LNG terminals owned by a small number of companies with no meaningful third-party access.

• The failure of liberalisation demonstrates the importance of regulating across the value chain. Gas market reform in Japan has been piecemeal. Third-party access rules have not been complemented by mandatory unbundling or by other measures to increase competition in downstream retail markets. If the market were to be liberalised, reform is needed on all fronts: while effective third-party access facilitates competition, the lack of downstream competition has prevented third-party access from being effective.

2.5 Case Study 3: The United States—Master Limited Partnerships

In the United States, a unique corporate structure, master limited partnerships, enables ownership of midstream assets to be reallocated to owners with appropriate risk profiles. The structure facilitates the transfer of midstream assets from organisations focused on high-risk, high-return activities, such as oil and gas exploration and development to organisations seeking low-risk, low-return assets, such as pension funds. While the case study focuses on oil pipelines, it is applicable to midstream infrastructure more generally.

Key lessons from the US experience with master limited partnerships include:

• Midstream assets are low-risk, low-return assets and can attract significant investment. Once constructed, midstream assets such as pipelines have a relatively simple business model, especially in markets with high demand and regulated charges, such as the United States. Such assets were attractive to investors comfortable with low-risk holdings and a regular return, such as pension funds.

• Greater capital liquidity enables better allocation of capital. Many midstream assets were constructed by companies with a greater appetite for risk and higher return expectations, such as domestic and international oil companies with upstream assets, as a way of transporting wellhead natural gas to consumers. However, these companies specialised in higher-risk, higher-return investments. Instruments such as master limited partnerships enabled these companies to sell midstream assets to investors with more appropriate risk profiles and recycle the proceeds into new investment more consistent with their own risk-reward profile.

• Tax efficiency is important in attracting investor interest. A master limited partnership is a particular form of business entity that is not liable for US federal income tax. Allowing midstream assets to be structured into a master limited partnership reduced tax liability and improved the returns, therefore increasing investor interest.

• Regulation gives clarity and certainty, further enhancing capital liquidity. Beyond the corporate structure, master limited partnerships in the United States have benefited from a clear, credible and stable regulatory regime, which has created confidence among investors less familiar with the energy industry. Regulated access charges, a history of long-term contracts, and a stable regulatory and tax regime helped lower the risk of an investment and attract new capital.

• 1. Background

The United States is the world’s largest oil consumer. The level of domestic crude oil production has increased over the past few years, reversing a decline that began in 1986. According to the IEA, crude oil production increased from 5 million barrels a day in 2008 to just less than 5.7 million barrels a day in 2011 and 6.5 million barrels a day in 2012. This increase in oil production was largely brought about by new seismic and horizontal drilling technology and hydraulic fracturing, bringing domestic resources that were previously considered non-viable into production.

Pipelines are the common transport mode for shipping crude oil and refined products. In total, the country has more than 275,000 km of crude-gathering and distribution pipelines, operated by 2338 companies. The top 10 operators alone run almost 90,000 km of pipeline. In 2011, this network delivered 514.3 million barrels a day of crude oil between regions. The highest concentration of pipelines is in the Gulf Coast, which is also home to almost half the country’s refining capacity.

Because of the capital-intensive nature of pipeline operations, many companies have sought to structure these units as master limited partnerships, publicly traded businesses that are taxed as partnerships. Unlike a corporation, a partnership in the United States is classified as a pass-through entity and is not liable for federal income taxes. Instead, partners pay tax based on their allocated share of the partnership. The structure offers two significant advantages. First, tax is levied only at a single level of federal income tax, which is applied individually on the total income of each member of the partnership. The master limited partnerships do not pay corporation tax. The other advantage is that favourable tax treatment allows a master limited partnership to access lower-cost capital than if it were taxed as a corporation.

These advantages make the master limited partnership approach an especially attractive option for capital-intensive pipeline infrastructure transmission enterprises.

• 2. Benefits to infrastructure owners

One example of the structure was Shell Midstream Partners, a master limited partnership that held onshore and offshore oil infrastructure. Three of the four pipelines in its portfolio served the Gulf Coast, while the fourth reached into the Northeast (Fig. 19.15).

Fig. 19.15

Shell midstream partners pipelines

For the infrastructure owner, a particular advantage of this corporate structure is that the business retains control of the pipelines. Unlike shareholders in a publicly traded company, unitholders—investors holding shares of master limited partnerships—are not entitled to elect the general partner or any directors. Instead, they benefit from a stream of income in accordance with their ownership interest, while the partnership itself is managed by a board of directors and executive officers appointed by a general partner, in this case Shell Pipeline Company LP, an affiliate of Shell. The distribution of ownership interests varied across the pipelines in the portfolio (Table 19.3).

Table 19.3 Shell Midstream Partners ownership rights allocation

Launching an initial public offering for Shell Midstream Partners allowed Shell to release capital for investment elsewhere in its value chain and optimise its risk profile. It also allowed Shell to divest itself of low-return, non-core assets and to improve its focus on other activities. At the same time, investors in Midstream Partners, such as pension funds, were attracted by its lower risk-return profile.

• 3. Importance of the regulatory framework

The regulatory framework provided certainty for investment by detailing eligible assets and activities. Master limited partnerships were only possible as a result of the regulatory authorities providing rules for partnership treatment: federal rules on qualifying income and assets gave Shell the necessary certainty to proceed. It also enabled Shell to offer stable and predictable cash flows to investors. Rules on access meant that Midstream Partners’ assets generated stable revenue under FERC-based tariffs and long-term transportation agreements. In addition, ship-or-pay contracts mitigated volatility in cash flows by limiting exposure to changing market dynamics that could reduce production and affect shipper demand. Finally, life-of-lease agreements, some of which have a guaranteed return, reduced cash flow exposure to volume reductions.

3 Unbundling Midstream Infrastructure

Midstream infrastructure unbundling is a critical step in natural gas market liberalisation progress and in the promotion of natural gas market competition. This section analyses the effects of unbundling with the background of natural gas market liberalisation as well as related goals of unbundling. In addition, a comparison of five partition models is carried out using case studies from the United Kingdom, the European Union and Japan. These case studies offer experience and a reference point to China in its future unbundling work.

Natural gas markets have historically been dominated by large vertically integrated companies operating across the various segments of the value chain. Vertically integrated pipeline owners face particularly strong incentives to engage in anti-competitive behaviour, charging excessive rates to third-party natural gas shippers for access to midstream infrastructure to protect profits in their own production or retail businesses.

Unbundling seeks to separate the incentives facing midstream operations from those of upstream and downstream operations and to reduce the opportunity and incentives for anti-competitive behaviour. Without this, owners of midstream assets will retain an incentive to operate in a way that favours their upstream or downstream businesses. Unbundling focuses on the midstream segment because of its natural monopolies and the potential for misusing market power (Fig. 19.16).

Fig. 19.16

Unbundling is the separation of midstream business from that of upstream and downstream business

Full ownership unbundling is the most complete form of unbundling, although some models of unbundling seek to change these incentives without separation of ownership. For example, if a single vertically integrated firm participates in the upstream segment, transportation and retail sales, but regulation effectively prevents it from operating its midstream assets to the advantage its upstream or downstream businesses, vertical integration does not threaten efficient market operations.

Unbundling is a key step in natural gas market liberalisation, as part of a broader effort to create open access to midstream infrastructure, particularly to pipelines which have stronger characteristics of natural monopolies. Unbundling is required in addition to third-party-access regimes. Third-party access requirements address the incentive of a natural monopoly owner to charge very high prices to maximise its profits, reducing pipeline utilisation in the process. Unbundling requirements, on the other hand, address the incentive for vertically integrated owners to make monopoly profits by favouring their vertically integrated partners and excluding third parties.

Vertically integrated companies can misuse their market power even if third-party access to midstream assets is allowed, for example through a lack of transparency over available capacity and prices or through onerous contracting or technical studies requirements for third parties. Such anti-competitive behaviour can be remedied by strict policing of third-party access rules, but removing the incentive for this behaviour through unbundling has been seen by many regulators as a part of the solution. Unbundling is not itself the goal, but rather a means to ensure that third-party access is effective. The success of an unbundling regime should be measured by the ultimate effectiveness of an open access reform package in supporting an efficient and competitive gas market.

3.1 Models of Unbundling

Five unbundling models are defined and examined using case studies from the United Kingdom, the European Union and Japan. They are:

• Service unbundling: Businesses must offer use of their midstream assets as a distinct service separate from the wholesale supply of natural gas.

• Account unbundling: Midstream businesses must maintain separate accounts from upstream and downstream businesses to prevent cross-subsidisation and distorting behaviour.

• Legal unbundling: Midstream assets are placed into a separate legal entity, such as a wholly-owned subsidiary, to reinforce the operational separation of these assets from other assets within a vertically integrated entity.

• Structural unbundling: Strict regulatory requirements are placed on how a midstream business is operated to ensure that it supports the efficient operation of the natural gas market, rather than to the benefit of related upstream or downstream interests.

• Ownership unbundling: The legal entity that owns midstream assets does not have common ownership with upstream or downstream interests, fully separating their economic incentives.

Each of these models builds sequentially on each other, alongside an overarching process known as functional unbundling, which can reinforce each of these models. Functional unbundling restrictions can vary from being fairly mild to quite onerous. They could include, for instance, requiring separate management, locations, support units and logos, prohibiting the sharing of information, and imposing additional compliance and reporting requirements. Functional unbundling is a critical element of any unbundling process. To illustrate, a legally unbundled midstream business that shared management or offices with a related upstream or downstream business could be less effective than, say, a midstream business that legally remained part of a vertically integrated entity, but had more rigorous separation of staff and management.

Each of the five models of unbundling serves different purposes and follows sequential changes in moving from service unbundling to ownership unbundling (Table 19.4).

Table 19.4 Operational changes resulting from five types of unbundling

3.2 Key Insights from the Case Studies

Our review of international experience in unbundling midstream assets from upstream and downstream businesses produced three general insights that might be valuable to China’s policy discussions.

• Complete ownership unbundling is not necessary under a strong regulator. The case studies indicated that there are viable models that don’t require full ownership unbundling. In particular, structural unbundling under a strong regulator could capture many of the benefits of full ownership unbundling. Of the country case studies, only the United Kingdom and The Netherlands pursued full ownership unbundling. France and Germany argued for structural unbundling that fell short of full ownership unbundling, and the latest EU Gas Directive included this option along with strong regulatory measures to enforce a well-developed structural unbundling model. Experience in the United States also suggested that a competitive natural gas market can be supported without mandatory ownership unbundling, provided the operations of transmission companies are tightly prescribed. Each of these cases followed a unique path to unbundling (Fig. 19.17).

  Fig. 19.17

  

  The path of unbundling (ultimate ownership rights unbundling might not be necessary)

  In general, structural unbundling can be effective if the regulator is strong. However, anything less than structural unbundling is likely to be inadequate in delivering liberalised natural gas markets. The experience of the United Kingdom and Japan indicated that service unbundling alone offered few benefits and that service and account unbundling, combined with meaningful functional unbundling, was the minimum viable unbundling models. However, this combination of unbundling models should be seen as a stepping stone to deeper unbundling, rather than an end point. The European experience also indicated that legal unbundling offered little without moving to deeper structural unbundling, complemented with functional unbundling.

  These observations suggest a streamlined unbundling process consisting of three steps (Fig. 19.18). Functional unbundling supports this process at key junctions, principally in the account, legal and structural unbundling phases.

  Fig. 19.18

  

  Streamlined unbundling process (three steps only)

• Domestic production can increase the benefits of unbundling. A key benefit of unbundling was to open upstream activities to competition and efficient production. In markets that had few indigenous natural gas resources and were heavily reliant on imports, unbundling and other open-access measures promoted the efficient delivery of natural gas to market, but had only a limited impact on upstream activity. In contrast, in countries with substantial indigenous resources, unbundling and other open-access measures could promote domestic production by enhancing access to downstream wholesale and retail markets. Indeed, countries with more domestic production have tended to unbundle earlier and more comprehensively (Fig. 19.19).

  Fig. 19.19

  

  Correlation of domestic natural gas production volumes and levels of and timing of unbundling. Note Characterising 1992 reforms in the United States as structural unbundling is based on the strong non-discrimination, transparency and capacity release requirements of FERC Order 636, reinforced with extensive functional unbundling measures. Source Vivid Economics, based on Gao and IEA

  The Netherlands and United Kingdom, with their indigenous North Sea resources, pursued unbundling more rapidly than nations such as France and Germany with limited domestic reserves. The United States, with its substantial and geographically diverse upstream resources, was the world leader in unbundling efforts, requiring legal and other structural unbundling measures as early as 1992. Japan, with its negligible domestic natural gas resources, pursued unbundling only tentatively. This suggests that countries with significant domestic resources perceive higher economic benefits from unbundling—in terms of promoting a dynamic and competitive upstream sector and unlocking the economic and energy security benefits of domestic production—and are more willing to pursue these reforms.

• LNG and storage facilities tend to face less strict unbundling regimes than pipelines. Unbundling requirements for LNG terminals and storage facilities were generally less stringent than for pipelines, reflecting the greater potential for competitive pressure on these facilities, as well as the relatively new development of this type of infrastructure. The potential for LNG regasification terminals or storage facilities to exercise excessive market power depends on the number of alternative providers of similar services. In a physically well-connected market, LNG terminals are one source of supply competing alongside many others and have limited market power. Similarly, a diversified and well-connected market may have multiple storage providers, as well as other options such as pipeline linepack (in which natural gas is stored in the pipeline), flexible production capacity and demand curtailment. Other than in very small or fragmented markets, the potential for LNG terminals and storage facilities to exercise market power is likely to be limited. As a result, both unbundling and third-party access requirements tended to be more lenient for these facilities.

3.3 Case Study 1: The UK—The Long and Difficult Road to Spinoff

Despite the United Kingdom’s position today as an exemplary case of full natural gas supply chain unbundling, the process has been far from smooth. Regulatory arrangements were reviewed and amended on numerous occasions before the present market structure was largely reached in 2000. Unbundling was not always synchronised with liberalisation, and with measures to introduce competition in the broader gas market. Full ownership unbundling was only achieved in 2000 when the then British Gas Plc separated its Transco subsidiary into the separately owned Lattice Group Plc, well after the emergence of substantial gas market competition through the early and mid-1990s.

By that time, substantial competition had already emerged in large parts of the UK natural gas market. British Gas had already lost significant market share before major reforms under the Gas Act of 1995 were implemented. The Gas Release Scheme, for instance, had forced British Gas to release natural gas contracts to competing suppliers. A compounding factor was that many of British Gas’s legacy North Sea natural gas contracts were priced higher than prevailing market prices, pressuring the company’s market position.

The first phase of reform was marked by the Gas Act of 1986. The act privatised the state-owned British Gas Corp. as British Gas Plc and provided a limited form of service unbundling of the company’s pipeline operations. The act allowed larger natural gas customers to source natural gas from any authorised supplier and required British Gas to allow these suppliers to use its pipelines. In effect, British Gas was told to offer a standalone pipeline service to competitors seeking to supply large customers. However, this service unbundling was not supported by account or functional unbundling and proved to be largely ineffective. The Monopolies and Mergers Commission found in 1988 that British Gas had been abusing its market position by engaging in price discrimination and sought to address this by requiring the company to publish common carriage terms to support pipeline access. The change, however, was still largely ineffective.

Subsequent reviews by the Office of Fair Trading in 1991 and the Monopolies and Mergers Commission in 1993 suggested that further unbundling was necessary to promote competition. The Office of Fair Trading review addressed a range of other structural elements of the natural gas market other than unbundling. It led to British Gas undertaking to make supply available to competitors under the Gas Release Strategy, which triggered a substantial reduction in its market share with large industrial customers between 1991 and 1993. It was these provisions, rather than its unbundling recommendations, that were instrumental in driving a decline in British Gas’s market share.

In response to the critical 1993 Monopolies and Mergers Commission review, British Gas bypassed the account unbundling phase and voluntarily moved directly to legal unbundling in 1994. A transportation and storage subsidiary, Transco, was created and separated from British Gas’s trading and sales activities. Despite the commission’s recommendation for full ownership unbundling, in response to regulatory and commercial pressures, the unbundling of British Gas progressed in two further phases.

The Gas Act of 1995 required Transco to establish a Network Code to govern the national transmission system, which effectively constituted structural unbundling of the network business. The code was published in 1996, establishing the rules and procedures for third-party access to pipelines and introducing a regime for daily balancing. The code strengthened access to the pipeline system for natural gas market players, supporting competition even though Transco remained a British Gas subsidiary.

However, this business structure did not last, as competitive pressures built around British Gas. The 1995 Gas Act extended the scope of competition to include the smallest, residential customers, and full retail competition was implemented across the United Kingdom by 1997. As competition in both large and small user markets deepened, the relatively high price of British Gas’s legacy upstream contracts for North Sea gas weighed on its business. The pressure prompted British Gas to voluntarily divest its trading and sales businesses. British Gas was unbundled into two entities: Centrica plc, which held sales and retail units, as well as upstream assets in Morecombe Bay, and BG plc, which retained Transco, the midstream unit, as well as domestic and global upstream assets.

This structural unbundling model appears to have been effective, even though Transco remained a subsidiary of BG, a major upstream player. Transco held some ownership of upstream assets, and its separation from BG was maintained by the Network Code.

The final step in full ownership unbundling came in 2000, when BG split into the BG Group and the Lattice Group, which took ownership of Transco. The split meant that Transco was entirely separated from all upstream and downstream assets. Further ownership changes saw the Lattice Group merge with the operator of the United Kingdom’s electricity grid, National Grid, in 2002 and sell off some local distribution networks in 2005. While Transco initially included storage assets, these were spun off into a storage subsidiary, which was privatised in 2001 and purchased by Centrica in 2002.

3.4 Case Study 2: Europe—The Step-by-Step Progression Towards Spinoff and the Multitude of Choices

The EU regulatory regime has evolved towards greater unbundling over the course of three major regulatory packages since 1998. These stages broadly comprise account and functional unbundling in 1998, legal unbundling from 2003 and more detailed structural and ownership bundling approaches since 2009. Some member states have moved to comply with EU directives more swiftly than others, and several have gone beyond the minimum requirements of EU regulation.

Differences on the merits of unbundling have led to a diversity of approaches among EU member states and an EU regulatory approach that offers a menu of unbundling options rather than a single prescriptive model. Development of the Third Gas Directive was contentious and ultimately led to a political and regulatory compromise that offered two main unbundling models: structural unbundling and ownership unbundling.

The characteristics of the member states that took different positions within this debate illuminate the motivations and concerns of those arguing for and against ownership unbundling models. For example, countries with domestic natural gas resources, such as the United Kingdom and The Netherlands, appear to be more enthusiastic proponents of unbundling. The benefits of unbundling are greater in such countries, promoting competition among natural gas producers. Conversely, in countries like Germany, where there are limited domestic natural gas resources and the primary physical assets held by natural gas businesses are pipelines, unbundling was more hesitant. These fundamental differences could, in part, explain varying regulatory attitudes toward unbundling.

The First Gas Directive successfully achieved account unbundling, but does not appear to have had substantial effects on gas market competition. The directive required separate accounts for transmission, distribution and storage activities to support transparency and competition in these activities. A 2003 benchmarking report by the European Commission found that all member states had complied with minimum account unbundling requirements and several had gone further to legal or ownership unbundling. However, the same report noted that prospects for competition in the natural gas market were lagging significantly behind those for electricity in many member states, citing Germany in particular. Around 2001, the European Commission itself began arguing that the first package of measures had been ineffective and that further reforms were needed.

One weakness of the First Gas Directive may have been limited functional unbundling in support of the core model of account unbundling. While the directive included some broad provisions against discriminatory behaviour and a general requirement for transmission providers not to abuse commercially sensitive information obtained from third parties, it did not include detailed and enforceable provisions to separate information and management systems between transmission and other business units. Some member states, including The Netherlands and Ireland, voluntarily adopted functional unbundling measures to separate management of transportation businesses. Others, such as Austria, Belgium, Denmark and Italy, went further, adopting legal unbundling. Meanwhile, Spain and the United Kingdom moved to ownership unbundling. However, some major member states, notably France and Germany, only implemented the directive’s minimum requirement of account unbundling and appear to have been slower in progressing natural gas market competition during this period.

The Second Gas Directive, adopted in 2003, mandated the legal separation of transmission businesses, reinforced with functional unbundling measures. The directive required transmission system operators to be “independent at least in terms of legal form, organisation, and decision-making from other activities not relating to transmission”. Specific functional unbundling measures required entirely separate management, effective independent decision-making rights and a compliance programme to maintain independence. Member states adopted elements of the Second Gas Directive at different speeds and to differing degrees. By 2005, for example, The Netherlands had established full ownership unbundling, while Germany had only implemented minimum regulatory requirements for a legal unbundling regime.

Policy-makers and market observers quickly concluded the Second Gas Directive was also ineffective in promoting competition and argued for further reform. A 2007 European Commission report found that “wholesale gas trade has been slow to develop, and the incumbents remain dominant in their traditional markets”. It concluded that the level of unbundling in place was inadequate to “resolve the systemic conflict of interest inherent in the vertical integration of supply and network activities”. In the same year, an IEA review of German energy policies concluded that legal unbundling was ineffective and that the involvement of traders in pipeline businesses had limited the liquidity of wholesale markets. A similar 2009 IEA review of French energy policies identified the dominance of GDF-Suez, especially in the bilateral trade of wholesale natural gas, as constraining the ability of other market players to supply the French market.

Earlier reform efforts had targeted mandatory ownership unbundling. For example, the European Commission argued in 2007 that “full ownership unbundling is the most effective means to ensure choice for energy users and encourage investment.” However, nine member states—including France and Germany—opposed full ownership unbundling, saying that it would not improve competition or reduce prices. They argued that breaking up large, vertically integrated energy companies would weaken their negotiating power in international markets—for example with powerful external suppliers such as Russia’s Gazprom—with no benefit to consumers.

The adoption of the Third Gas Directive was contentious, with several large member states arguing against mandatory ownership unbundling. The compromise captured in the Third Directive presented ownership unbundling as the ideal model, but allowed member states to choose from two alternative structural unbundling models. The directive recommended full 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 for the market”. It also argued that the two alternative models, the independent transmission operator (ITO) model and the independent system operator (ISO) model, “should enable a vertically integrated undertaking to maintain ownership of network assets while ensuring an effective separation of interests, provided that…extensive regulatory control mechanisms are put in place”.

The ISO and ITO models were essentially less stringent forms of unbundling. Unlike ownership unbundling, setting up an ISO or ITO would let transmission networks remain under the ownership of vertically integrated firms.

EU member states have adopted either full ownership unbundling or the ITO model. The United Kingdom, The Netherlands, Denmark and Spain have ownership unbundling models, though these regimes were in place before the Third Gas Directive was adopted. Elsewhere, the ITO model has been adopted, complemented by a range of strong functional unbundling requirements. By mid-2014, 21 natural gas transmission operators had been certified.

No country had pursued the ISO model by mid-2014. The core element of the ISO model was that network ownership remains with a subsidiary of the vertically integrated entity, but system operation and investment decisions are made by a legally separate entity with separate ownership. Vertically integrated companies seemed unconvinced by an approach that would require them to fund investments made by entirely separate entities, while the ITO model allowed investment decisions to be made jointly by the parent company and the regulatory authority.

The choice between the full unbundling and the ITO model may reflect different evolutionary stages in the development of natural gas markets. Countries that embraced full ownership unbundling started their reform processes earlier and progressed more rapidly along the spectrum of unbundling models. The progress made in markets such as the United Kingdom and The Netherlands may reflect the maturity of their unbundling efforts, rather than the advantage of ownership unbundling over alternative models. Indeed, an effective and mature structural unbundling model may be sufficient to support and enable competition in the upstream and downstream segments of the natural gas value chain.

3.5 Case Study 3: Japan—Market Characteristics Restricting Unbundling

Japan’s two tentative attempts at unbundling appear to have had only a modest effect on its natural gas market, although the lack of competition may also reflect the fundamentals of the Japanese markets as much as the merits of its regulatory efforts. One of the benefits of unbundling appears to be a dynamic upstream market, but since Japan has no domestic natural gas resources, this incentive is less compelling. Minimal pipeline interconnectivity further limits the potential for regulation to unlock competition. In general, the limitations of Japan’s unbundling efforts since 1995 may be both a symptom and a cause of the lack of competition.

Japan began its unbundling measures in 1995 with a service unbundling regime. The 1995 reform required Japan’s three largest natural gas companies to offer pipeline services to competitors seeking to supply large consumers, underpinning the emerging third-party access regime. These requirements were extended to additional customers in 1999. They were reinforced in 2000 with functional unbundling requirements that directed companies to separate the transportation function from other elements of their business. However, the measures were lenient and did not materially change the behaviour of incumbent natural gas suppliers. A second wave of reform in 2003 and 2004 introduced account unbundling supported by new and more stringent functional unbundling requirements. The functional unbundling measures required separate physical office locations, staff functions, and decision-making and prohibited information sharing. Compliance improved, but was not uniform.

The overall reform programme has been only modestly successful, with markets remaining highly concentrated. As of 2012, three large, vertically integrated players together supplied around 70% of the market. Companies wanting to use pipelines owned by other companies have complained of entry barriers and opaque access requirements. In particular, many complained of insufficient information on the available capacity of pipelines and on standards and procedures for assessing fees and other compensation mechanisms.

The Japanese experience suggests that account and functional unbundling can deliver benefits, but its value may have been limited by the fundamentals of the Japanese natural gas market. Service and account unbundling, combined with meaningful functional unbundling, appears to be the minimum viable unbundling model, acting as a stepping stone to more advanced unbundling model.

3.6 Unbundling LNG Terminals and Gas Storage Facilities

Unbundling requirements for LNG terminals and storage facilities are generally less stringent than for pipelines, reflecting the greater potential for competitive pressure on these facilities, as well as the relatively new development of this type of infrastructure. The potential for LNG regasification terminals or storage facilities to exercise market power depends on the number of alternative providers of similar services and the degree of interconnection between them. In most markets, there are likely to be a larger number of LNG terminals and storage sites than pipeline routes because of the smaller economies of scale. Moreover, in a physically well-connected market, LNG terminals will compete with each other and with other sources of supply, limiting their market power. Similarly, a diversified and well-connected market may have multiple storage providers, alongside storage services provided by pipeline linepack, flexible production capacity and demand curtailment.

Except in very small or fragmented markets, the potential for LNG terminals and storage facilities to exercise market power is likely to be limited, and regulations mandating unbundling and third-party access requirements will not tend to be as stringent as for pipelines. For example, Japan requires only account unbundling for LNG facilities and places no requirements on storage facilities. Unbundling requirements in the European Union are stronger than those in Japan for both LNG regasification terminals and storage facilities, with both types of facilities required to have unbundled accounts. In addition, storage operators cannot participate in company structures of vertically integrated natural gas companies, imposing an additional functional unbundling requirement.

A range of European LNG and storage facilities have gone beyond the minimum regulatory requirements for account unbundling, adopting either legal or ownership unbundling. In some cases, particularly for LNG terminals, legal unbundling has been adopted for practical reasons associated with forming joint ventures. Ownership unbundling has been adopted in instances when transportation assets face unbundling requirements, and since storage facilities or LNG terminals are held by transportation owners, they become unbundled from upstream and downstream interests by default. In other cases, legal unbundling through wholly-owned subsidiaries has occurred on a voluntary basis, possibly pre-empting regulatory requirements to unbundle or other regulations limiting the benefits of vertical integration. Finally, new LNG terminals can receive an exemption from third-party requirements if, among other things, they are unbundled.

Examples of LNG facilities and storage facilities and their prevailing level of unbundling show a wide range of approaches (Table 19.5). Overall, the range of experience suggests that access to LNG or storage terminals is not a key regulatory concern in the European market and that legal unbundling of these facilities is not an imposition on normal commercial behaviour.

Table 19.5 European LNG receiving stations and gas reserve facilities and their voluntary unbundling

4 The Downstream Segment: Natural Gas Trading Hubs and the Liberalisation of Wholesale Natural Gas Markets

The downstream segment of the natural gas value chain includes wholesale and retail markets supplying gas to end users. Greater competition in the downstream segment can increase choice and reduce the price paid by the end users of natural gas, for example by establishing natural gas hubs and increasing competition in wholesale markets. Competitive wholesale markets, in turn, are important for ensuring effective retail competition and delivering benefits for consumers and end users. Whether focused on a physical location, such as Henry Hub in the United States, or a virtual platform, such as Britain’s NBP, activity on wholesale markets is the dominant factor in pricing and delivering natural gas to retailers and, eventually, end users.

This section analyses the experience of the United States, the United Kingdom and continental Europe in constructing natural gas trading hubs, providing a reference point to China in promoting its own natural gas downstream market liberalisation.

4.1 Pros and Cons of Natural Gas Hubs

There are two basic types of natural gas hub: physical hubs, such Henry Hub in the United States, and virtual hubs, such as the NBP in the United Kingdom. The IEA defines a physical hub as a geographical point in the network where the price is set for natural gas delivered to that specific location. A virtual hub, on the other hand, sets the price for natural gas across a wider geographic area. Unlike a physical hub, the NBP price reflects the price in the entire area without geographic differentials linked to transport costs. In general, a natural gas hub cannot be both physical and virtual, but it can evolve over time, for instance, starting as a physical hub and then expanding to become a wider virtual hub.

A natural gas hub has two core functions. The first is to physically connect buyers and sellers in a natural gas system. Before the creation of a hub, a gas system may already have many or all of the individual elements required for a hub, and some of them may already be connected. A hub strengthens these connections by linking physical flows between buyers and sellers across the entire system (Fig. 19.20). The second is to competitively determination natural gas prices. A gas hub provides a point or area in the gas network where demand and supply are balanced by a price. This balancing price is determined through competition between many buyers and sellers in the marketplace. In this way, hub prices reflect the fundamental market conditions for natural gas rather than prices tied to other commodities such as oil-indexed prices or regulated prices set by the government.

Fig. 19.20

The position of natural gas hubs in connecting buyers and sellers

Natural gas hubs also provide a set of institutional rules, standardised contracts and price benchmarks. Hub prices serve as a focal point for market participants, ensuring that natural gas market conditions are widely known. In this way, hubs increase market transparency and lower transaction costs. Hub prices can also be used as references in contracts without delivery through the hub itself.

The creation of a natural gas hub comes with a variety of benefits, but also has potential drawbacks. The benefits include:

• Market-based price signals raise the economic efficiency of trade and investment decisions. The competitive trading of natural gas sets a price that reflects the true cost and value of gas in the economy. These competitive prices direct natural gas to where it is most needed from whoever can supply it most cheaply. Trade takes place only when it is economically efficient, maximising the overall gains from trade. Such co-ordination is difficult to achieve other than through market mechanisms, especially in large and complex gas systems. In the longer term, the signals from competitive prices raise the quality of capital allocation as they drive natural gas market players to make investments only when they can create real economic value.

• Hubs benefit from powerful and often self-reinforcing network effects. Better market co-ordination, contact standardisation and greater transparency facilitate trading by reducing the costs of transactions. A hub lowers market participants’ costs in searching for trading partners, who can now be easily found at exchanges or over the counter at the hub. A hub also reduces bargaining over the terms of the trade: a reference price and standardised contracts avoid wasted time and resources in negotiation over the terms of bespoke bilateral contracts. By reducing transaction costs, a hub makes it easier for new players to enter the natural gas market, widening market participation and increasing competition.

• A natural gas hub can improve a country’s security of energy supply. Hubs help to diversify sources of supply; for example, by connecting regions within a country. Moreover, efficient price signals mean that, when markets are tight, additional supply is encouraged to come to market while also inducing reductions in gas demand. This helps to reduce the likelihood of unanticipated natural gas shortages.

However, natural gas trading hubs also have some potential drawbacks:

• Hubs can disrupt pre-existing arrangements in a country’s natural gas industry. In particular, hub prices are determined by competitive forces, not by the government or a dominant incumbent. A transition to hub pricing puts pressure on incumbent players and leads to a shift in the structure of natural gas markets. Hub pricing also puts pressure on regulated prices, as well as any remaining oil-indexed contracts. For example, the international trend since 2005 towards hub pricing, most notably in Europe, has reduced the role of long-term, oil-linked contracts. Natural gas in North America is almost entirely priced on hubs, while half of European natural gas is priced on hubs, rather than through oil-indexed contracts.

• There is no guarantee that prices will decline with the emergence of hub pricing. At any particular time, hub prices may be higher or lower than oil-indexed contract prices. However, there appears to be a tendency for hub prices to be lower. For example, NBP prices were below European oil-indexed prices 77% of the time between 2000 and 2014. An increase in prices may have adverse impacts on broader state development objectives, especially in poorer regions, for example putting upward price pressure on domestic heating. However, hubs tend to develop when the oil-indexed contract price fails to clear the market, that is, when supply is available in excess of contracted volumes and demand for this extra supply exists at prices below oil-indexed contract prices. As a result, the hub price paid for non-contracted volumes will be below the oil-indexed contract price, and the potential savings between oil-indexed prices and hub prices encourage buyers to switch from oil-indexed contracts to hubs.

• Hub prices have tended to be more volatile than oil-indexed contract prices. Because of averaging and time lags, oil-indexed contracts tend to be less volatile than hub prices. The volatility of hub prices may be perceived as costly by natural gas buyers, although experience suggests that such price risks can be managed, especially in well-developed hub markets with a wide array of financial contracts for natural gas.

A China natural gas hub is likely to create long-lasting benefits, while its drawbacks are likely to be temporary. China’s large and complex domestic gas market could benefit from value-based pricing, market co-ordination and lower transaction costs. China’s market size means that valuable network effects could also operate more strongly. A natural gas hub could further encourage local gas production, including from shale natural gas, and improve energy import diversity and responsiveness. Consumer gas prices could fall following the establishment of hub pricing, although they could rise again later.

4.2 The Important Inspiration of International Experience in the Development of Natural Gas Trading Hubs

A successful natural gas hub can only develop and be successful under a clear set of physical, market, and institutional conditions (Table 19.6). These conditions follow from the functions that a natural gas hub performs, informed by the experience from countries that have developed hubs.

Table 19.6 Necessary preconditions in three areas for the successful development of a natural gas hub

Since the 1990s, the world has accumulated considerable experience in creating and developing natural gas hubs. This experience centres on US and European markets. The US natural gas market was restructured in the 1980s and 1990s, and its Henry Hub price has become the world’s leading natural gas price indicator. A similar process of liberalisation began in the United Kingdom in the 1990s, leading to creation of the NBP, the leading hub in Europe. In continental Europe, market liberalisation began later and has proceeded more slowly as part of European Commission’s plans for an Internal Energy Market.

Insights from the experience of the United States, continental Europe and the United Kingdom could benefit China. Indeed, China shares some structural features with the United States—in particular, both are geographically vast, with domestic production far removed from centres of demand. These characteristics suggest that, like the US Henry Hub, China may need a physical hub to accommodate significant differences in transmission costs to various dispersed destinations. Essentially, a physical hub prices natural gas at a single physical point of the network, after which transmission costs are added. This contrasts with a virtual hub, such as the NBP, which sets the price for natural gas within a region and imposes a fixed transmission cost for natural gas delivered within that region. A virtual hub is appropriate for a market with a relatively small delivery region and fixed transmission costs. The situation in China may be best served by multiple hubs that follow the pricing of a main hub, a structure similar to that seen in the United States.

The process of building a hub in Europe also has relevance for China. Hub development in continental Europe and the United Kingdom took place against a backdrop of domestic production and imported natural gas, both through pipeline and as LNG. In contrast, US hub development took place without LNG playing an important role. Continental European natural gas markets have also been undergoing a gradual transition from a highly regulated, state-dominated system in the 1990s towards a fully liberalised system. Finally, potentially analogous to Asian markets, Europe has been home to several regional hubs that coexist on the EU natural gas market.

Overall, a robust and credible liberalisation process, along with favourable market conditions, has been instrumental in the development of natural gas hubs. The US experience shows that open access to pipelines is critical for market-based pricing, and that liberalisation can help wholesale markets shift away from long-term contracts and towards market-based pricing in 5–10 years. The experience of continental Europe is of hubs being established as a result of favourable market conditions enabled by the regulatory reform process. In these cases, market forces created a buyers’ market in natural gas, which, combined with the liberalisation of natural gas markets, accelerated hub development. The UK experience is one of market and regulatory changes working in parallel to increase competition in wholesale markets, leading to the establishment of the NBP. Standardisation of contracts played a key role in driving hub success in the United Kingdom.

4.3 Case Study 1: The United States—Regional Price Balances and Short-Term Pricing

The US natural gas market underwent fundamental reform beginning in the 1980s, with the emergence of ample natural gas supplies and regulatory changes to liberalise the market. In the 1980s and early 1990s, the US regulator, FERC, implemented reforms to decouple the production and trading of natural gas from its transportation by pipeline. The economic argument was that the production and consumption of natural gas can involve many different buyers and sellers and has the potential to be competitive. Meanwhile, pipeline transport services were often highly concentrated, as a result of their natural monopoly characteristics, and should be regulated. As an alternative, guaranteed open access for all market participants on a non-discriminatory basis could create greater competition among producers and natural gas shippers and better allocation of economic resources.

The empirical evidence shows that reforms in the United States had substantial impact quickly. In the early 1990s, movements of natural gas prices in different regions were weakly correlated, with significant price divergence. By the late 1990s, wholesale price correlations had risen to very high levels with the application of the law of one price, an approach that equalised prices across locations, excluding transport costs. Evidence suggests that regulation to ensure non-discriminatory open access to pipelines played a key role in driving the move to a competitive, national natural gas market.

In parallel, the underlying contract structure of the industry shifted from long-term contracts to short-term pricing. Existing long-term contracts were either renegotiated in light of the changed market environment or terminated. Spot and futures prices emerged as the key co-ordinating mechanisms within the US natural gas sector, with pricing centred on Henry Hub. Market concentration fell, with the 20 largest players accounting for 44% of physical and financial transaction volumes in 2014. More recently, the Henry Hub price, plus a mark-up for transport, has been used in LNG contracts between US exporters and foreign buyers.

4.4 Case Study 2: Continental Europe—Market Conditions for Natural Gas Hub Development

European natural gas hubs began developing only in 2008, reflecting the slow progress of EU natural gas market liberalisation. Northern Europe is more advanced than southern Europe in terms of natural gas trading and hub development. The legacy system of bilaterally negotiated oil-indexed natural gas contracts remains more prevalent in the south.

Several factors drove deepened natural gas trading and hub development in Western Europe after 2008. The 2008 global financial crisis dampened European natural gas demand, in contrast to the boom that had been expected. Increased shale natural gas production in the United States meant that the country no longer imported LNG, with much of the freed supply diverted to Europe. These two factors created a buyers’ market in natural gas, and traders and brokers in key European markets—especially Germany and France—began to enjoy access to uncontracted pipeline natural gas. Low natural gas demand and greater LNG supply coupled with high oil prices meant that oil-linked contract prices rose above market-based natural gas prices, creating powerful incentives for buyers to renegotiate long-term contracts with upstream natural gas suppliers, such as Norway and Russia. Within a few years, long-term contracts had either been terminated or renegotiated to reflect market-based hub prices rather than oil prices.

The Dutch Title Transfer Facility (TTF) is widely seen as the most successful of the continental European natural gas trading hubs. The facility was deliberately designed as a virtual hub, based on its physical pipeline and LNG connections, its geographic location and the large domestic natural gas supply from the Dutch Groningen field. Development of the TTF accelerated in the late 2000s, and it has overtaken NBP as Europe’s most liquid hub. In contrast, the Belgian Zeebrugge hub is generally seen as a much less successful natural gas trading centre. Conditions at Zeebrugge—its location and relatively early development—once suggested that it could become the leading European natural gas hub, but local trading restrictions limited the number of market participants and slowed the development of its trading platform.

Overall, the move towards more active natural gas trading has increased the correlation of natural gas prices across European countries, similar to the US experience in the 1990s. Spot prices in the European Union now account for about half the natural gas trade.

4.5 Case Study 3: The UK—Two Natural Gas Market Reform Bills

Natural gas market liberalisation began in the United Kingdom in the 1990s, following a wave of privatisations in the previous decade. The United Kingdom was the first country in Europe to begin natural gas market reform, and aspects of first-mover advantage remain.

Two pieces of regulation were especially important to the reform effort in the United Kingdom. The Gas Act of 1986 removed the de facto monopoly of British Gas in serving large natural gas customers, while also requiring open access to its pipelines for its competitors. The Gas Act of 1995 set out a statutory timetable for full competition in the British natural gas market, including at the residential level. As a result, the market share held by British Gas declined rapidly, from nearly 100% in 1990 to 29% by 1996. These institutional and regulatory changes led to a surge in the number of market participants and trading activity during the mid-1990s. Among the new entrants to the natural gas market were merchant banks, electricity companies and foreign and domestic trading houses. The number of participants in the wholesale market rose from fewer than 15 in 1995 to more than 50 within about two years.

The 1995 Gas Act also established the Network Code, a key element in the development of natural gas trading. The code is a set of rules and procedures governing third-party access to the UK natural gas pipeline network. The code also enabled a system of daily balancing, which required short-term natural gas trades.

These regulatory developments were accompanied by shifts in the country’s demand and supply of natural gas. On the demand side, the “dash for gas” in the British electricity industry saw the growth of generation capacity using flexible combined-cycle natural gas turbines. On the supply side, natural gas was available from domestic production in the North Sea. The regulatory changes introduced by the Gas Acts of 1986 and 1995 meant that new participants were able to access natural gas segments across the value chain.

The regulatory and market factors combined put pressure on the old system of bilateral contracts, which were typically indexed to other commodities, such as gas oil or fuel oil. The NBP was created within the code as a virtual hub to promote the balancing of the natural gas system. From the late 1990s, the NBP evolved quickly as a trading point and was used as the basis for the standardised NBP97 contract, which became the cornerstone of British over-the-counter contracts. The NBP also became the delivery point for the Intercontinental Exchange natural gas futures contract.

With the deepening of UK natural gas trade since the late 1990s, NBP has become a leading natural gas hub in Europe. A number of factors helped its ascension, including the existence of domestic natural gas reserves, periods of high demand for natural gas and a stable regulatory framework that enabled open-access market participation via open access and offered a clear set of rules and standardised contracts.

4.6 Establishing Natural Gas Hubs in China

Natural gas hubs are market institutions, and thus to create a successful hub in China, the market structure of the natural gas industry in China will need to be changed. This will generate efficiency and generate costs, while also creating winners and losers. However, the long-term benefits of China establishing a hub are clear, as it will raise domestic natural gas production, raise energy diversification and also have major significance to response capabilities. Construction of natural gas hubs in China is therefore critical to the development of natural gas. This section will discuss the overall prospects for construction of natural gas hubs in China and the factors that must be considered in hub development, and analyse the potential steps.

• 1. The overall outlook for construction of natural gas trading hubs in China

Insights gained from international experience in establishing natural gas hubs, combined with an assessment of China’s circumstances, lead to five key conclusions.

• China is in a good position to develop more market-based natural gas trading with hub pricing. Key positive factors include domestic gas production, exposure to both pipeline and LNG imports, and its size within Asian energy markets.

• China’s large and complex domestic natural gas market would benefit from value-based pricing, market co-ordination and lower transaction costs. It is likely that these efficiency gains from hub pricing will bring large and long-lasting benefits, while any adverse effects, particularly disruption of current market arrangements, would be short-lived.

• A successful hub would require significant further liberalisation of the natural gas sector in China, which would reduce the influence of state-owned incumbents, improve market transparency, and create a level playing field for new market entrants through third-party access arrangements.

• China can move towards hub pricing in a series of small steps, backed by government policy. Beginning with pilot natural gas trading in a particular region, these steps may gradually satisfy the pre-conditions for a successful hub and ease the transition for incumbents.

• China is likely to develop the leading hub in Asia. Even though international experience suggests that first-mover advantages exist in the development of gas hubs, it is likely that a China hub would become the Asian market leader even if it emerges later than hubs in other countries in the region.

• 2. Factors for consideration when developing hubs

Based on international experience, the primary conditions for creating a successful hub are a well-developed physical natural gas transmission network that market participants can access under non-discriminatory conditions; a large number of independent buyers and sellers actively engaged in arbitrage, but without significant market power; and a government commitment to liberalising wholesale gas markets and a stable, transparent and credible regulatory framework.

Many of these preconditions for a successful hub are not currently met in Asian countries, including China. For instance, in China transmission infrastructure remains under development, markets are concentrated, prices are widely regulated and regulations such as third-party access rules that support the smooth operation of a market with many buyers and sellers are not yet in place.

A plan to develop a Chinese natural gas hub could begin by securing the preconditions through liberalisation of the natural gas sector in China. A hub is a market institution and requires market liberalisation to function well. Liberalisation facilitates a hub by enabling prices to be set competitively, reducing the influence of state-owned incumbents, improving market transparency and creating a level playing field for new market entrants through third-party access arrangements.

Hub pricing creates winners and losers along the natural gas value chain. Some players, protected under the previous regulatory regime, could lose revenues. Improving market signals could undermine the main rationale for vertical integration and for co-ordinating action across a supply chain. Other players, on the other hand, could benefit from greater market connectivity and the ability to optimise asset portfolios more actively.

Who wins and who loses, and by how much, is also affected by the oil price. Historically, natural gas prices have been driven by oil indexation. A higher oil price would mean higher natural gas contract prices, and moving to hub pricing would create strong downward pressure on natural gas prices. Midstream utilities that are locked into long-term oil-indexed contracts but unable to pass through their higher costs to consumers would be among the losers. However, in a world with lower oil prices, as seen since late 2014, legacy oil-linked natural gas contract prices would lie below the market-determined price for natural gas, thus potentially reversing the roles of winners and losers were a hub established, and slowing the adoption of hub pricing.

International experience shows that natural gas hubs are formed in response to market pressure coming from domestic sources or international market developments. In the past, the development of hubs has often been driven by large additional supplies of natural gas seeking access to consumers. This supply has either been domestically produced, as in the case of the UK’s NBP hub development in the 1990s, or available from global LNG markets, as in the deepening of continental European hub markets from the late 2000s.

At least three supply-side factors are exerting market pressure to form a hub in China: expanding domestic gas production, including from unconventional sources; supplies from the global LNG market not already contractually committed to particular export markets; and additional gas imports from Russia from existing or planned pipelines.

The development of natural gas hubs elsewhere in Asia could also challenge China’s domestic natural gas pricing arrangements and create momentum for a Chinese natural gas hub. For example, Singapore has put itself forward as an LNG hub, with limited trading since 2014. Japan has begun to publish spot LNG prices and has proposed the creation of a futures market. Although the European experience suggests that there are first-mover advantages in hub creation, a potential Chinese hub is likely to become the principal Asian hub even if it is not the first. China’s economy is much larger, with large industrial consumers of natural gas. China also has significant domestic production and has begun to develop a national pipeline network. China’s natural gas imports come over pipelines as well as LNG, unlike the rest of Asia, which relies heavily on LNG. These factors suggest that, supported by the appropriate regulatory environment, a Chinese hub is likely to emerge as the leader in Asia.

• 3. Potential steps for developing hubs

International experience shows that successful hub development takes time—at least 5–10 years—even in countries with energy sectors that were much more liberalised than that in China.

Taking an incremental and phased approach would allow China to address the preconditions for full hub pricing, within the broader market liberalisation process. Rushing to establish a full hub by government mandate in the early stages of liberalisation is likely to fail because of a shortage of participants and institutions. A phased approach, on the other hand, would allow market participants to learn and build institutions concurrently with a liberalisation programme. A phased approach would also allow for the gradual creation of a support network among participants, as various players have time to adjust to the new liberalised markets and the benefits of market-based pricing become more apparent.

The evolution of China’s natural gas sector towards hub pricing could be phased over 5–10 years and cover six specific aspects (Fig. 19.21).

Fig. 19.21

Hub development and its support from regulatory measures and their market effects

• Pilot trading market: Within an individual region, such as Shanghai, the government could create a pilot trading market with contestable natural gas demand and some uncontracted natural gas supply. The market would be connected through a natural gas network with third-party access. Entrepreneurs would also be encouraged to trade the uncontracted natural gas supply to meet demand among the customers, who are free to choose their supplier.

• Price transparency: The government could require publication of prices of natural gas sold under all types of contracts. The mandate would help reveal opportunities for arbitrage to entrepreneurial buyers and sellers, vital components of a successful market-based arrangement.

• Government recognition: Once significant trading activity develops within the pilot region—for example, a shift to standardised over-the-counter trading—the government could explicitly endorse the market by establishing a regulatory body. This body would standardise contracts further and seek to reduce transaction costs.

• Maturing trading: As exchange-based trading develops, the government would increase the scope of the pilot region to cover a larger geographic area or more types of buyers and sellers. At this stage, market regulation may have to become more stringent to reflect the growing system-wide role of natural gas trade.

Following these steps, a natural gas hub could then become self-sustaining with two final changes:

• Renegotiation: If traded natural gas prices are lower than legacy oil-indexed natural gas contract prices, companies paying legacy prices would be put at a disadvantage and may incur losses if they cannot pass along the price difference to their customers. With access to the liberalised trading on the natural gas hub, such companies would have a strong incentive to renegotiate legacy contracts, recalibrating prices or volumes, and buy traded natural gas instead.

• Network effects. As more and different organisations join hub trading, the benefits of the natural gas hub would increase as a result of network effect. The use and scope of hub pricing would tend to grow until it reaches the limits of either incomplete liberalisation or of geography.