Rapid change is the only constant in the LNG Market

By Colin Cooper | 23 June 2017

Qatar has been the world’s largest exporter of LNG for almost a decade and has been the primary supplier to many Asian consumers, including most of the Japanese utilities. Currently accounting for about 38% of global LNG exports, Qatar has been able to develop its LNG industry by being a prolific and reliable supplier - and buyers have been willing to pay-up via long-term oil-indexed purchase agreements in order to ensure those critical supplies are available.

While a nascent spot market has been growing slowly over the last five years, these long-term agreements with Qatar and other producers usually include prohibitions on reselling or redirecting cargos, and have been a significant barrier in the development of a robust trade in spot cargos. With less than 20% of the global LNG volumes being traded via short-term and spot contracts (where prices have occasionally fallen below $7/mmBtu for gas delivered to the Japanese and surrounding markets), these older oil indexed agreements, which can run 10-50% higher than spot prices (the higher the oil price, the higher the premium percentage), have been a windfall at times for LNG exporters.  Given this price disparity, and despite the relatively low volumes available now, the spot markets are attracting more interest from buyers.

Though these 20-25 year long-term agreements have provided supply surety, Japanese utilities (which consume about 34% of world’s supply of LNG) have, within the last few years, begun to push back on extending agreements nearing expiration and have been successful in negotiating shorter terms of five to 10 years. Now with the news that Qatar has been commercially and politically isolated by its Arab neighbors (including Saudi Arabia, the UAE and Egypt among others) over what those countries believe is Qatar’s continuing support for radical elements, Japan has gained a stronger hand in negotiating new terms for their latest tranche of expiring contracts. Having been locked into agreements that have prevented them from redirecting or reselling cargos, these Japanese companies could push for less restrictions and/or pricing tied to the emerging Pacific spot indexes instead of oil indexes.

In a worst-case scenario for the Qataris, the utilities may even choose not to extend those expiring contracts, opting instead to purchase gas from other suppliers under shorter-term agreements or in the spot market. A decade ago there were few other economic supply options outside of Qatar, but now with new LNG export facilities on-line in Australia and the US, and several additional plants under construction, the world is increasingly awash with LNG.  Faced with new competitors and higher costs under Arab sanctions, Qatar could find themselves increasingly out of the market.

Should Japan decide to move away from the relative surety of long and intermediate-term agreements, Qatar could find it difficult to replace that lost market share given their increasing isolation in the region. Though the total volume under the expiring term agreements is a closely held secret, based on the total volume of Japanese purchases, it can be assumed that several BCFD of gas could be up for grabs in the spot market in the next 12 to 24 months - gas that could ultimately be supplied in part or whole from US facilities.  

US LNG and the global spot markets

US LNG facilities currently operating and forecast to come on-line by the end of 2018, including Chenier’s rapidly expanding Sabine Pass, Dominion’s Point Cove, Sempra’s Cameron, and Freeport LNG are expected to produce more than 6 BCFD equivalent LNG. Though 80-90% of that capacity is contracted under firm purchase agreements to trading companies and utilities and industrials in the Asia-Pac region, those volumes generally do not come with destination restrictions and can be - and often are - resold into the growing spot markets.  Given that there has been concern that some portion of the new supply that’s coming on-line wouldn’t be taken under the firm purchase agreements (with the buyers opting instead to pay a penalty under their take-or-pay agreements), should the Japanese choose to buy their gas in the open market, any incremental increase in spot demand could be a win for US LNG exporters and the gas producers that supply them. 

Though US gas is geographically disadvantaged in the Pacific markets when compared to Middle Eastern, Australian, and Asian suppliers, the recent completion of the Panama Canal widening project has reduced shipping times to the region and has helped to make US LNG more competitive. While still faced with longer transit times and higher shipping costs than most other LNG suppliers, US producers currently hold some advantage in that the natural gas for LNG production is priced against Henry Hub and is supplied (either directly or by offset) from across North America. Almost all other LNG producers are tied to specific and isolated fields and basins, many offshore, with higher operating costs and less liquid pricing mechanisms. Of course, the question is will that US upstream supply price advantage last in the face of increasing demand for Gulf Coast LNG?

The price at the Hub have been hovering around $3/mmBtu for the last eight months or so, a level that has encouraged US producers to increase drilling activity. The US natural gas rig count is on the rise (currently at 185 – double what it was mid-year 2016, though still well below the record of 1800 rigs in 2008) and production is once again increasing after dipping last year.  With production now at over 70 BCFD and storage injection levels running below last year’s pace, the gas market appears to be close to supply/demand equilibrium for now. 

Should the Qataris lose three to four BCFD of oil-indexed Japanese business to the spot market, LNG prices in the Asia-Pac spot market should increase (driven by increased demand), and in turn increase demand for US Gulf Coast LNG. Of course, even should another three to four BCFD in export demand materialize on the Gulf Coast, given the wealth of shale gas available for exploitation and the long lead-times for development of new LNG facilities, US gas producers should be able to match increased demand in relatively short order through drilling. But, as less accessible/higher cost supplies will need to be developed, some level of price increase will be inevitable and short-term price spikes will likely occur, particularly in the winter months. Still, even faced with increased volatility, producers that have struggled with sub $2 gas in the not too distant past would likely welcome continuation of $3 plus natural gas that is supported by increased demand from LNG exports.    

US Gas and LNG producers are facing new risks

Even with the latest developments, there are just too many variables to forecast any outcome. Will the Japanese break with the Qataris and move those volumes the spot market?  Will the Qataris be able to negotiate their way out of the Arab sanctions? If not, what will be the impact of higher costs on the Qataris? Will they ultimately lose market share to the advantage of US producers?

The confluence of current events - including developments in the Middle East, changing Japanese buying strategies and the ongoing development of the Asia-Pac spot market - all reinforce the point that there is no certainty or clarity in how this market will develop and mature. US LNG exporters, and the natural gas providers and traders that supply them, are all increasingly exposed to any number of geopolitical developments and risks, and increased uncertainty and price volatility are likely.   

Natural gas producers, traders, and LNG producers need software systems that will help them identify opportunity, limit downside exposures and improve margins from the wellhead to the LNG off-loading arm. 

Any software platform used to manage LNG should be able to:

a) Handle both natural gas and liquids, as well as NGLs

b) Support NGLs and the mid-stream of NGL deals, including processing and fractionation

c) Control the entire LNG lifecycle from liquefaction to regasification

d) Model the input, output, costs, and losses of both liquefaction and regasification

e) Manage all components of the storage and transportation contracts

f) Analyse positions and exposures including mark-to-market valuation, value at risk (VaR), backtesting, stress testing, and P&L

g) Track all transaction data to manage FX exposures

h) Support spread trades such as calendar spreads or time spreads

A single, integrated system that efficiently manages the physical movement of product and all the details required to track LNG in real-time provides the critical business intelligence and analysis information to make optimal decisions around trade execution, position management, and scheduling. Using Eka’s Smart Commodity Management solutions to manage the entirety of the natural gas lifecycle enables participants across all aspects of the LNG value chain to mitigate the effects of market volatility and succeed in an increasingly competitive, and uncertain, market.

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