4. Prices and market reforms

from 330 to 276 a year. Coal prices rose by over 40% y-o-y in 2017 and by almost 10% in 2018, to reach an average of USD 92/tonne in 2018 from USD 45/tonne in April 2016. Each of these factors (demand growth, oil indexation and inter-fuel competition) weighed in a different manner on natural gas prices in the distinct consuming regions. Whilst natural gas markets are becoming increasingly interlinked, regional price-setting dynamics retain their dominance.

Figure 4.1. Crude oil and natural gas monthly average prices, 2014–19

Sources: TTF, Henry Hub, Japan LNG contract and Brent data: Bloomberg Finance LP (2019), (subscription required); Asian LNG spot data: ICIS (2019), ICIS LNG Edge, www.icis.com/energy/liquefied-natural-gas/lng-edge (subscription required).

Global natural gas prices continued to recover in 2018, with y-o-y average growth varying between 6% and 38% depending on the region.

Asian LNG prices – from tight to loose

Asian LNG import prices remain heavily influenced by oil price dynamics. It is estimated that about 60% of Asian LNG import contracts include some form of oil indexation, most commonly linked to the price of the Japanese Customs-cleared Crude or “Japanese Crude Cocktail” (JCC). Figure 4.2 shows a very strong correlation (over 0.98) between the Japanese LNG contract price1 and the five-month average of JCC, indicating the persisting dominance of oil indexation.

Japan’s LNG import contract price continued its recovery in 2018 and rose by 25.5% y-o-y from an average of USD 8/MBtu in 2017 to USD 10.1/MBtu in 2018 (Figure 4.1). This has been driven by the increase in crude oil prices, with Brent strengthening by 30% and JCC by 32% y-o-y and filtering through the LNG import contract price with a lag of 4–6 months. Crude oil prices started to recover in mid-2017, as Brent prices rose from USD 46/barrel in June 2017 to USD 81/barrel in October 2018. This supported LNG import contract prices rising to almost USD 12/MBtu by December 2018, from an average of USD 10/MBtu through the summer.

As shown in Figure 4.1, the Asian LNG spot price – which is more reflective of short-term supply–demand dynamics – has been following a somewhat different trajectory. During the first quarter of 2018 it was trading at a premium compared to the average contract price. This was

from USD 6.6/MBtu in January to USD 8.6/MBtu in March. Natural gas prices on the TTF continued to increase through the second and third quarter of 2018, from a level of USD 7/MBtu in April to almost USD 10/MBtu in September.

A number of factors have been driving this counter seasonal price dynamic. The cold winter of 2017/18 emptied northwest European gas storage sites, with storage inventory at the end of the heating season being 10 billion cubic metres (bcm) (or 40%) below the five-year average. This in turn increased injection needs through the second and third quarters (accounting for approximately 30% of total northwest European demand during this period) and kept upward pressure on gas prices. This coincided with a relatively tight supply situation on the Asian gas markets, as discussed in the previous section. A third factor potentially strengthening gas prices in Europe, via fuel competition within the power sector, was the increase in Rotterdam coal prices, rising by 25% through the April–September period, from USD 80/tonne to USD 100/tonne.

During the 2018/19 heating season natural gas prices halved on the TTF, from almost USD 10/MBtu at the beginning of September 2018 to below USD 5/MBtu by March 2019. This has been partly driven by the above-average temperatures in Europe, putting downward pressure on natural gas consumption for space heating purposes, and the lower-than-expected LNG import demand in Asia and the relatively loose LNG market resulting from it. In European markets, natural gas prices falling below USD 5/MBtu combined with carbon prices holding above EUR 20 (Euros) per tonne of carbon dioxide equivalent have improved the competitiveness of natural gas vis-à-vis coal in the power sector (see Chapter 1).

This counter seasonal price pattern resulted in negative summer–winter spreads for the 2018/19 gas year, indicating that natural gas prices were higher during the injection season than in the heating season.

North America – stability and volatility

In the United States natural gas prices on the Henry Hub rose by 6.4% in 2018 to USD 3.16/MBtu, from an average USD 2.96/MBtu in 2017. This was driven by the record growth of 10% (or 80 bcm) in domestic natural gas consumption. Ample domestic supply, primarily from the Appalachian and the Permian basins, mitigated a stronger price response. Price volatility on the Henry Hub in 2018 was higher than the ten-year average by 12 percentage points (66% vs 54%). As shown in Figure 4.3, this volatility was driven primarily by the price spike in January 2018, when a cold snap drove up US natural gas consumption to its highest monthly level since at least 2001, whilst well freeze-offs3 reportedly limited gas production (EIA, 2018a).

Moreover, the January 2018 cold snap widened the locational spreads between Henry Hub and some of the balancing hubs, especially in the eastern markets. While Henry Hub remained at price levels around USD 3–6/MBtu, eastern markets reached price levels of USD 80/MBtu near Boston (Algonquin) and USD 140/MBtu near New York City.

Locational spreads re-emerged in the United States on several occasions during 2018. The Sumas Hub, located in the northwest of the United States on the border with Canada, has been suffering from high price volatility since October 2018, when a rupture occurred in Enbridge’s

British Columbia natural gas pipeline (EIA, 2018b). Import flows from Canada during November 2018–February 2019 were about one-third lower compared to last year, putting further pressure on natural gas prices on the Sumas Hub during this period, rising to USD 10.56/MBtu versus USD 2.62/MBtu a year earlier.

Figure 4.3. Henry Hub monthly price volatility, 1997–2019

400%

300%

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The January 2018 cold snap drove up Henry Hub price volatility to levels not seen since the polar vortex that hit the United States in January 2003.

On the other side of the border, natural gas prices on Alberta’s AECO Hub plummeted by 30% y-o-y from an average USD 1.66 in 2017 to USD 1.17 in 2018 – their lowest level since at least the beginning of this century.

In contrast with the premium in the northwest United States, natural gas has been trading at a discount to Henry Hub on the Waha Hub located in the Permian basin, with the price differential averaging USD 1.13/MBtu during 2018. Natural gas production in the Permian has risen almost eightfold in the last 8 years, from 10 bcm in 2010 to 75 bcm in 2018, mainly on the back of tight oil production in the form of associated petroleum gas. The lack of sufficient midstream takeaway capacity (including processing plants and transmission pipelines)4 has depressed natural gas prices over the last couple of years, with the average yearly Waha discount widening from USD 0.03/MBtu in 2014 to last year’s USD 1.13/MBtu. As shown in Figure 4.4, natural gas prices on the Waha Hub plunged into negative territory in late March 2019, reaching a record low of USD -4.63/MBtu in early April.

The strong region-dependent spreads in North America point towards pipeline capacity constraints in connecting supply regions with demand centres.