The dynamics of the LNG market are changing fast.There is more and more spot and short term trading, new players in theform of trading houses are coming to the market, new price benchmarks are beingintroduced and new financial instruments like futures and swaps becomeavailable for managing the price risks.
The current market is in a state of oversupply, asthere is a rising supply coming onto world markets from new exportingfacilities mainly from the U.S. and Australia. As the demand in Asia,good for 70% of the global LNG demand, has failed to keep up with the risingsupply, LNG prices have sunk to a seven-year low in that geography.
The average spot price in Asia for LNG for delivery inMay dropped by 42.5% year-over-year to $4.241 per million British thermalunits, the lowest monthly average since July 2009, according to price reportingagency Platts.
The result of this cocktail of excess supply and lowmarket prices is that the main buyers from leading importing countries likeJapan and Korea move away from a single reliance on long term oil indexedcontracts to a much more flexible procurement portfolio also including shortterm and spot contracts. Already, sales of LNG on the spot market and viashort-term contracts lasting less than four years had risen to app. 30% oftrade in 2015 from 5.4% in 2000, and are likely to grow further. Pricereporting agencies claim that there are daily bids and offers for physical LNGcargoes.
This move away from long term contracts is bad newsfor the producers who have invested billions into LNG plants and now seethat today’s LNG prices are insufficient to guarantee a proper return on theirinvestments. Still the major producers have been reluctant to cut output forfear of losing their market share, even if that means selling their products ata discount. Companies also cannot afford to curtail production atfacilities now coming on stream that have taken years and billions of dollarsof investment to start up.
Buyers are understandably more cost conscious and expectingthe price of LNG to reflect more adequately what is going on in themarketplace. For instance the worlds’ biggest buyer, Japanese JERA, now plansto buy LNG using contracts of varying length, and move away from using oil as apricing reference.
LNG buyers should go for a mix of different types ofpricing formulas in order to cover the various possibilities for the evolutionof the gas price and the oil price.
The main pricing benchmark so far in Asia is theso-called “Japan Crude Cocktail” (JCC) that represents the average pricefor crude oil imports into Japan. The JCC index is used as a reference priceindex for long-term LNG contracts in Northeast Asia. As LNG prices declinedalong with crude oil prices in 2015, the JCC-indexed prices started to divergemarkedly from prices of physical LNG delivered into Japan.
The last few years more LNG spot contracts havestarted to be priced off spot indexes. An estimated 40% of the spot andshort-term contracts are currently priced off the Platts JKM index. Efforts areunderway to develop alternative benchmarks to complement the Platts JKM.Recently the SGX, the Singapore Exchange launched the SLInG index and in Japanthey have launched the RIM Index. Both countries done this to support theirgoal of becoming the regional or global LNG Trading Hub. These indices are alsobenchmarks for LNG futures contracts that could be used for a hedge of spot LNGcontracts. Although these financial contracts are hardly traded by theindustry so far.
The US Henry Hub index is likely to become animportant pricing benchmark for LNG term contracts in Asia, as it isincreasingly being used by the US LNG exporters for deliveries into Japan andSouth Korea. The Henry Hub index is an existing benchmark for the US naturalgas market and also the underlying benchmark for the highly liquid natural gasfutures contract traded on the NYMEX.
For the success of a futures contract the mainrequirements are a well-functioning underling cash market and enough potentialbuyers and sellers to create enough liquidity. Due to the fast growth of spotand short term trading based on one of the spot benchmarks, more and moremarket players are facing an exposure to LNG market prices and for the JCC tothe Brent oil prices that they would like to hedge away, if needed. Looking atthe players in the market there is a good diversity between those who have longand short term exposures to the LNG market. Among the players whohave physical positions that need to be hedged, the “Shorts” are typically theJapanese, South Korean and Taiwanese power and gas companies, and the “Longs”are typically project and infrastructure developers. Banks, trading houses likeGunvor, Vitol, Trafigura, Mercuria, etc. , financiers and LNG ship owners alsohave financial exposures to LNG prices.
The Brent and Henry Hub Natural gas futures arehighly liquid and could therefore be used as a solid hedging instrument. Forthe futures based on the recently launched Asian spot indices the liquidity isstill very poor, although it is still early days, so these should be approachedwith a lot of caution.
It is certainly recommendable to inform and educateyour people about the use of financial instruments as part of your riskmanagement strategy. It would be my pleasure to share my unique expertise withyou and your people.
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Headline crude prices for the week beginning 11 February 2019 – Brent: US$61/b; WTI: US$52/b
Headlines of the week
Midstream & Downstream
Global liquid fuels
Electricity, coal, renewables, and emissions
2018 was a year that started with crude prices at US$62/b and ended at US$46/b. In between those two points, prices had gently risen up to peak of US$80/b as the oil world worried about the impact of new American sanctions on Iran in September before crashing down in the last two months on a rising tide of American production. What did that mean for the financial health of the industry over the last quarter and last year?
Nothing negative, it appears. With the last of the financial results from supermajors released, the world’s largest oil firms reported strong profits for Q418 and blockbuster profits for the full year 2018. Despite the blip in prices, the efforts of the supermajors – along with the rest of the industry – to keep costs in check after being burnt by the 2015 crash has paid off.
ExxonMobil, for example, may have missed analyst expectations for 4Q18 revenue at US$71.9 billion, but reported a better-than-expected net profit of US$6 billion. The latter was down 28% y-o-y, but the Q417 figure included a one-off benefit related to then-implemented US tax reform. Full year net profit was even better – up 5.7% to US$20.8 billion as upstream production rose to 4.01 mmboe/d – allowing ExxonMobil to come close to reclaiming its title of the world’s most profitable oil company.
But for now, that title is still held by Shell, which managed to eclipse ExxonMobil with full year net profits of US$21.4 billion. That’s the best annual results for the Anglo-Dutch firm since 2014; product of the deep and painful cost-cutting measures implemented after. Shell’s gamble in purchasing the BG Group for US$53 billion – which sparked a spat of asset sales to pare down debt – has paid off, with contributions from LNG trading named as a strong contributor to financial performance. Shell’s upstream output for 2018 came in at 3.78 mmb/d and the company is also looking to follow in the footsteps of ExxonMobil, Chevron and BP in the Permian, where it admits its footprint is currently ‘a bit small’.
Shell’s fellow British firm BP also reported its highest profits since 2014, doubling its net profits for the full year 2018 on a 65% jump in 4Q18 profits. It completes a long recovery for the firm, which has struggled since the Deepwater Horizon disaster in 2010, allowing it to focus on the future – specifically US shale through the recent US$10.5 billion purchase of BHP’s Permian assets. Chevron, too, is focusing on onshore shale, as surging Permian output drove full year net profit up by 60.8% and 4Q18 net profit up by 19.9%. Chevron is also increasingly focusing on vertical integration again – to capture the full value of surging Texas crude by expanding its refining facilities in Texas, just as ExxonMobil is doing in Beaumont. French major Total’s figures may have been less impressive in percentage terms – but that it is coming from a higher 2017 base, when it outperformed its bigger supermajor cousins.
So, despite the year ending with crude prices in the doldrums, 2018 seems to be proof of Big Oil’s ability to better weather price downturns after years of discipline. Some of the control is loosening – major upstream investments have either been sanctioned or planned since 2018 – but there is still enough restraint left over to keep the oil industry in the black when trends turn sour.
Supermajor Net Profits for 4Q18 and 2018
- 4Q18 – Net profit US$6 billion (-28%);
- 2018 – Net profit US$20.8 (+5.7%)
- 4Q18 – Net profit US$5.69 billion (+32.3%);
- 2018 – Net profit US$21.4 billion (+36%)
- 4Q18 – Net profit US$3.73 billion (+19.9%);
- 2018 – Net profit US$14.8 billion (+60.8%)
- 4Q18 – Net profit US$3.48 billion (+65%);
- 2018 - Net profit US$12.7 billion (+105%)
- 4Q18 – Net profit US$3.88 billion (+16%);
- 2018 - Net profit US$13.6 billion (+28%)