Gas pricing and market reform

FEEDSTOCK

Gas pricing and market reform

Natural gas pricing remains the dominant component of ammonia production costs. The fall in global oil and gas prices due to the Covid outbreak and the continued growth in the LNG market is continuing to break the hold of oil indexation on gas pricing. Meanwhile, reform of gas markets continues, in places as diverse as Brazil, China and India.

Qatargas’ Mozah LNG tanker, the largest LNG carrier in the world.

PHOTO: EXXONMOBIL

Syngas-based industries, dominated by ammonia, methanol, and to a lesser extent hydrogen, are highly dependent upon feedstock costs. Since the 1960s, and aside from China’s large scale adoption of coal gasification, that feedstock has predominantly been natural gas. While China’s coal-based industry has tended to be towards the top of the cost curve, and its large scale production has made it a price setter, global markets for natural gas are key determinants of the profitability of ammonia and methanol production worldwide.

The switch to the use of gas for chemical production happened at a time when most power generation was based upon burning coal, and gas, often a by-product of oil drilling that might otherwise be wastefully flared, was cheap at source but difficult to transport in the absence of expensive long-distance pipelines. This made the economics of gas-based ammonia/urea and methanol production highly persuasive – the urea or methanol was far easier to transport than the gas, and so an export-based industry grew where ‘stranded’ gas was available, such as in Trinidad, the Middle East, and Central or Southeast Asia.

The gas market has however changed beyond recognition since those times. Global pipeline networks have continued to grow on land, while the spread of liquefied natural gas (LNG) liquefaction and regasification terminals and associated shipping have turned gas into a global rather than regional commodity. Gas market pricing has evolved, via gas trading hubs which now set prices internationally. Elsewhere, old fields have depleted, while the development of horizontal drilling and hydraulic fracturing technologies have opened up new gas deposits in mature markets such as the US which were previously thought to be unrecoverable at any reasonable cost.

Gas pricing mechanisms have sometimes been slow to catch up with these new realities in some regions, where prices remain indexed to the cost of oil production, or where national governments have often continued to control gas pricing. But gas market reform continues to work its way through markets all around the world.

Market turmoil

The past few years have been a turbulent time in global gas markets. Figure 1 shows LNG spot pricing in Japan. Japanese prices had been running high in the wake of the Fukushima nuclear disaster and a major switch from nuclear to gas-based electricity generation. However, LNG prices fell as the Chinese economy slowed, but there was a rebound in 2017-2018 as China made a large scale move away from coal-fired power generation towards natural gas and LNG imports began to increase.

The US and China have been the main drivers of global gas demand growth, accounting for around2 /3 of all incremental demand. Gas’ penetration of the US power market has now reached 38%, and use rose 8% in 2019. European consumption increased by 11%. But at the same time, Japan began restarting its nuclear facilities in 2019 and gas demand fell there by 12%. Overall, global gas consumption grew by an estimated 70 bcm in 2019, or 1.8%, which is roughly in line with the average growth rate experienced over the period 2010-17.

At the same time, supply has been increasing rapidly, outpacing demand. US shale gas production was the major culprit. Production growth, at 3% globally, outpaced demand, driven by US shale expansion – US production increases represented 70% of incremental supply in 2019, leading to a large build-up of gas in storage. Russian gas production was boosted by the Yamal LNG project, and China has been increasing production via coalbed methane and shale gas output. Increases in global LNG supply, especially from the United States, where the shale gas boom had led to supply exceeding domestic demand, and also Australia, pushed prices downwards in 2019, as Figure 1 shows. LNG trade increased by 12% in 2019.

Covid

The coronavirus outbreak happened in a market that was already oversupplied, with catastrophic results. Global GDP fell by an estimated 2.8% last year. Industrial consumption of natural gas fell sharply in Europe, while in the US a fall in gas consumption caused by a milder winter was balanced by the cheap prevailing prices and a consequent continuing shift to gas-fired power generation. Overall, however, the gas market has seen a major demand shock, and the International Energy Agency forecasts that the demand contraction in mature markets in Europe, North America, Eurasia and Asia may lead to a 4% year on year decline in global gas demand.

Production has fallen – Russian production contracted by 9% in the first half of 2020 as it was not able to export as much gas by pipeline to Europe. However, LNG supply continued to increase, with added demand in China and India. Meanwhile, LNG demand began to spike at the end of 2020, with a combination of factors responsible, from recovering demand, especially in China, a lack of shipping, delays in the Panama Canal, and production issues in Australia and Malaysia. This drove the run-up in prices at the end of 2020 which can be seen in Figure 1.

Fig. 1: Japanese delivered LNG spot price, monthly average, $/MMBtu

LNG

The continuing growth of the global LNG market has transformed and is continuing to transform the way that the world uses natural gas. Production and consumption of liquefied natural gas reached 485 bcm in 2019, representing 12% of the global gas market, and 38% of internationally traded gas. LNG trade has virtually doubled over the past decade, and growth continues – the higher gas prices of 2017-18 encouraged another wave of new investment decisions, which totalled 120 bcm/ year of nameplate capacity in 2018-19. There were a record number of decisions to proceed with new LNG projects in 2019, including Sabine Pass LNG train 6, Golden Pass LNG trains 1–3 and Calcasieu Pass (all in the US), Mozambique LNG trains 1 and 2, Arctic LNG 2 in Russia and Nigeria LNG train 7.

LNG was in oversupply in 2020, exacerbated by the fall in demand due to Covid19, and is set to be in oversupply in 2021 as well. A sustained period of lower oil prices and increased competition among gas supply sources as new supply reaches the market have combined to erode margins, putting pressure on gas and LNG producers.

At the same time, this pressure is helping to change the LNG market. In its early days, the huge costs of liquefaction and regasification terminals meant that LNG tended to be supplied on long-term, oil-indexed contracts. But the growth in the quantity of LNG being shipped, the greater spread in the number of countries both supplying and able to receive LNG, and its move away from oil-associated gas as a source of supply encouraged a gradual move away from long term fixed price contracts, albeit still indexed to oil. But the oil market has major players working in concert to restrict supply at times of low prices, especially via OPEC. While there has been an attempt to produce a similar body for the gas market – the Gas Exporting Countries Forum (GECF), it has not been able to enforce supply cutbacks, and of course does not include some of the largest suppliers such as the US and Australia. So now, the relatively high price for oil and widespread availability of LNG is leading to a decoupling in LNG prices from oil, in a similar way that happened to gas pipeline contracts in Europe and elsewhere. Spot LNG cargoes are being offered at discounts of up to 50-70% of the prevailing price of oil, and the cheapness of LNG is helping to incentivise consumers, especially large scale industrial consumers, to switch to gas. Likewise, while from 2000-18 LNG averaged more than three times its coal price equivalent, it is now at rough parity, again encouraging switching by power generators. Gas is also able to compete on carbon intensity and other pollutants compared to competing fossil fuels, important in a gradually decarbonising world.

LNG’s greatest potential remains in Asia, where coal still meets 47% of energy consumption, particularly in China and India. China is now moving steadily but decisively away from coal use. McKinsey reckons that if gas increased its share of primary energy consumption in Asia from just 12% to 20%, this would require up to 400 million t/a of LNG demand, doubling the size of the LNG market from what it is at present.

Gas pricing

Natural gas is priced in different ways. The International Gas Union, in its annual survey of wholesale gas price fixing mechanisms, distinguishes between: ‘GOG’ – gas-on-gas competition – where there are multiple producers selling into a price unregulated market via trading hubs; OPE – oil price escalation – where the price of gas contracts is tied to oil prices by an escalation factor; and various forms of regulated prices: regulated cost of service (RCS), where a company is allowed to make back costs plus a fixed increment; regulated social and political (RSP) and regulated below cost (RBC), where a company, usually state-owned, sells gas below the cost of delivery for political or other reasons.

Fig. 2: Make-up of gas pricing contracts, major markets

Figure 2 shows the balance between these types of price mechanism for all gas consumed in various regional markets.

Figure 2 shows that North America essentially functions as a pure gas-on-gas market, having deregulated its gas markets during the 1990s. So does most of Europe, where gas deregulation began in the UK in the 1990s and has gradually spread to the rest of the continent. Over the period 2005-2019, most of Russia’s pipeline exports into Europe also moved from OPE to GOG pricing, and the remaining OPE slice shown in Europe for Figure 2 comes from imports of LNG. Conversely, Asia and the Pacific remain strongly based around oil price-linked gas, again due to the prevalence of LNG in these markets. Latin America is a patchwork of pricing mechanisms, while the FSU is moving to gas on gas competition from a regulated cost of service system. The Middle East and Africa still rely upon government-set pricing mechanisms however.

Major developments over the past 15 years have included:

• The move away from regulated pricing in the Russian market to gas on gas competition as independent producers have begun to compete with each other and Gazprom to sell gas to the power sector and large industrial consumers.
• Similar deregulation has occurred in Argentina, and more recently Nigeria.
• From 2013, China has begun to move away from regulated cost of service (RCS) to oil price escalation, initially in two provinces but gradually nationwide, most recently extending into the residential sector via city gate pricing. Some of this OPE pricing has moved to GOG. The main remaining regulated gas market in China is for fertilizer production.
• India also began price reforms in 2014, gradually moving from regulated (social/political) to GOG pricing.
• There has been a rise in new LNG importers, importing at OPE and/or GOG, which is replacing domestic production operating at regulated prices.
• As noted above, there are signs that the link between oil and gas pricing is slowly being broken in the LNG market. Around 40% of LNG is traded via GOG rather than OPE pricing, and with the discounts that were being operating on OPE prices last year some of that was in effect partially GOG.

While Europe and North America both now have mature gas trading hubs, there is still no real equivalent in Asia. As 90% of traded gas in Asia is shipped as LNG, the most logical hub would be one that could see both import and re-export of significant LNG volumes. But the preponderance of LNG demand in east Asia as opposed to other regions still distorts the LNG market and prevents it from becoming a truly global market; there are still significant regional variations in delivered LNG prices.

The future for gas

Most of the gas demand lost in 2020 is expected to be recovered this year, in mature markets such as Europe, Eurasia and North America, as demand from industrial and power generation sectors gradually returns. Some marginal gains are also expected from coal-to-gas switching, helped by low gas prices and continuing abundant supply. Additional demand growth over the next five years will come from faster-growing markets in the Asia-Pacific region (and to a lesser extent the Middle East). The Asia Pacific region accounts for over half of projected new incremental consumption from 2022-25, led by China and India. Additional demand in the Middle East (about a quarter of the total increase) is primarily driven by large gas-producing markets such as Saudi Arabia and Iran.

As well as power production, industrial uses are expected to drive this consumption increase, with around 40% of new gas demand coming from industry, and much of this industrial demand will come from fertilizer and methanol production. New ammonia and methanol production is expected to lead to 3.4% year on year growth in industrial consumption of gas. India of course represents a large slice of this with its import replacement programme. The US meanwhile is leading growth in methanol, via export-oriented projects such as Northwest Innovation in Washington State. Globally, use as methanol feedstock represents over 30% of the growth in the industrial gas demand sector.

China will add the most new demand for gas, with a projected demand increase of 60 bcm/year total over the period 201925, as power generators and industrial consumers are encouraged to move from coal to gas, and some vehicles are converted to run on natural gas. While China is making large investments in shale and other unconventional gas production, this will also necessitate much greater import of LNG. This will be good news for the US shale gas industry, hit hard by the run of low gas prices last year. New gas supply is expected from the US, Russia and especially the Middle East, the latter region adding 120 bcm/year of extra supply from 2019-25.