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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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Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.
The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can.
This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.
The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.
The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis.
Current OPEC membership:
U.S. crude oil production in the U.S. Federal Gulf of Mexico (GOM) averaged 1.8 million barrels per day (b/d) in 2018, setting a new annual record. The U.S. Energy Information Administration (EIA) expects oil production in the GOM to set new production records in 2019 and in 2020, even after accounting for shut-ins related to Hurricane Barry in July 2019 and including forecasted adjustments for hurricane-related shut-ins for the remainder of 2019 and for 2020.
Based on EIA’s latest Short-Term Energy Outlook’s (STEO) expected production levels at new and existing fields, annual crude oil production in the GOM will increase to an average of 1.9 million b/d in 2019 and 2.0 million b/d in 2020. However, even with this level of growth, projected GOM crude oil production will account for a smaller share of the U.S. total. EIA expects the GOM to account for 15% of total U.S. crude oil production in 2019 and in 2020, compared with 23% of total U.S. crude oil production in 2011, as onshore production growth continues to outpace offshore production growth.
In 2019, crude oil production in the GOM fell from 1.9 million b/d in June to 1.6 million b/d in July because some production platforms were evacuated in anticipation of Hurricane Barry. This disruption was resolved relatively quickly, and no disruptions caused by Hurricane Barry remain. Although final data are not yet available, EIA estimates GOM crude oil production reached 2.0 million b/d in August 2019.
Producers expect eight new projects to come online in 2019 and four more in 2020. EIA expects these projects to contribute about 44,000 b/d in 2019 and about 190,000 b/d in 2020 as projects ramp up production. Uncertainties in oil markets affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly.
Source: Rystad Energy
Because of the amount of time needed to discover and develop large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than onshore production in the Lower 48 states. In 2015 and early 2016, decreasing profit margins and reduced expectations for a quick oil price recovery prompted many GOM operators to reconsider future exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2018.
Source: U.S. Energy Information Administration, Thompson Reuters, Baker Hughes
Crude oil price increases in 2017 and 2018 relative to lows in 2015 and 2016 have not yet had a significant effect on operations in the GOM, but they have the potential to contribute to increasing rig counts and field discoveries in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead they affect the discovery of future fields and the start-up of new projects.
Source: U.S. Energy Information Administration, Monthly Refinery Report
The API gravity of crude oil input to U.S. refineries has generally increased, or gotten lighter, since 2011 because of changes in domestic production and imports. Regionally, refinery crude slates—or the mix of crude oil grades that a refinery is processing—have become lighter in the East Coast, Gulf Coast, and West Coast regions, and they have become slightly heavier in the Midwest and Rocky Mountain regions.
API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, so light oils have high API gravities. Crude oil with an API gravity greater than 38 degrees is generally considered light crude oil; crude oil with an API gravity of 22 degrees or below is considered heavy crude oil.
The crude slate processed in refineries situated along the Gulf Coast—the region with the most refining capacity in the United States—has had the largest increase in API gravity, increasing from an average of 30.0 degrees in 2011 to an average of 32.6 degrees in 2018. The West Coast had the heaviest crude slate in 2018 at 28.2 degrees, and the East Coast had the lightest of the three regions at 34.8 degrees.
Production of increasingly lighter crude oil in the United States has contributed to the overall lightening of the crude oil slate for U.S. refiners. The fastest-growing category of domestic production has been crude oil with an API gravity greater than 40 degrees, according to data in the U.S. Energy Information Administration’s (EIA) Monthly Crude Oil and Natural Gas Production Report.
Since 2015, when EIA began collecting crude oil production data by API gravity, light crude oil production in the Lower 48 states has grown from an annual average of 4.6 million barrels per day (b/d) to 6.4 million b/d in the first seven months of 2019.
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production Report
When setting crude oil slates, refiners consider logistical constraints and the cost of transportation, as well as their unique refinery configuration. For example, nearly all (more than 99% in 2018) crude oil imports to the Midwest and the Rocky Mountain regions come from Canada because of geographic proximity and existing pipeline and rail infrastructure between these regions.
Crude oil imports from Canada, which consist of mostly heavy crude oil, have increased by 67% since 2011 because of increased Canadian production. Crude oil imports from Canada have accounted for a greater share of refinery inputs in the Midwest and Rocky Mountain regions, leading to heavier refinery crude slates in these regions.
By comparison, crude oil production in Texas tends to be lighter: Texas accounted for half of crude oil production above 40 degrees API in the United States in 2018. The share of domestic crude oil in the Gulf Coast refinery crude oil slate increased from 36% in 2011 to 70% in 2018. As a result, the change in the average API gravity of crude oil processed in refineries in the Gulf Coast region was the largest increase among all regions in the United States during that period.
Source: U.S. Energy Information Administration, Monthly Imports Report and Monthly Refinery Report
East Coast refineries have three ways to receive crude oil shipments, depending on which are more economical: by rail from the Midwest, by coastwise-compliant (Jones Act) tankers from the Gulf Coast, or by importing. From 2011 to 2018, the share of imported crude oil in the East Coast region decreased from 95% to 81% as the share of domestic crude oil inputs increased. Conversely, the share of imported crude oil at West Coast refineries increased from 46% in 2011 to 51% in 2018.