Global | Publication | January 2021
Global demand for LNG grew by 12.5% to 359 million t in 2019. An industry record of 40 million t of additional supply became available as the bulk of new liquefaction projects from the investment wave of 2014/2015 came online. By contrast, 2020 has proved to be very different, with Sempra Energy’s Costa Azul LNG export plant in Mexico being the only new LNG export project in the world to take a Final Investment Decision (FID) in 2020. This can primarily be attributed to the impact of the COVID-19 pandemic and the fall in commodity prices earlier this year, but each region has had its own particular challenges, as this articles examines.
For the LNG industry in Asia, 2020 has been a year that we would probably all rather forget. The perennial hope of dotting the islands and coastlines of a region that is still hungry for more electricity generation with LNG receiving terminals shone brightly at the beginning of the year, with prospects of FIDs for multiple LNG to power projects in countries such as Pakistan, Bangladesh, Myanmar, Vietnam, Indonesia, and the Philippines. However, a significant number of international players have pulled out of these and other regasification projects during the course of the year. The projects that have continued have suffered from COVID-19 related paralysis of key ministries, which has made consensus-building more challenging.
Despite this, emerging nations in South and Southeast Asia have continued rapid growth in power demand. While Asia remains the region with the greatest reliance on coal, its use as the fuel of choice continues to decline, and gas is increasingly seen as necessary to enable a transition to low-carbon solutions without limiting economic growth. Market forecasts still suggest that the region will be importing a third of global LNG demand by 2040, and it is hoped that governments will turn their attention back to LNG infrastructure to stimulate economies as the world begins to emerge from the pandemic in 2021.
Energy affordability and security remain significant issues across the region. Power tariffs have generally been increased as a result of many governments reducing energy subsidies, and lower LNG prices (caused by abundant global supply) have made the transition to natural gas increasingly attractive. For example, China’s LNG imports are expected to rise 10% to new highs in 2021 as companies take advantage of this year’s low prices to cover increasing industrial use and robust residential demand.
On the small scale side, in June an FSRU in Thanlyin Township in Myanmar received its first cargo from a small scale LNG carrier. The LNG is being consumed in the greenfield power plant in Thaketa and power plants at Thanlyin and Kyauk Phyu. This project was completed in around nine months by CNTIC VPower, a joint venture between Hong Kong-listed VPower Group (which had no prior experience in the LNG sector) and China National Technical Import and Export Corp. Myanmar is one of the least electrified countries, showing that even with a complicated supply chain (this one is likely to need a vessel acting as an FSU in deeper water, with a small scale vessel shuttling between the FSU and FSRU) LNG can still bring real value to markets that are constrained.
In Singapore, the Energy Market Authority has issued a request for proposals to increase the number of licensed LNG importers into Singapore from three to five, and Singapore LNG Corporation is currently in the process of expanding its LNG terminal and changing its arrangements with existing importers, to accommodate expected increases in imports over the next decade.
The Indian Gas Exchange was launched in June 2020, providing a physical gas trading platform in one of the region’s growing gas markets. As the share of gas in India’s energy mix continues to increase, more players will enter the Indian market, leading to an increase in sophistication.
Last but by no means least, Singapore’s Pavilion Energy recently announced the signing of an innovative long-term supply contract with Qatar Petroleum, which requires each delivered LNG cargo to be accompanied by a statement of its greenhouse gas emissions (GHGs), measured from well to discharge port. If other purchasers follow suit, and an industry wide methodology for assessing GHGs at each step of the LNG chain can be established, the opportunities for monitoring and potentially reducing GHGs are exciting.
2020 has marked a year of M&A and sell-downs in LNG and oil and gas projects across Australia, a shift in tone from 2019’s milestone of officially becoming the world’s largest exporter of LNG. Exports are forecasted to decline to 76 million t (after reaching 79 million t in 2019) due to the combined effects of COVID-19-related demand reduction, and production issues at the Prelude and Gorgon LNG plants.1
Australia is on the cusp of a multi-billion-dollar transformation in ownership of its LNG infrastructure assets, with both infrastructure funds and traditional industry players tipped to emerge as potential buyers in current sale processes. Reportedly on the market are various interests in LNG projects and upstream assets.
Multiple projects face issues relating to upstream resource fields nearing depletion, such as North West Shelf and Darwin LNG. Existing joint ventures are exploring back-fill tolling arrangements with other fields, the net result being potential misalignment between field and infrastructure ownership, and a number of parties seeking to exit existing joint ventures. Infrastructure players have been identified as potential investors, given the attractiveness of the long-term stable tolling arrangements, particularly in relation to midstream assets.
Asset owners are looking to monetise large amounts of capital sunk into LNG assets in order to generate capital efficiency, enabling them to redirect some capital into ‘new energy’ projects, whilst using other amounts for further exploration and production. The low oil price is likely to be accelerating this divestment trend – nearly 75% of Australia’s LNG is sold under oil-indexed long-term contracts, and the pricing lag will be felt acutely next year. To entice new buyers, owners may need to repackage assets to offer a commercial model allowing for stable rates of return via service and tolling arrangements.
In the East Coast gas market, the Federal Government continues to mull over a domestic gas reservation scheme as a potential measure to address perceived lack of access to gas and comparatively higher prices, and has released a further issues paper as of October 2020. Domestic manufacturers have long blamed Queensland’s massive LNG export projects for diverting gas overseas as LNG and for increasing domestic gas prices.
The Federal Government recently threatened to intervene in the energy market by building a new gas-fired power station in the Hunter Valley in New South Wales with gas pipelines to feed a new national trading hub, in the event that industry did not replace the capacity to be lost from the Liddell coal-fired power station on its planned closure in 2022. The Federal Government also signalled it will be negotiating with Queensland’s LNG exporters to increase the volumes of gas they reserve for the domestic market.
A number of projects in the Sub-Saharan Africa region have been progressing steadily, although in the current climate, focus on LNG in the region will most likely shift to further development of existing projects rather than the sanctioning of new developments. The most interesting developments have been in Mozambique and Nigeria.
Mozambique has a number of projects in development and continues to position itself as a future contender for one of the largest global exporters. The Coral South FLNG Project (liquefaction capacity 3.4 million tpy) is expected to be the first LNG project in Mozambique to begin operations. The COVID-19 outbreak caused drilling operations to be suspended in April, but despite this, lead developer ENI recently confirmed that drilling will resume in early 2021. With work on the new-build platform continuing as planned at a South Korean shipyard, the project remains on track to achieve start-up in 2022.
Next up is the Mozambique LNG project (liquefaction capacity 12.88 million tpy), the country’s first onshore LNG development with a target start-up date of 2024. Progress with construction was interrupted this year due to the pandemic, but this did not prevent Total (as operator) concluding the biggest project financing ever agreed in Africa, which it announced in July 2020. The project will be financed by a mix of direct and indirect loans from no less than eight export credit agencies, 19 commercial bank facilities, and a loan from the African Development Bank, to the tune of US$14.9 billion (making the total investment in the project somewhere in the region of US$20 billion). The promise of such huge sums is surely a sign that investors continue to have confidence in the long-term prospects for Mozambique.
The Matola Gas Company, in partnership with Total, recently announced the construction of an LNG terminal in the Mozambique port of Matola. It has been reported that LNG will initially be purchased on the international market, later to be replaced by LNG produced from gas reserves in Mozambique’s Rovuma Basin, assuming that FID for the Rovuma LNG project – due to have been taken this year – goes ahead in 2021. The Rovuma LNG project (liquefaction capacity 8.2 million tpy) is another of Mozambique’s flagship LNG projects and ExxonMobil was due to have taken FID this year. That date has now been pushed back, following on from another delay the previous year, which will doubtless have an impact on the original target for production start-up of 2025. Construction of the Matola terminal, which represents a US$300 million investment, is expected to begin in 2021. The project will include an FSRU moored in the harbour and a gas-to-power plant that will be connected to South Africa’s gas network.
In Nigeria, in May 2020, Nigeria LNG Ltd (NLNG) signed a US$3 billion corporate loan to finance the construction of its seventh LNG train. This project, a joint venture between the Nigeria National Petroleum Corporation and IOCs Shell, ENI and Total, is expected to boost Nigeria’s LNG output by nearly one-third. NLNG currently operates a liquefaction complex with six existing liquefaction trains and associated facilities, with a combined capacity of 22 million tpy of LNG and 5 million tpy of liquefied petroleum gas and condensates. Train 7 will add approximately 8 million tpy of LNG and increase NLNG’s overall capacity to 30 million tpy.
Energy access, affordability, and reliability are major focus areas for the South African government moving into 2021, and LNG can play a crucial role in the state achieving these policy objectives.
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 involved. The IRP provides for an additional 3000 MW of installed capacity for gas and diesel.
To implement the IRP, the government published an RFP for the Risk Mitigation Independent Power Producer Programme (RMIPPP) in August 2020, for the procurement of 2000 MW new generation capacity from dispatchable facilities. Bids must submitted in December 2020. The objective of the RMIPPP is to fill the short-term supply gap, alleviate the current electricity supply constraints, and reduce utilisation of diesel-based peaking electricity generation in the medium to short-term. The 2000 MW of new capacity will be procured from a range of energy technologies, to be installed by 2022.
Given the short time frame and the fact that South Africa does not have any LNG import infrastructure, the role of LNG in RMIPPP presents some challenges. However, it is possible that powerships, which could run on multiple fuels such as natural gas, liquefied gas and diesel, could meet the tight deadlines. The Turkish powership company Karpowership has expressed an interest in participating in the RFP and applied for government approval to berth powerships in ports Richards Bay Coega and Saldanha. Karpowership’s Global Sales Director Patrick O’Driscoll said “Karpowership has the ability to respond now, so speed of delivery has been paramount to all the work we’ve done in Africa”. He pointed to a 120 MW contract in Senegal which the company delivered and operated in nine weeks.
The government has selected Coega Special Economic Zone (SEZ) – which is adjacent to the deepwater port of Ngqura, 120 km northeast of Port Elizabeth – as the preferred port for the import of LNG. The port selection makes sense from a government perspective. It is close to Mossgas (who it is understood could run out of gas in by the end of this year), and Total recently made a gas condensate discovery on the Luiperd prospect (Block 11B/12B, 175 km offshore the east coast of South Africa). This discovery is anticipated to be a catalyst for South Africa’s gas-to power programme.
In the longer term, LNG from Mozambique is also on the cards. The Matola gas-to-power plant, as detailed earlier, will be connected to South Africa’s gas network and will be able to put regasified LNG directly into South Africa’s system.
The US held 10% of global market share as of the end of 2019 and has overtaken Malaysia as the world’s third largest exporter of LNG, having exported 13.1 million t of LNG out of a total of approximately 41 million t in global export volumes.2 The new trains that came online in 2019 contributed more than half of added global liquefaction capacity in 2019, with a total of nearly 28 million tpy. The Federal Energy Regulatory Commission has also approved a further 13 applications for onshore LNG facilities in the US. Several of these new projects were expected to achieve FID in 2020 but have been delayed into 2021 and possibly beyond whilst the global economy reacts to the impact of the COVID-19 pandemic.
One of the defining features of the global LNG trade during 2020 was the steep decline in demand caused by the pandemic. Data from the US Energy Information Administration (EIA) reflects that in January 2020, the US was exporting 8 billion ft3/d. By July 2020, this dropped to 3.1 billion ft3/d as the effects of the pandemic and the ensuing global lockdowns unfolded. Approximately 175 US LNG cargoes were cancelled up to October 2020, with 80% of the cancellations relating to cargoes that were scheduled to load during the summer months. Fewer cargoes are being cancelled for the final months of 2020, and the EIA expects that demand will slowly increase during the winter months, with US LNG exports averaging approximately 5.5 billon ft3/d in 2020 and 8.4 billion ft3/d in 2021.
LNG markets were largely already oversupplied on the back of record volumes of LNG being contracted during 2019 and European storage facilities approaching capacity. The demand shock compounded the problem, with US LNG cargoes seeming to bear the brunt of the economic downturn. However, the US LNG Sales and Purchase Agreement model pioneered by Cheniere Energy and the flexibility afforded to its buyers came to the fore again. By utilising the ability to cancel cargoes (against the payment of cancellation fees and the fixed price component, but foregoing payment for the LNG), LNG buyers that were lucky enough to have US LNG in their portfolio were able to make substantial operational adjustments to balance their demand/supply and to balance their trading positions, highlighting yet again the unique role of US LNG in the global market. Interestingly, this phenomenon highlighted the strength of the project debt financing structures underpinning some of the affected LNG sellers and their liquefaction terminals in the US. At the same time, it also impacted the financial performance of terminal owners, allowing them to recognise and bring forward certain elements or components of their LNG sales price structure to the time of cancellation, even while it forced them to forego the commodity portion of their LNG sales price as a result of the cancellation.
The ongoing transformation of LNG into a globally traded commodity was another feature of the past year that contributed to enabling LNG players to hedge their risks in a volatile market. Even though spot trading liquidity declined as a result of the drop in importing demand, spot trading has provided another solution to contracting challenges faced by US exporters with excess available capacity.
So far, the US liquefaction sector seems to have weathered the damage inflicted by 2020’s volume of cargo cancellations and appears poised to hit pre-pandemic export volumes. By November, feed gas deliveries had resumed at pre-pandemic levels and, taking into account future liquefaction capacity (proposed, approved or under construction), the US looks set to expand its role in shaping global LNG dynamics further in 2021.
Canada’s nascent LNG industry has had a rocky start. Even before 2020, many proposed LNG export projects had been shelved or put on hold due to financial and regulatory obstacles, low commodity prices, and other market factors. The risks of protests, blockades, and the challenges associated with engagement with Indigenous groups have received particular attention in the press. Many commentators have expressed frustration over how long it has taken to develop LNG export capacity in Canada and raised concerns that, with large scale liquefaction facilities already having been operating for many years in other major gas-producing countries, such as the US, Qatar and Australia, and other projects expected to come on-stream soon, the window of opportunity for Canadian projects to satisfy Asian and European LNG demand may be narrowing. 2020 did little to allay those frustrations and concerns.
In March 2020, Warren Buffett’s Berkshire Hathaway was reported to have exited the proposed Énergie Saguenay LNG export project in Québec, and FID is not expected until the end of 2021. Around the same time, the COVID-19 pandemic began to cause widespread disruption and LNG demand reduction, dampening Canada’s progress during 2020 in developing LNG export capacity and causing further project timelines to be postponed. These included the commencement of construction of the proposed Woodfibre LNG project in Squamish, British Columbia (BC), reportedly deferred until the summer of 2021, and the FID on the proposed Goldboro LNG project in Nova Scotia, reportedly deferred until June 2021. The measures that have been required to reduce the spread of COVID-19 have also caused disruption on the ground, with workforce reductions at the LNG Canada project which is under construction in Kitimat, BC.
Despite 2020 having been a challenging year for Canada’s LNG industry, there is reason to be optimistic for a more positive 2021. The workforce reductions on the LNG Canada project were brief and the project continues to target 2025 for commencement of exports. The fundamental drivers for the development of LNG export capacity in Canada also remain strong in many respects. Oil and gas majors still project that LNG demand will increase substantially over the coming decades, particularly in Asia, and there remains a strong desire by many in Canada to supply that demand with responsibly-sourced, cost-effective, and relatively clean Canadian LNG. There is also increasing interest in the development of LNG bunkering facilities in Canada, including at the Tilbury LNG facility in Delta, BC. There is confidence and positivity that, as the world emerges from the effects of COVID-19 during 2021 and the market rebalances, many of these projects will proceed and that Canada continues to be on track to join the large scale global LNG export trade by the middle of this decade.
The LNG industry has faced many challenges during 2020. As global demand for LNG significantly declined, Europe responded by trying to balance the market by importing LNG and storing both LNG in LNG storage tanks at European terminals, and also regasified LNG in natural gas storage facilities. Many were predicting that, partly as a result of these imports, European gas storage facilities would be full before the start of winter in Europe. This has not come to fruition, although as we move towards the end of 2020 there is indeed a lot of LNG and natural gas in storage in Europe.
In an unexpected move earlier in the year, the LNG market responded to the lack of global demand with the cancellation of a number of planned LNG exports from the US, something few people anticipated. The general expectation was that LNG would continue to be produced and exported and that the market would find a home for it. Such are the fundamental ramifications of the COVID-19 pandemic.
Looking forward, the LNG industry will continue to face major headwinds. There are serious questions about how quickly global demand for LNG will recover, and therefore how quickly additional liquefaction capacity will be required. In the short-term, unplanned outages at LNG export facilities including at Prelude and Gorgon are assisting to reduce oversupply and balance the market. Although unfortunate for the LNG export terminals affected by production problems, this has been a very lucky turn of events for the export terminals around the world which are still in production.
Short-term hopes for the remainder of 2020 and the start of 2021 are resting on a cold – ideally very cold – winter in Europe. As Norton Rose Fulbright contemplates the short-term future of the LNG industry while finalising this article, the company’s London team is working from home in the UK’s second lockdown. So far, temperatures have been mild – not ideal for the natural gas industry. With future global demand for LNG expected to recover slowly, all eyes are on the amount of LNG and gas currently in storage in Europe and the extent to which this will have been drawn-down by the end of winter. If storage volumes remain high, 2021 will most likely see a return to cancellations of LNG export cargoes from the US. Problems with oversupply will remain and may be compounded when various liquefaction plants emerge from their current shutdowns.
Looking further into the future, could the interesting development in GHG emissions reporting be the first of many such supply agreements? Perhaps other buyers will decide to follow suit in requiring this information before it is mandated by governments seeking ways to decarbonise supply chains. Wood Mackenzie is certainly of the view that “carbon footprint will be one factor determining how attractive an LNG project is to developers and buyers, and will influence the price it can command.” The energy transition is underway and we may see more LNG buyers looking to purchase greener LNG cargoes in the future.
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