The shifting LNG market

This article was originally published in LNG Industry. It was written by Richard Howley, Penny Cygan-Jones and Jack Longden.

LNG spot prices in Asia have risen from a low of US$4.241 in May to US$6.60/million Btu as winter approaches, a shadow of the US$20/million Btu that were being realised in 2012 - 2013. The price increase was also driven by increased demand from South Korea, which saw four nuclear units put offline following earthquakes in mid-September, depriving it of 22 GW of network capacity. India also proved to be an active market throughout September as LNG became an attractive alternative to competing fuel supplies due to depressed prices and ready market availability.

The momentum of the AUS$200 billion LNG construction boom in Australia, coinciding with increased supply from Qatar and North America, continues to subdue prices across the market. At the same time, the industry has seen higher than forecast project costs and cost overruns. Other projects, such as the US$40 billion Woodside Browse project, a partnership including Royal Dutch Shell, BP and a joint venture (JV) between Mitsubishi and Mitsui, have been halted indefinitely amidst concerns of feasibility. Unsurprisingly, there are no new greenfield sites in Australia that are scheduled to be approved in the next few years.¹

With increasing pressure on large scale LNG plants to prove returns to investors, the market is increasingly backing smaller scale LNG initiatives. The technology to allow LNG providers to offer a variety of ‘plug and play’ products is now proven thanks to early adoption, and offers commercial opportunities with decreased commissioning times in bunkering, distribution by lorry and rail, and small scale distribution and redeployment. These technologies allow for scalable supplies that are better suited to respond to short term fluctuations in demand, including demand originating from areas of the market that were previously unsuited to LNG as a fuel source. The interior of Alaska and the islands of Indonesia are two examples discussed in greater detail within this article.

In addition, tighter regulation on emissions within the EU, both atmospheric and marine (where bunker fuel will be required to have a sulfur content of 0.5% or lower from 1 January 2020), continues to encourage growth in small scale LNG projects across the continent, from reloading services (Grain LNG, UK) to bunkering initiatives (Port of Rotterdam Harbour Basin and Zeebrugge) to multi-modal LNG reload terminals and truck loading (Enagas, Spain). Opportunities for small scale LNG in transport are also increasingly being realised, with the first LNG-fuelled bus in India being launched at Petronet’s Kochi LNG import terminal. This project, involving Petronet LNG, India Oil Corp. and Tata Motors Ltd, demonstrates the market interest in LNG alternatives.

Engie, Mitsubishi Corp. and NYK Line have also recently launched Gas4Sea, a bunkering initiative that combines leading industry experience in LNG supply with shipping expertise to offer a ship-to-ship (STS) refuelling platform. The purpose built bunkering vessel is the first of its kind, offering 5000 m3 of LNG capacity, which is scheduled to become operational in 4Q16.

Where large scale LNG investment is occurring, the market has seen an increasing preference for floating terminals over land-based options. Floating terminals offer lower associated long-term risk, with scalable capacities through the addition of extra floating storage units (FSUs). This also realises efficiencies in existing LNG infrastructure by recovering additional value from older LNG carriers, which can be readily adapted for storage purposes. Advancements in LNG connector technology has also facilitated a number of flexible mooring options that can withstand rougher sea conditions with easier, intelligent, connection points. This dramatically increases the ease of access to LNG by removing the need for established docking facilities, reducing costs and improving safety across the industry.

Recent developments in the LNG market reflect the Einsteinian theory that “In the middle of difficulty lies opportunity.” A number of key industry and broader geopolitical headlines that emphasise this current dynamic are outlined below.

The Chief Financial Officer (CFO) of Shell, Simon Henry, announced in early November 2016 that he believed “oil demand will peak before supply and that peak may be between five and 15 years from hence.”² Oil demand in Europe has decreased by 17% over the past decade, largely as a result of a widespread move towards renewables and clean energy. Demand in China has also flattened over recent months due to a slowdown in industry. Henry’s prediction highlights the increasing role that LNG could play in meeting future energy demand worldwide. With dwindling support for coal and oil, gas is the cleanest alternative to fuel the baseload generation required to support networks increasingly powered by renewables, without the associated risks or costs of nuclear.

The Fair Trade Commission of Japan has recently launched an investigation into whether re-sale restrictions in so called ‘destination clauses’ in LNG contracts (contractual provisions limiting the right of the buyer to sell contracted cargo to a third party) are in violation of competition laws. Japan is the world’s largest import market for LNG, importing over 80 million t in 2015. If such clauses are found to violate fair trade laws, the market may see the renegotiation of more than US$600 billion-worth of long-term trading contracts. A report conducted for Japan’s ministry of Economy, Trade and Industry (METI) revealed that currently approximately 80% of Japanese and South Korean long-term LNG import contracts could be subject to such renegotiations.³ This will likely strengthen the position of Japanese LNG buyers by giving them the leverage to amend existing contracts for flexibility. If found to be anti-competitive in Japan, it is expected that contracts across the Asia Pacific region will be renegotiated, just as they were in Europe following the decision of the European Commission in October 2004.

As a result of a return to coal and the restarting of two nuclear generators, Japan’s LNG imports for 2016 are expected to decrease by 3% overall by the end of the year, with a further decrease of 3% forecast for 2017. However, it will still remain the largest net LNG importer in the world. In addition, the large scale restart of nuclear is far from certain. The announcement by newly elected governor Niigata Ryuichi Yoneyama that the Kashiwazaki-Kariwa nuclear plant will not be reopened at present demonstrates the pressure still bearing upon Tokyo Electric Power Co. to meet power demand with alternatives to nuclear. Currently, 40 of the 42 reactors in Japan remain offline amid safety concerns. LNG has been TEPCO’s preferred replacement since the Kashiwazaki-Kariwa reactors closed; with 65% of the company’s electricity production attributable to LNG, representing 27% of the country’s overall LNG imports.⁴,⁵

Shell and Pavilion Gas were awarded licences by the Singapore Energy Market Authority (EMA) to import LNG to Singapore, with the next tranche of LNG imports expected to commence from 2017. Pavillion Energy had already announced plans to work with ExxonMobil to develop LNG bunkering and other downstream solutions in Singapore. Pavillion CEO, Seah Moon, has particularly highlighted the role that developments in small scale LNG could have on demand in South East Asia as the EMA continues to adopt a strategy to create a regional LNG fuelling and reloading hub on the island. Increasingly, the interplay between small scale and large scale LNG will be a key source of growth for the sector.

The authorities in Singapore claim that, by virtue of its geography, it provides a natural location from which larger LNG carriers could break-bulk and re-load onto smaller regional barges for ‘milk-run’ LNG deliveries. Using Indonesia as an example, the country has a population of 250 million people, living across 17 000 islands. Whilst demand across the population may be small and fragmented, the collective volume represents a significant alternative market for LNG growth in the region. Pavillion has signed a memorandum of understanding (MoU) with state-owned Pertamina in Indonesia to explore joint marketing, trading and procurement opportunities. In the meantime, BP has gained final investment approval to expand operations at its Tangguh LNG project, which will see an increase in production by 50% to 11.4 million t. Perusahaan Listrik Negara, the Indonesian government owned electricity provider, will receive 75% of the annual LNG production from the new train.⁶

In addition to new projects coming on stream, existing supply is returning to market. Algeria has re-started its Skilda LNG plant following two months of planned maintenance. The country is the second largest natural gas supplier to Europe after Russia, producing 6.5 trillion ft³/yr gross in its last production year (a 4% increase on the previous year). State-owned Sonatrach exported 12.1 million t of LNG to Europe in 2014; 25% of which went to France and 2.74 million t was delivered to Spain. The expectation is that the company will have exported 36 million t of gas to Europe by the close of 2016, representing a 15% increase on 2015 levels. In addition, three new projects are to come on stream by June 2017: the Touat gas venture, the Timimoun project and the Raggane gas wells.

The Department of Energy (DoE) in South Africa has issued an Information Memorandum relating to the Independent Power Producer programme to procure two LNG-to-power projects totalling 3000 MW of capacity at a cost of US$3.7 billion. The DoE selected the Ngqura port in the Eastern-Cape Province, and Richards Bay in the KwaZulu-Natal Province, for the first phase of the procurement programme.⁷ A separate Request for Qualification (RFQs) will be released for each project with preferred bidders being selected to submit Request for Proposals (RFPs). The integrated LNG-to-power projects will incorporate FSRUs within the port limits, and transmission pipelines and generation facilities outside of the ports. Both generation units will receive revenues under a Power Purchase Agreement (PPA) with Eskom, the South African public utility provider.

The significant interface and finance risks associated with LNG-to-power projects have increasingly been overshadowed by the huge financial incentives of providing a cleaner alternative to emission intensive coal plants in the absence of World Bank subsidies. South Africa has particular appeal to companies with existing gas interests on the west coast of Africa. Other countries in the West African region have also shown growing interest in LNG imports for the purposes of power generation, with first gas imports expected in Ghana by the end of 1Q17.

BP has joined ConocoPhillips to give assurances to the Alaskan LNG project amid doubts that the state-led project would become operational. The Alaskan government paid US$65 million for TransCanada Corp.’s 25% stake in the Alaska LNG project in late 2015, which would transport gas from the North Slope fields to a facility on Cook inlet for shipment to the Asian market. However, increasing global supplies of LNG and depressed prices have dissuaded private project partners from investing further. In August 2016, a report from Wood Mackenzie found that the Alaskan LNG project was “one of the least competitive” proposed plants worldwide, prompting ExxonMobil to withhold investment from the next stage of the project.⁸ Alaskan Governor, Bill Walker, took to South Korea and Singapore to meet key LNG buyers with an aim of securing a contracted buyer for the 20 million tpy of LNG that are forecast from the site. Despite the negative feasibility analysis in the Wood McKenzie report, Governor Walker is insistent the Alaska LNG project would bring billions of dollars of revenue to the state, even with oil prices as low as US$45/bbl. However, should prices return to the US$27 lows of January 2016, it is difficult to see how investors may be willing to participate further.

At the same time, Alaska Railroad Corp. has been awarded the first rail licence in the US to transport LNG by rail. A month-long operational performance trial period took place between September and October on a route between Anchorage and Fairbanks. The proposal is that LNG, transported in International Standards Organisation (ISO) containers by rail, could help meet Alaska’s growing energy needs in the interior, where few pipelines are available to make deliveries. The proposal would be to transport the fuel at night on existing infrastructure to avoid interaction with passenger railcars. ISO containers are of a standard dimension, ensuring compatibility with loading and unloading venues. This avoids the high cost of new bespoke infrastructure and minimises the concerns of travellers who perceive LNG as ‘dangerous’ cargo.

A period of uncertainty faces the global LNG market. In the event that recently awarded US export licences were to be suspended in order to satisfy domestic demand, the price of LNG on the global market would be expected to rise in the short-term as supply decreases. The medium and long-term implications following the recent US election on the trade of LNG is, however, unclear. Increased investment in the oil and gas sector, sustained by tax incentives and softened policies on carbon emissions, could help sustain significant growth in the market, with increased export potential.

Following the outcome of the referendum on Britain’s continued membership in the EU, concerns have been raised about the effect that the UK’s exit might have on LNG volumes and prices in the UK.

In practice, the UK already has mitigation against security of supply risks built into the system. The existing import infrastructure allows multiple sources of supply via its three gas interconnectors and three LNG import terminals. As the infrastructure is already largely in place, Norton Rose Fulbright would expect operations and gas flows to continue as normal, irrespective of any Brexit.

For Brexit to have an effect on UK prices, it would need to lead to consequences such as export tariffs imposed on EU gas flowing to the UK. LNG import capacity is not fully utilised at present, but this is more of a supply and demand issue and unlikely to be connected to Brexit. LNG accounted for only 13% of UK gas supply in 2015 but there is room for this to increase given current spare capacity and with a fourth import terminal under construction (offshore Barrow-in-Furness). A joint project between Flogas and Stolt-Nielsen has also recently been announced at the eastern Scottish Port of Rosyth, with a scheduled operation date for 2019. Small scale Stolt-Nielsen carriers are expected to deliver LNG for bulk storage at the port, before regional truck distribution by Flogas; demonstrating the increasing potential of small scale LNG in Britain. However, whether or not the UK will be an attractive destination for spare LNG volumes is more likely to be driven by the price of gas in the UK market than any other factor. Questions could also be raised about the guarantee of gas supplies through key interconnectors, such as UK-Belgium Interconnector system (IUK), in the event that continental members wished to store surplus supplies on the mainland in the event of European shortages.

Regardless, the impact of Brexit will not be clear until Article 50 is triggered, and even then, may not be fully known until Britain’s future trade relationship with Europe is established and implemented.

The depressed price of oil, which continues to be a key factor in securing finance, paired with oversupply, has seen the price of LNG fall. Industry overruns and the costs associated with LNG R&D continue to squeeze profit margins in the sector. However, opportunities remain. The growing sustainable relationship between large scale and small scale LNG, paired with increasingly tougher regulations on emissions, continues to promote LNG as the hydrocarbon of choice. Competitive prices and ease of availability look set to cement global interest for years to come.