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Gas readies for its oil moment

The growth in spot LNG is transforming gas into a globalised commodity market

A need to transact naturally leads to markets. But the very nature of the energy industry—large capital investments, long gestation periods, specificity of assets—can lead to very volatile markets, with high risk and the potential for violent boom-and-bust cycles.

As a result, the industry can tend away from fledgling competitive markets and towards natural monopolies. Having one large terminal or pipeline is more efficient than having many small ones. On the flip side, monopolies can often ultimately result in lower output and higher prices.

Within non-free market value chains, a government normally takes a hand in regulating prices or ensuring ‘security of supply’—and bring with them new problems such as inefficiency and regulatory capture. A better role for government is to manage a transition away from the limitations of monopoly structures into efficient, tolerably volatile market. 

Towards a traded market 

Free markets can re-emerge in one of two ways: either monopolies crumble under competitive pressures—usually caused by new entrants bringing additional supply—or by governments deliberately breaking up monopolies through policies of liberalisation.

The development of oil markets was driven to some extent by both factors, in tension with the Opec states’ governments spending over a decade trying to retard competitive market development. But it was largely the former that sparked the big bang that created truly global liquid oil trading.

Gas, due to its greater logistical challenges to oil, has been a slower developer towards a global market, and its regional market developments have perhaps seen the government deregulatory role play a larger role in the evolution of regional hubs than peer-on-peer competition as a driver (although, obviously, domestic production growth helped the emergence of the US’ Henry Hub and, in particular, the UK’s NBP market). But a volume glut and appetite for competition and innovation in international LNG could mean that gas is about to experience its oil moment. 

Oil’s long journey 

To understand the journey that gas markets are on, it must be remembered that the crude and oil products spot trading of the ’70s and ’80s did not emerge fully formed from a perfectly structured market that had been under no tension at all in prior years. The industry of the ’50s and ’60s was, admittedly, dominated by vertically integrated majors—through mutual joint ownership in several operating companies throughout the Middle East and paying royalties to their host countries as a percent of ‘posted prices’, which were deliberately kept low.

These oil majors did the vast majority of exploring, producing, transporting and refining of oil, as well as distributing and marketing the finished products. The so-called ‘Seven Sisters’ and a few other firms also finely tuned crude production to the prevailing demand for petroleum products—largely ensuring overall price stability—while also optimising supply around the globe to try to balance the market at lowest cost and maximum profit. 

Gas, due to its greater logistical challenges to oil, has been a slower developer towards a global market

But the model was, even in its earliest stages, not without its challenges. Smaller independents, most famously J. Paul Getty, were prepared to pay more for concessions and offered higher royalties, while still making substantial profits. Non-US oil was also globalising beyond the Middle East—French state oil firm Elf (now part of Total) discovered oil in Algeria in 1956; by the end of the ’50s Russia was second only to the US as the world’s largest producer.

And more than half of Libyan production—on the back of its Petroleum Law of 1955 which offered many smaller concessions and stricter terms for exploration—ended up with US producers such as Conoco, Marathon and Amerada Hess that had no refineries in Europe and no outlets for their crude, straining the vertically integrated model. These newcomers, not unlike the independent oil, and indeed gas, shale producers today, were interested in getting production out of the ground and securing a return on their investment as swiftly as possible. Not unlike the LNG markets today, this ‘wall’ of supply was looking for home. 

Opec efforts 

Into this creaking status quo was unleashed, in September 1960, the hand of government, or rather governments, in the shape of the creation of Opec at a meeting in Baghdad. Nationalisation and state control of both production and price became the key themes of the '60s and early ’70s, led by Muammar Gaddafi in Libya in 1971.

But, while majors’ ability to carefully calibrate the global supply-demand balance was gone, the new state-owned producers of Opec were, throughout the next decade, less able to impact the industry’s vertical integration. They still needed their former partners to lift, transport and refine oil and market refined products.

The last thing that Iran’s regime wanted was trading liquidity that ultimately took price control out of Opec’s hands

The catalyst for the decisive break with the old way of doing things was the fall of the Shah of Iran in 1979. The event is also a reminder of the impact the law of unintended consequences can often have on the development of markets—the last thing that Iran’s regime wanted to do was kick off trading liquidity that ultimately took price control largely out of Opec’s hands.

After the Iranian revolution, the majors were forced to cancel third-party oil deliveries, which drove buyers of oil into the spot market. With no vertically integrated market tightly controlled by a handful of firms, discrepancies between nomination dates, quantities, types and location of the crudes purchased by refiners appeared. To remedy these problems, term contract holders had to trade among themselves—rather than within their internal organisations—to move crude from where it was to where it was required. The result was a massive growth in the volume of spot trades, from some 5pc of global production in January 1979 to almost 20pc by March of the same year. 

Enter Brent 

Into this changing landscape where traditional actors were grappling with rapidly evolving roles was injected another key ingredient—new supply from a country with a strongly pro-market bias. Again, the corollary with the current US LNG supply wave is difficult to avoid.

Following the discovery of the Ekofisk, Forties and Brent fields (1969-71), North Sea production had reached 2mn bl/d by 1980, making the region a key supplier of non-Opec crude. Underpinned by elements such as English law, standardised contracts, no destination restrictions and tax advantages in ‘spinning’ or ‘churning’ the cargoes, North Sea Brent market swiftly developed as the world’s pre-eminent transparent and liquid spot oil trading market.

Gas projects are ideal for creating natural monopolies—they require large capital investments in production and distribution, often leading to just a handful of large end-users

While Opec continued to try to tightly control prices in opposition to the rising market mechanisms, a 1986 price collapse to $8/bl served to highlight the increasing futility of its efforts. In November of that year, it abruptly threw in the towel, switching the cartel’s strategy away from ‘official’ prices and towards managing Opec supply through the quota system. A new system of spot market-related formula prices, based on prevailing benchmarks, rapidly gained primacy. By 1987, over 60pc of the world’s oil supply was tied to the spot market—and the system of individual crude grades priced relative to benchmarks has survived for over 35 years. 

Gas laggard 

It is hardly surprising, given that gas is much more difficult and expensive to move around than crude—requiring pipelines and specialist storage facilities on land and complex liquefaction, shipping and regasification infrastructure to travel by sea—that its journey towards a global market has been longer.

Gas projects are ideal for creating natural monopolies—they require large capital investments in production and distribution, often leading to just one or a handful of large end-users and/or a sole seller to smaller customers. They have previously required long-term contractual commitments (often 20-30 years) at pre-arranged, or at least fully hedgeable, prices. This contract pricing does not necessarily reflect gas supply-demand fundamentals. And governments are often closely involved in all commercial and pricing decisions, sometimes underwriting projects.

Asian gas has only really started moving towards market mechanisms in the second half of the last decade

Thus far, it has been national or regional pipeline gas markets, in the US, UK, rest of Europe and, more slowly, east Asia, that have led the way towards a more market approach, mainly driven by government-mandated liberalisation. The process did not really start until the ’80s, when US president Ronald Reagan’s 1987 Natural Gas Policy Act, aimed at promoting competition and creating a unified gas market, was passed by Congress.

US interstate pipelines were hived off transportation companies only, providing open access to pipeline capacity and keeping them away from trading and marketing. Further legislation in 1992 limited the role of pipeline company affiliates and bundling of services, positioning the US gas market for take-off. 

The European experience 

In the UK, the Thatcher government introduced the 1986 Gas Act, whereby the model of state-owned British Gas as the monopsony buyer of all North Sea gas, owner of all pipeline and storage infrastructure and supplier to every end-user from the largest industrial to the householder was taken apart piece-by piece. The signing of a network code governing non-discriminatory access to the pipeline network in 1999 and the creator of market regulator Ofgem in 1999 created the platform for the rapid growth of the NBP gas market in the early ’00s.

But, alongside regulatory pressure, the development of the UK traded market was buoyed by a North Sea gas glut that provided an oversupply to supercharge liquidity. And luck also played a part—a substantial delay to the Killingholme gas-fired power plant, for which then UK utility Powergen had contracted gas supply that it did need, meant there was an, albeit not entirely voluntary, market maker for the fledgling hub.

The domestic gas oversupply led to the construction of the UK-Belgium Interconnector pipeline and the export of UK gas trading into continental Europe, initially at the pipeline’s flange at Zeebrugge. The continent’s path to a regional gas market was slower than the UK’s, as it had neither oversupply nor unanimous government support for liberalisation.

Somewhat ironically, given its imminent EU exit, the UK scored one of its most significant European wins by eventually, with European Commission support, bludgeoning French and German administrations—who had been lobbied strongly by utilities with strong links to government and fiercely resistant to giving up their hugely profitable market dominance—into submission in creating a Europe-wide gas market.

The UK’s ‘reward’ was the Dutch TTF market overtaking the NBP as the key European gas benchmark in the second half of the ’10s. But the emergence of two robust benchmarks allowed a revolution in European gas pricing— all Norwegian and most Russian pipeline gas supply to Europe is now based on some form of gas indexation. 

Asian progress 

Asian gas has only really started moving towards market mechanisms in the second half of the last decade—not illogically, given the region’s supply security concerns due to being net short of production and geographical limitations to creating a robust, interlinked pipeline network.

Japan was Asia’s first LNG importer as far back as 1969, when Tokyo utility Tepco began deliveries from Alaska. The oil-linked pricing the Japanese adopted, and which came to dominate the global LNG contractual landscape, was entirely appropriate, given that was replacing crude and products as a heating and generation fuel (as indeed was also the case in Europe’s long-term oil-indexed pipeline gas contracts).

South Korea and Taiwan later followed in starting LNG imports, in 1986 and 1991 respectively. Both countries had vertically integrated gas import and distribution monopolies, in Kogas and CPC, whereas Japan had regional utilities but much the same end-to-end structure. China was a much later adopter, but its enthusiasm for LNG has seen it become the global demand growth story of the ’10s.

Driven by growth in Asian imports and by the construction of new terminals in, particularly southern, Europe, LNG markets expanded through the ’80s with new producers joining the ranks: Libya, Brunei, Abu Dhabi, Trinidad and Tobago, Indonesia and Malaysia. Later, they were joined by Nigeria, Oman and Qatar.

The process of deregulation can be lengthy, and it is still ongoing in Japan. China, Korea and Taiwan have similar plans.

But, until the turn of the century, the market was still a relatively small pool of 11 importing and 12 exporting countries. Then China, Singapore, Thailand and even exporter Malaysia began ramping up imports of LNG. Post-2010, further markets opened up—in Latin America, Egypt (if temporarily), Jordan, Pakistan, Dubai and Africa.  

Japan was also Asia's first mover in pursuing a deregulation agenda, starting in 2016, and again there was an element of chance, or in this case serious misfortune, about the shift. The aftermath of the 2011 Fukushima disaster saw a major hike in electricity prices following closure of all nuclear power plants, on the back of LNG spot prices climbing as Japanese buyers had to access the market to service an unexpected large uptick in their import requirements. Price increases were passed onto consumers, causing widespread resentment and driving political will to break up monopoly structures in favour of competitive end-user markets.

The process of deregulation can be lengthy, and it is still ongoing in Japan. China, Korea and Taiwan have similar plans. Increasing competition and the potential impact for domestic prices lower than where they would have been in the old structures will be closely watched by other Asian countries. Increasing liberalisation of Asian receiving markets is likely to attract new entrants, competition and further development in the regional LNG market. 

LNG boom 

And its is the LNG market that is key to joining up the world’s regional gas markets into a truly global traded marketplace. The liquid form of the fuel in effect creates virtual pipelines, with the falling costs of the LNG logistics chain able to significantly tighten arbitrage between the US, European and Asian markets.

While governments have played a key role in creating the conditions for regional pipeline hubs, it is drivers such as supply, new and evolving actors and economics that will bring a global gas market to fruition.

20 exporting and 42 importing countries - Today's LNG market

Evidence of all three is growing. On the demand side, floating storage regasification units (FSRUs) have reduced the cost and lead-time of imports and opened new markets such as Bangladesh, Panama and Pakistan. Sri Lanka and Vietnam are likely the next new importers. Innovation in floating liquefaction units (FLNGs) are playing a similar role in bringing supply to market more quickly and cost effectively.

Rather than simply producer-seller and utility-buyer market actors, large aggregators, or portfolio players, with top credit ratings have plunged enthusiastically into the LNG emerged—disrupting project financing, contractual terms, particularly tenure and pricing, and pretty much every other aspects of the traditional value chain. Portfolio players build a supply book invest and longer-term contracts but are comfortable selling on shorter tenures and any hedgeable pricing basis.

It is perhaps telling that, among this cohort, one finds the majors Shell, Total, BP and the traditional heavyweights of oil trading, such as Vitol, Gunvor, Trafigura and Glencore. All are becoming ‘gas and oil’ companies and applying their oil trading skills to the LNG market.

Crucially, new supply from the US is arriving into the market, providing the volumes to lubricate liquidity. Like North Sea oil all those years ago, US supply is coming from a country with a commitment to competitive markets and with no destination restrictions. Indeed, the parallel is sufficiently striking to even beg the question whether a US Gulf Coast Fob marker could be the LNG’s markets Dated Brent—albeit that is complicated by its geographical proximity to the Henry Hub futures liquidity behemoth. 

Today, the LNG market comprises of 20 exporting and 42 importing countries. About a third of it is contracted on either spot or short-term basis, and that is a 2018 figure that may capture progress in the last 12 months. World liquefaction capacity is over 400mn t/yr, while the regasification capacity is more than double that volume. The most liquid LNG benchmark, the Japan Korea Marker (JKM) published by price reporting agency Platts, has grown by more than 250pc pa in each of two years since 2017. While oil and gas face different competitive pressures, there are clear similarities. Following the path of oil, a truly global gas markets is ready for take-off.

Adi Imsirovic, research associate, Oxford Institute of Energy Studies

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