UK: Alternatives to redundancy: A guide for UK employers
The economic effects of the outbreak of coronavirus (COVID-19) for many businesses are significant and likely to endure for a long period of time.
Nick Prowse and Penny Cygan-Jones, Norton Rose Fulbright, UK, take a look at what’s on the horizon for the year ahead.
2019 has seen the start of a re-shaping of the LNG industry, with the promise of further changes in 2020 and beyond. As well as new import and export countries entering the market, the year has been marked by the development mega-liquefaction projects, particularly in the US, Russia and Qatar. Developments in technology are opening up previously stranded reserves and there have been sigificant moves towards the commoditisation of LNG. In this article, Norton Rose Fulbright takes a closer look at how some of these themes are playing out in different regions.
The US1 has gone from being an importer of LNG to being one of the largest exporters in a very short time, with plans to double its production again. There are currently nine LNG trains operating and producing LNG,2 plus Kinder Morgan’s Elba Island liquefaction project placed its first train in commercial service in October (although as of the time of writing no commissioning cargo has been loaded and shipped). All of these projects were designed to take advantage of the ‘great shale revolution’ in the US and the corresponding upheaval in the supply and demand dynamics of the domestic natural gas market. Consequently, the US has already become the fourth largest LNG supplier globally (behind Qatar, Australia and Malaysia) and, by adding 8.2 million t of LNG to global supply in 2018, it is second only to Australia as the largest driver of supply growth.3 Furthermore, as these ‘first wave’ projects emerge from the development and construction phase to become operational, the ‘second wave’ is becoming a reality with four more projects making firm progress.
The emergence of US LNG exports has likely been the most significant development affecting the global LNG trade over the last few years. The de-coupling of LNG and crude oil with the introduction of Cheniere’s Henry Hub-based pricing formula, combined with the elimination of ‘destination clauses’ (removing restrictions on cargo destinations and allowing diversions) from US LNG sale and purchase agreements (SPAs) has contributed to accelerated growth and liberalisation of the global LNG trade, including in the spot market, which accounted for 31 per cent of total global LNG trade in 2018.
Alongside this significant growth in the physical trading and delivery of LNG on a spot basis, the industry is seeing an increase in the development and volume of financial trading of LNG, largely in the form of futures contracts. LNG futures contracts have been around for a few years, but meaningful penetration and growth in trading volumes emerged only in 2017/2018.4
One of the key issues hindering the development of LNG as a global commodity has been the lack of physical trading hubs in different regions. While natural gas trades and physically settles at the Henry Hub (and other points) in the US, the National Balancing Point (NBP) in the UK, or the Title Transfer Facility (TTF) in the Netherlands, a true physical trading hub in LNG has yet to develop and emerge in a meaningful way, despite the efforts of initial contenders such as Singapore to develop a liquid financial derivatives trading market for LNG with its SGX LNG Index Group spot price index (which ceased publication on 31 October 2019), and leading importing countries such as China and Japan. However, on 14 October, CME Group published its new LNG futures contract – the ‘Gulf Coast LNG Export Futures’. According to CME, this new contract is the first-ever physically delivered LNG contract, which is listed with and subject to the rules and regulations of NYMEX. The Gulf Coast LNG Export Futures contract applies to all LNG bought or sold for future delivery on NYMEX with delivery at Cheniere’s Sabine Pass LNG terminal facility (CME Group also reported that the Freeport LNG terminal and additional facilities will be included as loading ports in future delivery months). The publication of this contract is certainly an important milestone in the development of a physical LNG trading hub, though its practical implementation and effect on the global LNG industry remain to be seen.
As further evidence of the development of LNG as a commodity in the global marketplace, Freeport LNG announced that it will operate the first ever ‘virtual’ LNG store-front in Redwood Marketplace – an online commodity trading platform that will enable bilateral negotiation and confirmation of commercial terms between buyers and sellers.
The US Geological Survey (via the Department of the Interior) reported in October 2019 that the Marcellus and Utica shale basins hold an estimated 214 trillion ft3 of ‘undiscovered technically recoverable’ natural gas. If this is correct, there is ample reason to conclude that production of US LNG will continue to grow and increase market share for the foreseeable future.
Traditional LNG markets in Northern Asia5 are presenting challenges for LNG sellers. Deregulation in Japan and Korea means LNG buyers no longer have the security in their domestic markets they once had, and are therefore more reluctant to commit on a long-term basis for new LNG supplies. US and Chinese geopolitical trade tensions have led to a 30 per cent tariff on LNG exported from the US to China, effectively shutting one of the most rapidly growing markets for US exporters. More significantly, this excludes Chinese capital from new US projects.Increased competition from renewable energy, including big advances in offshore wind in Taiwan and solar projects in Japan, is contributing to a politically and economically challenging environment for LNG contracts. Many players making the long-term commitments to enable liquefaction projects to proceed are adopting aggregator business models, looking to acquire LNG on a long-term basis from cost effective sources and then selling LNG wherever they can find markets. This can involve pricing LNG on local indices such as JKM and then selling it on relatively short terms of five years or less.
Also of importance is the increased emphasis that international energy companies are placing on opening new up LNG markets. Shell has acquired one of the two LNG bunkering licences in Singapore, and the marine bunkers market is seen to offer exciting possibilities for LNG as the global shipping industry adopts a new IMO standard of having no more than 0.5 per cent of sulfur in marine fuel from January 1, 2020. Total announced recently that it will be acquiring a large interest in Adani Group’s gas distribution business in India, which is part of a plan that also includes selling LNG as a vehicle fuel through a service station network in India. There are also other plans by IOCs to distribute LNG as a liquid fuel in this region.
There are parts of Asia that still have remarkably low levels of electrification, and there have been multiple LNG to power projects proposed for countries such as Bangladesh, Myanmar, Pakistan and Indonesia.
Even countries that we have thought of as significant gas producers (and indeed exporters of LNG), such as Thailand, Malaysia and Indonesia, are looking at multiple LNG import projects to address either relatively localised anomalies in their distribution of gas or perceived monopolistic behaviour by incumbents.
We must be nearing the point where there is sufficient liquidity in LNG markets where LNG projects are treated by the lender community in a similar way to oil projects. Perhaps the next step is the development of reliable price indices in the main gas consuming regions?
Australia6 faces a looming dichotomy; as it moves into the number one position worldwide for nameplate liquefaction capacity (88 million tpy ),7 it is also about to join the small cohort of countries who both import and export LNG. Its projected overtaking of Qatar as the world’s largest exporter of LNG has not yet occurred, with the first eight months of 2019 seeing Australia exporting 52 million t, compared to Qatar’s 54 million t. Nevertheless, it remains projected that by mid-2020 Australia will take the number one spot (perhaps only briefly, given Qatar’s extensive pre-FID expansion plans).
In contrast to these abundant volumes marked for export, much of which is sold under long term sales arrangements, the ‘east coast gas shortage’ continues – a period which has seen regional domestic gas prices on the east coast of Australia spike significantly since 2015. This issue has driven an appetite for LNG imports, with five separate floating storage and regasification unit (FSRU) projects proposed as a source of supplementary gas.
The most advanced of these had been the Port KemblaGas Terminal in the state of New South Wales, to be operated by a joint venture (JV) consisting of JERA, Marubeni and Squadron Energy. Development approval was granted in April 2019 and in May, Australia’s third-largest energy retailer EnergyAustralia became the first confirmed offtaker. However, in August 2019, it was reported that the consortium proposes to increase the nameplate capacity of the terminal to almost double its original planned capacity in response to higher than anticipated customer demand, and will need go back to the government to seek further approvals.
AGL’s US$250 million Crib Point import terminal in Victoria has reached approvals stage, although AGL announced in June 2019 that stringent requirements for data in the approvals process had led to delays, pushing forecasted first deliveries back to the first half of 2022. Other projects include EPIK’s Newcastle GasDock in New South Wales, which, in August 2019, secured status from the New South Wales government as a project of critical state significant infrastructure (granting it a streamlined approvals process), and Venice Energy’s Outer Harbor LNG Project for Port Adelaide in South Australia, which is at feasibility stage. Australia’s Department of Industry had previously predicted that only one or two of the five LNG import terminals was likely to proceed, on the basis that LNG import prices are forecast to be higher than domestic gas by the mid-2020s. However, warnings of a major east coast gas shortfall from 2022 continue, and in the absence of the states of NSW and Victoria lifting their onshore gas exploration moratoriums, enthusiasm for LNG imports for this region has remained high.
On the east coast, LNG export restrictions still loom whilst the federal government reviews plans to amend its Australian Domestic Gas Security Mechanism. This was enacted in 2017 with the aim of ensuring that domestic demand was fulfilled; it imposes LNG export restrictions in Queensland in the event of a shortfall being forecast for the following year. To date, Queensland LNG producers have agreed to supply well-priced additional gas into the domestic market in an effort to avoid restrictions being imposed. The review by the federal Department of Industry, Innovation and Science was due to be completed by the end of September 2019, but at the time of writing the conclusions have yet to be published.
The vast geography of Australia has meant that the LNG narratives on the east and west coasts are somewhat disconnected. Elsewhere, the focus has turned to upstream resources that can backfill existing projects and expansions. Woodside proposes to use the Browse gasfield development to backfill the North West Shelf (NWS) LNG project from 2020 and to toll third-party gas for the first time as it approaches depletion of its own reserves. The terms on which gas from the Browse field is processed remain contentious between the NWS participants. Plans for the Scarborough gas development include adding a second train at the existing Pluto LNG facility, with FID projected for 2020 and first LNG scheduled for 2025, despite Woodside currently seeking to reduce its 75 per cent stake in the project.
Darwin LNG requires a new source of backfill from 2023 as the Bayu-Undan field supplies are expected to cease. ConocoPhillips has indicated, amidst reports of its own sell down plans from the LNG project, that Santos’ Barossa gas field located offshore north of Darwin is intended to fill the gap, with the offshore pipeline contract awarded in September 2019 and FID expected early 2020. Inpex has also flagged expansion plans for Ichthys LNG, as it approaches plateau production in 2019, earlier than planned.
Energy access, affordability and reliability are major focus areas for the South African government8 moving into 2020, and LNG can play a crucial role in the state achieving these policy objectives.
At the 2019 Africa Oil and Power Conference, held in Cape Town, Minister of Mineral and Energy Resources, Gwede Mantashe, noted in his keynote speech that the government seeks to promote energy security through regional trade, particularly by importing electricity generated by gas in the Eastern part of Africa.
In October 2019, the much anticipated Integrated Resources Plan (IRP) – an electricity capacity plan – was approved by Cabinet and published. It sets out an indication of the country’s electricity demands, how this demand is to be addressed and the costs. It is hoped that the policy certainty which the IRP provides will facilitate investment in power generation and reduce the costs of doing business in the country.
The IRP provides for an additional 3000 MW of installed capacity for gas and diesel. The government has announced that it has selected Coega Special Economic Zone (SEZ) as the location for the first LNG import terminal and gas-to-power plant to be developed. In addition to this, the site will be a location base for the import of feedstock for the GTL refinery in Mossel Bay, and will be utilised for the conversion of existing power plants from diesel to gas. While the site provides significant opportunities for the LNG sector, there are technical concerns regarding the infrastructure of the port which still need to be addressed.
In July 2019,9 South African state-owned rail, port and pipeline company, Transnet, announced that it had entered into a US$2 million cost-sharing agreement with the World Bank to study future use of Transnet pipelines for the development of inland natural gas transmission and the establishment of ‘virtual’ LNG pipelines. These facilities are earmarked to become operational by 2024.
In terms of the IRP, gas-fired generation is forecast to account for 8.1 per cent (6380 MW) of installed capacity in South Africa by 2030, and is expected to make up the shortfall caused by the phase out/conversion of existing coal-fired power stations. However, a number of key policy documents, including the Gas Utilisation Master Plan, remain under consideration and will need to be harmonised with existing legislation. The updated IRP is a positive step forward, and clearly illustrates a shift in long-term focus from a coal powered future for South Africa to one underpinned by gas-fired generation, operating in conjunction with renewable energy projects.
Finally, the proposed unbundling of South African National Power Utility Co. (Eskom) into three separate entities responsible for generation, distribution and transmission, respectively, may influence the development of LNG projects in South Africa and lead to a more competitive power generation market, facilitating growth in the LNG industry.
2019 saw increased supply emerging from new source in Africa.10 Growth in export volumes from African projects currently under development account for most of the additional trade east of the Suez Canal.
Kosmos Energy, the main shareholder with BP in a number of floating LNG (FLNG) projects offshore Mauritania and Senegal in West Africa, has reported that the latest drilling in the Greater Tortue-Ahmeyim field has resulted in locating the high-quality Albian reservoir, which should lead to an increase in LNG production. The Greater Tortue Ahmeyim LNG project is on track to deliver first gas in the 1H22.
Mozambique has Africa’s third largest gas reserves after discoveries off its coast early in the decade. Three LNG plants with the capacity to export more than 30 million tpy are moving ahead, with a fourth under construction. ENH, Mozambique’s national oil company, announced in September it was forming a 51:49 JV with Vitol to increase the value of its energy commodities. The first LNG export plant under its development, the offshore Coral South FLNG export, is led by Eni and is on track to commence production in 2022. With a 20-year contract in place, BP has already agreed to an offtake deal for all LNG produced.
In further progress in Mozambique, TechnipFMC has been named engineering, procurement and construction (EPC) contractor for the Offshore Area 1 development in respect of a subsea hardware system worth more than US$1 billion for gas supply to the Mozambique onshore LNG project. The liquefaction project will have a phase one output of almost 12.9 million tpy of LNG from two liquefaction trains, as well as all necessary associated infrastructure, storage tanks and export jetty facilities. The phase one development contract with an estimated value of US$6 billion was in turn awarded to a joint venture between Saipem, the Italian energy services company, US-based McDermott International and Japan’s Chiyoda Corp.
In Algeria, a new deal has been agreed with the Government of Tunisia and Eni for the pipeline transportation of natural gas to southern Europe, whilst Algeria also prepares to direct new gas finds into industry rather than LNG exports. This follows the agreement reached with Algerian state energy company Sonatrach in May in relation to the purchase and transport of gas across the strait of Sicily and completes the contractual framework that allows Eni to import Algerian gas into Italy until at least 2027 (with options to extend).
The impact of consolidation in the run up to 2020 continues to shape the future direction of the LNG industry. We have witnessed the mega-merger between BG Group and Shell in 2016, followed by Total’s acquisition of Engie’s LNG business in 2018. In September 2019,
Total announced the closing of a further acquisition – Anadarko’s 26.5 per cent operated interest in the Mozambique LNG project for a purchase price of US$3.9 billion. The main players in the LNG industry are clearly seeking to grow and benefit from larger LNG portfolios and the resulting economies of scale. LNG markets will continue to evolve in 2020 and beyond. With increased supply, lower prices and more LNG markets, we will continue to see an evolution towards LNG becoming a truly globally traded commodity. In this context, we may also see the industry using physical trading and financial trading of LNG in the futures markets. Sellers should pay close attention to buying trends, and consider how these might impact the length or other terms of their LNG SPAs. The impact of supply and demand metrics on price, and how to deal with non-investment grade counterparties, will also play a role in shaping the industry as we enter a new decade, whilst the continuing momentum of small scale projects and new uses for LNG in the marine and transport sectors mean the industry will continue to evolve.
This article first appeared in LNG Industry
The economic effects of the outbreak of coronavirus (COVID-19) for many businesses are significant and likely to endure for a long period of time.
As businesses worldwide navigate the challenges brought on by the rapid spread of COVID-19 (coronavirus), it is now more essential than ever that corporations be ready with solutions to address risk issues as they arise.
In light of the impact of the COVID-19 pandemic in Europe and Germany, the German Government has issued a number of sovereign measures on the basis of the Law on Infection Protection in order to slow down the further spreading of the pandemic.