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DBS Group Research • November 2019DBS Asian Insights85SECTOR BRIEFING

Natural Gas & LNG Trends in Asia

LNG Solutions in Prime Play

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DBS Asian Insights SECTOR BRIEFING 8502

Natural Gas & LNG Trends in AsiaLNG Solutions in Prime Play

Produced by:Asian Insights Office • DBS Group Research

go.dbs.com/research @dbsinsights [email protected]

Wen Nan Tan EditorMartin Tacchi Art Director

Pei Hwa HO [email protected]

Suvro Sarkar [email protected]

Jason SUM [email protected]

Jinmyung ChoiNH Investment & Securities

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Executive Summary

LNG Value Chain Demand Supply AnalysisLNG Value Chain Overview

LNG Demand and Regas Forecast

LNG supply and Liquefaction Forecasts

Key LNG Asset ClassesLNG Liquefaction Terminals

LNG Receiving Assets

LNG Carriers

Beneficiary of Booming Demand for Gas SolutionsKorea’s Winning Formula

As the global LNG demand upcycle continues to play out, with various demand drivers firmly in place, especially in Asia (read our previous report: “Natural Gas & LNG Trends in Asia – The Volume Game is Strong”), we believe the LNG investment cycle could reach another inflexion point soon as the market will likely turn from current oversupply situation into a supply deficit situation beyond 2022, if no new liquefaction projects are sanctioned beyond what is already in the pipeline.

In addition, despite some near-term hiccups owing to trade tensions and global growth slowdown, LNG demand to 2025 is still projected to grow at 6% CAGR, the fastest growing among fossil fuels. This will spur ongoing demand for LNG solutions in Asia – LNG carriers, Floating Storage Regasification Units (FSRUs) and Floating LNG (FLNG) vessels. Consequently, this will directly benefit the leading Asian shipyards.

Executive SummarySnapshot of the LNG value chain and relevant asset classes

Source: DBS Bank

LNG investment cycle to pick up steam

Onshore gas production

Offshore gas production

Onshore liquefaction

Offshore liquefaction

LNG Trucking

LNG Shipping

Storage

Offshore regasification

Onshore regasification

Transmission and distribution

LNG upstream

LNG midstream

LNG downstream

Floating, liquefied natural gas units (FLNG)

Floating, storage regasification units (FSRU) LNG Carrier (LNGC)


LNG market could turn into supply deficit by 2030 if no new liquefication projects are sanctioned

Source: International Gas Union (IGU), DBS Bank

Global LNG demand forecast till 2025

Source: IGU, Clarkson Research, DBS Bank

Global LNG liquefaction capacity

expected to reach around 588mtpa in

2025


05

We anticipate global LNG liquefaction (export) capacity to reach around 588mtpa in 2025 from 380mtpa in 2018 (55% growth). Of this, 110mtpa of capacity was under construction as at end-2018. In addition, we expect more liquefaction projects to reach final investment decisions (FID) stage between now and 2021, to facilitate construction of another c.100mtpa of capacity by the end of our forecast horizon in 2025. Within the seven-year period between 2018 and 2025, most of the capacity growth will primarily be driven by the oil supermajors and national oil companies (NOCs), owing to their better ability to adapt to rapidly evolving industry dynamics. On a country level, those having favourable long-term marginal cost LNG profiles like Qatar, Russia, and the United States will lead the charge. Newcomers like Mozambique and Canada are also expected to make a big splash towards the end of our forecast period (2024-25) and become solid contenders in the LNG supply market.

Do not discount Floating LNG (FLNG)

solutions for production requirements


We predict 17% or 25 of proposed LNG projects plan to adopt FLNGs in future. While natural gas production will likely continue to be spearheaded by shale gas developers, we believe the FLNG market will also expand given that:

1. 67% of natural gas reserves (excluding those within shale formations) are located underwater

2. 45% of underwater reserves are held in deep sea areas (where explorations are not feasible without FLNGs)

Moreover, given that the inaugural batch of FLNGs have been in operation since 2018, development/operational costs for gas field projects using FLNGs can now be evaluated and analysed, and once these first batch of projects using FLNGs prove to be cost efficient, FLNG adoption is likely to increase further.

We expect global nominal LNG import capacity to increase to 1,085mtpa in 2025 from 823mtpa in 2018. Again, we expect an additional approximately c.140mtpa of projects to be sanctioned and added till 2025, on top of what is already sanctioned. China will undoubtedly remain the most critical driver of LNG demand, but other Asian countries like Thailand, Pakistan, Vietnam and Bangladesh are expected to contribute in a big way as well, backed by an upswing in gas-to-power projects and depleting indigenous gas production. India’s role in the LNG growth story, while important, will be impeded to an extent by rising domestic gas supply, domestic infrastructure bottlenecks, and lack of focus on gas in the power sector.

Smaller Asian countries of South and Southeast Asia will account for 26% of incremental LNG regas capacity to 2025

Note: JKT refers to traditional Asian LNG markets of Japan, Korea TaiwanRest of Asia includes Thailand, Malaysia, Singapore, Pakistan, Bangladesh, Vietnam, Myanmar, Sri Lanka, Philippines, Hong Kong

Source: IGU, Clarkson Research, DBS Bank

LNG import capacity will also soar, especially

in Asia

Onshore regasification unit costs have been trending up in recent years, as project developers aim to bolster supply stability. On the other hand, offshore regasification unit costs have remained steady as the controlled environment in shipyard construction promotes cost stability. Based on our earlier additional regasification capacity projections, we estimate there will be around US$31bn of additional capital investment requirement in LNG receiving terminals in Asia (excluding Japan, Korea, and Taiwan) between 2018-2025. China and India will account for the lion’s share at around US$10bn and US$7bn respectively, while the remaining US$14bn is split between other Asian countries like Pakistan, Bangladesh, Thailand, and Vietnam.

The impetus for choosing floating over land alternatives is multi-fold, but financing constraints tend to be the most critical factor in developing countries. The capital outlay for a mid-scale (c.3mtpa) land terminal and other onshore infrastructure usually falls in the range of US$600-750m, a substantial amount that necessitates foreign capital for project financing. However, financing tends to be costly for emerging markets with elevated country and default risks. Electing to use FSRUs can help developing countries circumvent financing challenges, since FSRU projects require 30-50% less outlay than a land terminal with similar specifications. Furthermore, chartering a FSRU, rather than an outright purchase, can reduce initial investment costs even further, and mitigate potential cash flow mismatches, as the timing of revenue inflows will be more consistent with operating costs (which forms most of the cash outflows).

Bullish LNG market conditions bode well for related shipping players and builders. Amid rising LNG shipping demand, vessel supply appears to be still insufficient. Global marine LNG trade volume is set to expand at a CAGR of 9.5% over 2018 to 2019. Owing to the US-China trade dispute, LNG trade volume between the two countries over 2018c. 2019 is likely to tumble by 66% compared to before the dispute broke out. Despite this, global LNG trade volume remains on the rise, suggesting that issues such as the US-China trade dispute will not affect the changing global energy mix trend.

We note that there are only a few orders for LNGCs scheduled to be delivered after 2022. To meet demand, LNGC orders placed in the coming years for delivery after 2022 could potentially expand 33.7% (shipping capacity basis) compared to the 2017~2018 average. Such an increase in newbuilding orders will benefit the shipbuilding market.

Since the US began exporting LNG, approximately 1.8 ships have been needed for each 1mtpa of supply, which is considerably greater than the global average shipping multiplier of 1.3x. According to S&P Platts, the average distance covered by a laden LNG ship from the US stood at 9,268nm in 2018, compared to 3,936nm and 5,602nm for Australia and Qatar respectively, highlighting the vast distance between the US and central demand points. Hence, we expect the global average shipping multiplier to continue trending up as the US powers ahead in supply, which should further propel the demand outlook on LNGCs.

We estimate around US$31bn of capital investments in LNG

receiving terminals in Asia till 2025

Floating Storage Regasification Units (FSRUs) preferred in new emerging LNG

markets of Asia

Demand for LNG Carriers (LNGCs) to pick

up in line with greater LNG use

LNG Carrier supply beyond 2022 appears

insufficient in our view

Surge in US LNG cargoes to increase

demand for LNG Carriers


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Demand for LNGCs is expected to pick up, and the market penetration of super-sized LNGCs is set to strengthen. At present, LNG shipping players mainly use shipping routes passing through the Panama Canal and Suez Canal. Thus, the global LNGC fleet is now mainly composed of 160c. 174k cubic metre (CBM) Panamax vessels that can pass through the canals. However, expected changes in shipping routes should lead to greater demand for super-sized LNGCs (larger than Panamax ships).

Korean yards have been dominating the LNG carrier market, which is widely recognised for its high technical barriers of entry owing to the inherent characteristics of transporting a highly flammable fuel that needs to be stored at super low temperatures at below -160°C with low specific gravity. However, leading Singapore and Chinese shipyards will also enjoy some spillover effects of the demand uptrend for LNG solutions like Floating LNG (FLNG) and LNG carriers, as they continue building their track record. Those companies providing LNG containment systems and insulation systems also stand to benefit from this trend.

No. of LNGCs required for each mtpa of US LNG has been increasing amid growing exports to Asia

Source: Gaslog Ltd, NH I&S Research Center

Shipping route changes to spark demand for

super-sized LNGCs

Korean yards dominate the LNG solutions

space

LNG Value Chain Overview

The liquefied natural gas (LNG) value chain begins at the upstream stage, where natural gas is discovered and extracted and then piped to a liquefaction facility, either an onshore liquefaction terminal, or a floating liquefied natural gas vessel (FLNG).

After impurities and liquids are removed from the natural gas at the processing facility at the liquefaction terminal, the gas is then cooled to -160ºC, where it is converted to a liquid state (as its volume reduces by 600 times from its gaseous state) and then loaded on super-cooled storage tanks aboard LNG carriers to be transported to import terminals (commonly referred to as regasification terminals). At that stage, LNG is first stored in special cryogenic storage tanks, subsequently regasified with LNG vaporisers, and finally odourised before being transported via natural gas pipelines to gas fired power plants, industrial and petrochemical facilities or commercial and residential users.

LNG Value Chain Demand Supply Analysis


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LNG Demand and Regas Forecasts

What is the present LNG demand situation?The past few years marked the rise of China as a global gas superpower, as the Chinese titan overtook South Korea as the world’s second largest LNG importer in 2017, while accounting for nearly 50% of global LNG demand growth between 2015 to 2018. LNG consumption in the rest of Asia during the same period saw incredible momentum as well, representing 40% of global LNG demand growth with a 28.4mt increase in net imports.

Unsurprisingly, the slowdown in Asia’s LNG demand growth this year reverberated throughout the market. With the region’s demand for LNG failing to keep pace with breakneck supply growth, the spread between Asian and European spot LNG prices have shrank to the point where Asia no longer commands an adequate gas premium for LNG exporters, which led to a diversion of spot LNG to Europe.

China, the global gas superpower

Comprehensive overview of the LNG value chain


Source: IGU, DBS Bank

Though Europe has traditionally been a dumping ground for LNG, the region has been particularly instrumental in soaking up new cargoes this year, with global exports to the region swelling to 51 tonnes (+130% y-o-y) in the first six months of 2019. However, absorption of excess supply by Europe may soon come to an end as the region’s storage capacity approaches its limits.

Historical LNG net imports (2011-2018)


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Historical LNG imports (including re-imports) 2019 YTD

Source: Poten & Partners, DBS Bank

US exports shifted to Europe amid spread compression

Europe’s gas storage is filling up at an incredibly fast pace


Source: Bloomberg Finance L.P., DBS Bank

Source: Gas Infrastructure Europe, DBS Bank

Will cross-border pipeline gas pose a threat to LNG demand growth?Despite the proliferation of LNG, there are still many countries that are heavily dependent on pipeline gas today. In Europe, Russian and Norwegian pipeline exports constitute the majority of gas supply in countries like Germany, France, Italy and Turkey, while in North America, US pipeline gas makes up the bulk of Mexico’s gas supply. In central Asia, pipeline gas from Turkmenistan, Uzbekistan and Kazakhstan have been crucial in facilitating China’s transition away from coal.

Over the next five years, we anticipate cross-border pipeline capacity additions of around 120bcm, 80bcm and 45bcm in Europe (Russia and Azerbaijan to Europe), North America (US to Mexico), and North Asia (Russia to China) respectively.

Even with more cross-border pipelines surfacing in Europe, we believe LNG will take market share away from pipeline gas in the region for several reasons:

1. LNG can help allay energy security concerns as many countries in Western Europe are overly dependent on Russia for its gas supply (granting Moscow considerable political leverage

2. Expiry of around c.50bcm worth of long term pipeline contracts over the next seven years, coupled with ample unutilised regasification capacity in the region suggests that Europe could readily pivot towards LNG

3. Europe is well positioned to benefit from the favourable LNG price environment as it is best suited to accommodate the incoming flood of US LNG due to its proximity compared to Asia

4. Gas pipeline exports to Europe from Azerbaijan will require time to gain traction as the country’s domestic gas production is not growing fast enough

Pipeline gas exports play an important role in Europe, China and

Mexico

Relevance of pipeline gas in Europe should

fade gradually

Pipeline gas accounts for around 45% of Europe’s gas supply; Russian pipeline gas makes up 35% of gas supply in Europe

Source: BP PLC, DBS Bank


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LNG import terminals among European countries are relatively underutilised…

…allowing them to shift towards LNG as fixed pipeline contracts expire over the next seven years


Source: EIA, DBS Bank

On the demand side, favourable government policies and more coal-to-gas switching will increase the share of natural gas in China’s energy mix – the Government has set a target of 10% by 2020, and 15% by 2030, up from 7.4% in 2018. While domestic supply will grow at a faster pace over the next few years with the government’s call for the national oil companies to accelerate upstream activity, we still expect supply growth to trail demand growth due to inherent challenges in the upstream sector.


While China might yield decent results in boosting conventional and tight gas production, more time is required to climb the steep learning curve to unlock its shale and coal bed methane gas reserves in a more cost-effective manner without subsidies, according to Woodmac. Testament to the difficulties in shale gas, BP, the last of the international oil majors involved in China’s shale gas development, recently exited the country in April-2019 after drilling eight to ten wells in Sichuan with disappointing results.

One major obstacle in China’s natural gas infrastructure is its severe lack of storage capacity – the country’s total underground storage capacity available for peak shaving of 10bcm (as at end-2018, excluding tank capacity at LNG receiving terminals) only accounted for a mere 3.5% of total gas consumption, which is drastically lower than the international average of 15%, according to IHS Markit. As storage bottlenecks are unlikely to be resolved in the near to medium term, LNG is the only alternative to manage sharp supply deficits during winter months, when gas demand can be double the average daily consumption.

CNPC – which accounts for around 69% of China’s gas production – might have set an overly ambitious shale gas target

Source: PetroChina, DBS Bank


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China’s import dependency trending up as production lags demand

Asia’s (excluding China) gas production remained flat from 2010

While cross-border pipeline gas could adversely impact LNG demand in Europe and China, we believe prospects in other parts of Asia are murky at best. Natural gas production within Asia (excluding China) is gradually diminishing and is likely on a long-term structural decline, discouraging the development of new intra-region pipeline gas connections. The Trans-ASEAN gas pipeline project has made little progress in recent years due to a lack of stable feed gas supply from Indonesia, according to S&P Platts, while the fate of the TAPI pipeline that was meant to bring gas to India from Turkmenistan remains uncertain.

In addition, the significant distance between the top natural gas producers and prominent gas demand centres like India, Thailand, Pakistan and Bangladesh renders pipeline connections to not only be economically unfeasible, but extremely time consuming as well. Furthermore, there are a host of other challenges with pipeline gas that can be overcome with LNG, such as an acute lack of flexibility in end markets, complicated geopolitical issues (particularly if the project involves a transit in another country), and narrow supply diversity.




LNG is more competitive for transportation distances beyond 1,000km (offshore) and 3,000km (onshore)

New cross border pipeline projects are concentrated in North America and Europe

Source: Delft University of Technology, DBS Bank

1: Despite securing funding, the project remains geopolitically contentious2: South Caucassus pipelineSource: McKinsey, DBS Bank

Cross-border pipeline projects expected to come online by 2023 Importing Country Exporting Country Gas Flow

PipelineExpected completion | Capacity

Nord Stream 21

2020 | 55 bcm

Turkish Stream1

2020 | 31 bcm

Power of Siberia1

2020-25 | 38 bcm

SCP2 - expansion2019 | 16 bcm

Mozambique & South Africa2025 | 5 bcm

Trans-Anatolian Pipeline(Tanap) 2018 | 16 bcm

US-Mexico 3 projects2018-19 | 60 bcm


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LNG regasification capacity and demand forecast till 2025We expect global nominal LNG import capacity to soar to 1,085mtpa in 2025 from 823mtpa in 2018, which is about 141mtpa higher than purely factoring in projects that are currently under construction. However, we estimate global underlying LNG demand, or weather-neutral demand, will grow at an even more rapid CAGR of 6.1% between 2018 to 2025, to 479mt from 317mt in 2018, owing to structurally higher regasification utilisation in Europe and the proliferation of LNG bunkering.

China will undoubtedly remain the most critical driver of LNG demand, and other Asian countries like Thailand, Pakistan, Vietnam and Bangladesh are expected to contribute in a big way as well, backed by an upswing in gas-to-power projects and depleting indigenous gas production. India’s role in the LNG growth story, while important, will be impeded to an extent by rising domestic gas supply, domestic infrastructure bottlenecks and intense competition from coal in the power sector.

Global nominal regasification capacity forecast by geography

Global LNG demand forecast by geographySource: IGU, DBS Bank



LNG project timeline and general trendsLNG import and export projects follow the same development phases, with the caveat that export terminals are more costly on a ton-for-ton basis, due to the need for expensive massive cooling and pressurisation equipment required for liquefaction. On an all-in basis, liquefaction projects also necessitate greater capital expenditure as they are often larger in scale with a relatively longer construction period. The sequence below describes the phases of an LNG liquefaction/regasification project:

• Pre-Front End Engineering Design (Pre-FEED)

After a basic screening and evaluation process, a pre-FEED is performed to derive an initial conceptual project design to prove its feasibility in technical and economic terms. This can be a slow process for a greenfield project, but is likely much shorter for expansion, like the addition of another train.

• Front End Engineering Design (FEED)

The FEED is used as the basis to better define the scope of the project to potential EPC contract bidders, and to obtain a more comprehensive project cost estimate and project schedule. Typically, the entire FEED (including pre-FEED) process takes around 18-24 months.

• Engineering, Procurement and Construction (EPC) bidding

Contractors receive the FEED package and submit bids based on their own internal cost projections. If a bidder does not approve of the technical specifications in the FEED package, they can propose changes and submit a bid and guarantees based on the revised FEED package. This stage usually takes around 3-6 months.

• EPC Phase

The EPC phase begins after the project developers have made a final investment decision. Depending on the scale and technical aspects of the project, construction usually takes around 48-60 months for export terminals and 36-48 months for import terminals.

According to Wood Mackenzie, less than 10% of global LNG liquefaction projects were constructed under budget, and 60% experienced delays to completion. Cost overruns in the previous boom averaged 33%, led by Australian projects which averaged 40%. On the regasification side, our study of 18 projects that were under construction as at Dec-16 exhibits a similar trend, with 70% of projects completing behind schedule with an average delay period of 1.5 years.

The LNG sector is notorious for lengthy

project delays and substantial cost

overruns


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Timeline of an LNG project varies widely between 48-108 months

Greenfield and Brownfield liquefaction projects delayed by 10 months and 6 months respectively, on average

Source: DBS Bank

Source: Wood Mackenzie, DBS Bank


What is the expected capital investment required for LNG import terminals in Asia?According to IHS Markit, the weighted average unit cost of new onshore and offshore LNG import capacity was US$274/mtpa and U$129/mtpa respectively in 2017 (based on a three-year moving average). Onshore regasification unit costs have been trending up in recent years, as project developers are adding more storage capacity per unit of send-out capacity to bolster supply stability. On the other hand, offshore regasification unit costs remained steady as the controlled environment in shipyard construction promotes cost stability.

Based on our earlier capacity projections, we estimate there will be around US$31bn of capital investments in LNG receiving terminals in Asia (excluding Japan, Korea, and Taiwan) between

Regasification projects are equally susceptible to interruptions and delays as well


Country Terminal name Target completion date

Actual completion date

Length of delay (months)

China Yuedong LNG (Jieyang) Dec-16 May-17 5

China Rudong Jiangsu LNG Phase 2

Dec-15 Nov-16 11

China Beihai, Guangxi LNG Dec-15 Mar-16 3

Greece Revithoussa Dec-16 Dec-18 24

Philippines Pagbilao import terminal Mar-16 Uncompleted 43

Poland Swinoujscie Jun-14 Jun-16 24

China Dalian Phase 2 Dec-16 Nov-16 Completed in time

France Dunkirk LNG Dec-15 Jan-17 13

China Tianjin (Sinopec) Phase 1 Sep-17 Apr-18 7

China Tianjin (onshore) Dec-16 Oct-18 22

India Mundra LNG Dec-16 Uncompleted 34

India Dahej LNG (Phase 3-A1) Dec-16 Sep-16 Completed in time

Thailand Map Ta Phut Phase 2 Jun-17 Jun-17 Completed in time

China Shenzhen (Diefu) Dec-15 Aug-18 32

China Fujian (Zhangzhou) Dec-17 Uncompleted 22

China Zhoushan Dec-16 Oct-18 22

Korea Boryeong Dec-16 Jan-17 1

Japan Soma LNG Dec-18 Mar-18 Completed in time


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2018-2025. China and India will account for the lion’s share at around US$10bn and US$7bn respectively, while the remaining US$14bn is split between other Asian countries like Pakistan, Bangladesh, Thailand and Vietnam.

What other trends do we expect in LNG receiving capacity build-up throughout 2025?We foresee three trends in the build-up of LNG receiving capacity playing out in the medium to long term.

• Floating regasification terminals should continue on its current growth trajectory to make up around 17% of global regasification capacity by 2025. The inevitable shift towards FSRUs should more than offset cost inflation and drive the blended unit cost of new import capacity down.

• The composition of both LNG buyers and LNG regasification terminal owners is set to become more fragmented amid market liberalisation in key Asian markets to allow third party access to LNG import terminals and the advent of new LNG buyers other than the traditional buyers in Northeast Asia.

Terminal owners will install more on-site infrastructure to allow for more value-added services. LNG import terminals are gradually transiting towards a hub model, where LNG is not only regasified and distributed via the conventional distribution pipeline network, but also through other mediums like bunkering and truck loading. Other services that import terminals will increasingly offer include LNG reloading and transhipment, and cold energy integration, where waste cold energy released from LNG regasification is exploited for power production and district cooling.

Onshore vs offshore capex comparison


Onshore


Global regasification nominal capacity composition (by sector)

Global regasification nominal capacity composition (by owner)




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LNG supply and Liquefaction Forecasts

What is the present LNG supply situation? The world is currently awash with LNG, following the tidal wave of liquefaction terminals coming online from 2016. A grand net (additions less decommissioned) total of 85mtpa of nominal liquefaction capacity entered the system in 2016-2018, underpinned by growth in Australia (46.4mtpa), the United States (23.3mtpa) and Russia (11.0mtpa). The last time the world witnessed such dramatic capacity growth was back in the period of 2008-2010, when Qatar drastically expanded its nameplate liquefaction capacity to 69.2mtpa in 2010 from 30.2mtpa in 2008. To exacerbate the situation, several notable LNG export projects, like Ichthys LNG in Australia and Yamal LNG in Russia are running ahead of schedule (faster than expected project completion and capacity ramp-up), introducing more LNG supply while the world struggles to digest the current supply.

Source: McKinsey, DBS Bank

LNG import terminals are gradually shifting away from traditional business models and offering more value-added services

Exhibit 1: Overview of regas services along the value chain

Usually sold as bundled service

Operational: regulated services Unloading/berthing LNG storage Regasification (send-out)

Other: unregualted services Technical services:gassing-up, cooling down

Transhipment

Reloading

Quality assurance or adjustment:eg. , to commercial grade

Small-scale LNG: bunkering, truck loading, break bulk

Cooling services:for industrial or integrated power plants

Peak shaving

Virtual liquefaction

Berthing Storage Gasification/processing Transfer


When will the supply glut come to an end?The oversupply situation will likely only end in 2022-2023, due to the culmination of macroeconomic uncertainty putting a dampener on demand growth and another substantial wave of LNG liquefaction terminals turning online in 2019 and 2020. Protracted trade tensions between the two largest nations in the world, coupled with a broader macroeconomic slowdown will likely translate into slower gas demand growth in the short run. Meanwhile on

Historical nominal liquefaction capacity by geography

Global nominal liquefaction capacity composition (by owner)




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the supply front, a staggering 123mtpa (32% of global liquefaction capacity as at end-2018) of liquefaction capacity will be added between 2018-2025, assuming that projects under construction are completed according to schedule and no new projects are sanctioned during the period. Yet, bulk of the new terminals (71mtpa) will be coming onstream in 2019 to 2020, meaning the spurt in supply will likely exceed the increase in demand over the next two years by a wide margin.

Projects under construction as at Dec-18

Global nominal liquefaction capacity composition (by sector)




Are LNG suppliers likely to throttle export utilisation to manage excess supply?Due to the high degree of fixed costs involved in liquefaction, LNG exporters will continue sending out excess cargoes (supply that is not backed by long term contracts) or spot cargoes as long as the spot price received covers all variable operating costs or the marginal cost of production. The discussion here will be centred on US LNG, given that incremental global LNG deliveries over the next two years will be largely driven by US LNG - US LNG liquefaction capacity is projected to skyrocket to 71mtpa in 2020, from 23mtpa in 2018, and account for c.65% of global liquefaction capacity additions during the period.

After months of surplus LNG in the market, spot LNG prices are fast approaching the short run marginal cost (SRMC) of US LNG in both Asia and Europe after a brief dip below this level during certain months. However, the temporary slide in spot prices below US SRMC has not triggered a response from the US LNG plant owners, despite them incurring operating losses from unrestrained exports. We believe that it will take either:

a. A sustained decline in European and Asian spot LNG prices to below their respective US SRMC level beyond the start of winter this year, or

b. A decline in spot prices to below US SRMC less variable transportation costs (majority of LNG carriers are on long term charters and have to be paid) before we see a negative adjustment in US LNG deliveries

Of course, there are other factors in play - project owners will react differently depending on their hedging strategy, cost competitiveness of their projects (projects that can secure relatively cheaper feed gas will have a strong edge) and the extent of integration through the LNG value chain (able to market spot cargoes across various markets with greater ease). On the macro front, easing trade tensions between China and the US would stimulate demand for more spot cargoes, especially if China removes the 25% tariff imposed on US LNG.


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Tellurian can potentially deliver LNG FOB at US$1.35/mmbtu (excluding financing) by tapping on cheap Permian gas

US exports will continue unabated as long as producers can cover variable costs

Source: Tellurian, DBS Bank

Source: Bloomberg Finance L.P., DBS Bank

$1.50(1)

$0.75

$0.22

$0.79

$0.36

$0.88 $0.70 $0.50

$0.36

$0.79

$0.35

$0.15

$0.50

$0.50

Debt

Base case

Ups

trea

m

Opimistic case Permian gas

Liquefaction

Contingency

Gathering, processing & transportation

Lease operating

Drilling & completion

$1.00

$1.00

$2.35/mmBtu

$3.50/mmBtu

$4.50/mmBtu


Global nominal LNG liquefaction capacity and LNG supply forecastsWe anticipate global nameplate LNG liquefaction capacity and global LNG exports to reach around 588mtpa and 485m tons in 2025 respectively. More projects are expected to take final investment decisions (FID) between now and 2021, and complete construction by the end of our forecast horizon in 2025. This translates into an additional 100mtpa of capacity on top of the 110mtpa of capacity currently under construction (as at end-2018).

Within the seven-year period between 2018 and 2025, most of the capacity growth will primarily be driven by the oil supermajors and national oil companies (NOCs), owing to their keen ability to adapt to rapidly evolving industry dynamics. On a country level, those having favourable long run marginal cost LNG profiles like Qatar, Russia, and the United States will lead the charge. Newcomers like Mozambique and Canada are also expected to make a big splash towards the end of our forecast period (2024/25)IGU and become solid contenders in the LNG market.

There are several factors that could delay or even constrain the development of global LNG export capacity. First and foremost, prolonged weakness in spot LNG prices below the long run marginal cost (LRMC) of LNG projects, could prompt project owners to re-evaluate their plans.

Most notably, proposed projects that we expect to come onstream during our forecast period might fail to reach the FID stage, while projects under construction may not come online in a timely manner for a number of reasons, including: i) inability to secure sufficient long term offtake agreements with creditworthy counterparties could stifle access to financing, ii) the sheer complexity of designing, building and commissioning LNG terminals (though we have included a time buffer for each project as the LNG sector is notorious for extended project delays), especially for greenfield projects and iii) other development risks like extensive regulatory requirements.

What are the key risks to our projections?


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Global nominal liquefaction capacity forecast by geography

Global LNG supply forecasts by geography




LNG Liquefaction Terminals

FLNGs, or floating liquefied natural gas facilities, are offshore facilities used for natural gas operations. Using subsea equipment, they extract natural gases from subsea gas fields before liquefying, storing, and offloading them to LNG carriers. FLNGs are mainly used when it is not feasible to install undersea pipelines to connect the gas fields to onshore terminals.

Benefits of FLNG facilities

First, they do not require platform jackets and minimise pipeline installations. FLNGs are also frequently adopted when:

1. The ground surrounding the project field is insufficiently solid

2. The project is located in deep water fields or far away from land

In addition, given that FLNGs are built in shipyards before being deployed at project sites, managing their construction process is easier compared to large-scale on-site facilities, which is typically the case for land-based gas field projects. Moreover, given that FLNGs are floating facilities, they can be moved or redeployed at other fields.

As it has not been long since FLNGs were first introduced, there are currently only three shipbuilders in the world that boast FLNG construction track records - Samsung Heavy Industries (SHI; three facilities), Daewoo Shipbuilding Marine Engineering (DSME; one facility), and Keppel Corporation (two facilities).

Key LNG Asset Classes

Regasification projects are equally susceptible to interruptions and delays as well

Project name Operator Installation area Targeted operation

Annual output (mn tons)

Remarks

Kribi FLNG Golar LNG Cameroon 2018 2.4 Remodeled existing LNGC (Keppel Corporation)

PFLNG Satu Petronas Malaysia 2018 1.2 Built new ship (DSME)

Prelude FLNG Shell Australia 2018 3.6 Built new ship (SHI)

Rotan FLNG Petronas Malaysia 2020 1.5 To build new ship (SHI)

Coral South FLNG Eni Mozambique 2020 3.4 To build new ship (SHI)

Gimi FLNG Golar LNG Mauritania / Senegal

2022 2.5 To remodel existing LNGC (Keppel Corporation)

Source: NH I&S Research Center


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Amid rising natural gas consumption, we expect to see more natural gas exploration-related offshore development projects. According to International Energy Agency (IEA) statistics, only 13% of the remaining crude oil reserves are located underwater. However, out of the remaining natural gas reserves, 36% are underwater. Furthermore, out of remaining natural gas reserves on land, 71% are trapped within shale formations. Accordingly, without offshore gas field operations or shale gas projects, developers will likely secure only a limited amount of natural gas.

Global crude oil reserves

Global natural gas reserves

Crude oil reserve breakdown

Natural gas reserve breakdown

Discovered (bbl)

Drilled(bbl)

Remaining (bbl)

Portion of remaining reserves

Total 7,537 1,390 6147 81.6%

Onshore 2,247 885 1,362 60.6%

Nearshore 795 299 496 62.4%

Deep sea 302 28 274 90.7%

Shale formations/ others

4,193 178 4,015 95.8%

Discovered (tcm)

Drilled(tcm)

Remaining (tcm)

Portion of remaining reserves

Total 920 122 798 86.7%

Onshore 234 86 148 63.2%

Nearshore 179 22 157 87.7%

Deep sea 132 4 128 97.0%

Shale formations/ others

375 10 365 97.3%

Note: bbl = billion barrelsSource: IGU, NH I&S Research Center

Note: tcm = trillion cubic metresSource: IGU, NH I&S Research Center

Expanding natural gas consumption driving up deep sea gas field

projects


Natural gas production to be led mainly by shale gas developers, but the FLNG market is also set to expand. While more offshore gas field projects using FLNGs are coming into the limelight, they still lag shale gas projects in terms of natural gas production volume. We note that around two-thirds of newly operating natural gas production/liquefaction facilities are in North America. Also, about 46% of global natural gas reserves are held in shale formations, which are mainly found in North America. According to Energy Information Administration (EIA) statistics, US shale gas production climbed 18.8% y-o-y in 1H19, accounting for 61.1% of US natural gas production.

17% of planned LNG development projects predicted to use FLNGs. While natural gas production will likely continue to be spearheaded by shale gas developers, we believe the FLNG market will also expand, given that: 1) 67% of natural gas reserves (excluding those within shale formations) are located underwater; and 2) 45% of underwater reserves are held in deep sea areas (where explorations are not feasible without FLNGs). In fact, 17% of new LNG development projects are planning to employ FLNGs.

US natural gas production volume

Proportion of projects planning to use FLNGs

Global natural gas production volume

Expected FLNG installation breakdown by region

Source: EIA, BP Statistics, Clarkson, NH I&S Research Center

Source: IGU, NH I&S Research Center


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We believe additional FLNG orders are likely to be placed. There are currently at least 25 projects in the proposed phase that are expected to adopt FLNGs. Given that the inaugural FLNGs have been in operations since 2018, development/operational costs for gas field projects using FLNGs are being evaluated and analysed. If these projects using FLNGs prove to be cost efficient, FLNG adoption is likely to increase.

Planned FLNG orders

Projects planning to adopt FLNG

Average project costs, by project type



Project name Operator Installation area Targeted year Annual output (mn tons/year)

Stewart Energy Stewart Energy Group Canada 2019 5.0Kitsault Kitsault Energy Canada 2019 8.0Orca Orca LNG Canada 2019 4.0Cedar Haisla First Nation Canada 2020 6.4Cambridge Energy Cambridge Energy US 2020 7.5Delfin Fairwood LNG US 2020 12.0Main Pass Energy Hub Freeport-McMoran Energy US 2020 24.0Djibouti Poly-GCL Djibouti 2020 3.0Fortuna Golar Equatorial Guinea 2020 3.0Congn-Brazzaville New Age Democratic Republic of the Congo 2020 1.2Scarborough ExxonMobil Australia 2021 6.5Barca Barca LNG US 2021 12.0Eos Eos LNG US 2021 12.0Gorskaya Unannounced Russia 2021 1.3Point Comfort Lloyds Energy Group US 2022 9.0Avocet Fairwood LNG US Unannounced 3.3Malahat Steelhead Group Canada Unannounced 6.0Bonaparte ENGIE Australia Unannounced 2.0Browse Woodside Australia Unannounced 4.5Cash Maple PTTEP Australia Unannounced 2.0Crux Shell Australia Unannounced 2.0Poseidon ConocoPhillips Australia Unannounced 3.9Sunrise Shell/Woodside Australia Unannounced 4.0East Dara Black Platinum Energy Indonesia Unannounced 0.8Pandora Cott Oil & Gas Papua New Guinea Unannounced 1.0


Average project costs, by project type

LNG Receiving Assets

Like gas liquefaction, there are both onshore and floating solutions to regasify LNG, but the key difference is that floating regasification technology is not only more established, but more straightforward and better understood by market participants as well.

The LNG regasification process is generally similar across both land and offshore configurations - LNG is firstly unloaded from LNG carriers into cryogenic storage tanks, then pumped into a vaporiser unit where it is vaporised by heat exchange using seawater, and finally metered and delivered to the gas distribution network. However, a land-based concept could contain additional functions like LNG bunkering and reloading services and typically has larger storage capacity.

Today, while land importing terminals still make up the lion’s share of global regasification capacity, we are seeing good momentum in floating regasification units, primarily in emerging markets like Pakistan, Turkey, and Bangladesh in recent years. This has propelled its market share to around 12% in 2018, up substantially from 5% in 2010.

UnloadingArms or Hoses

BOG CompressorFuel gas

Recondenser

Vaporisers

HP Pumps

In-tank LP PumpsFSRU Tanks

Supply Tanker

Gas Metering & Export

Typical FSRU flow scheme

Source: The Oxford Institute for Energy Studies, DBS Bank


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Source: DBS Bank

Source: IGU, Clarksons, DBS Bank


Comparison between land terminals and FSRUs

Historical onshore and floating regasification capacity

Breakdown of new LNG importing countries (2010-2018) – Shaded names represent those with FSRUs

Historical and expected FSRU delivery schedule

Land-based terminals FSRUsGreater storage and regasification capacity – Crucial when storage and send-out capacities are of strategic importance to the market, or when the terminal is used to serve a large market.

Shorter project lead times – FSRUs are typically constructed within 24-36 months, while conversion usually takes around 12-18 months. With redeployment, the world’s fastest FSRU project was implemented in a span of 5 months from project inception to first gas.

Lower operating costs – More economical in the long-run, despite a substantial initial capital outlay. Land-based terminals tend to be more economically viable for projects lasting beyond 12-15 years.

Significantly lower capital investment – FSRUs can be completed at a significantly lower cost (30-50% less) than land-based alternatives. Additionally, vessels can be leased and redeployed or even function as an LNG carrier.

High local content value – Job creation via operation of the regasification terminal can be a compelling reason for governments to support the project

Less regulatory constraints – Offshore permits for FSRUs are easier to obtain, as it does not require a massive land area unlike its onshore counterparts

Ease of expansion – To meet rising gas demand, subject to land availability

Shipyard construction – Enables better project management and cost control, given that construction is performed in a controlled environment

Less susceptible to supply disruptions – Less affected by inclement weather, and large storage capacity ensures stable supply

2010 2011 2012 2013 2014 2015 2016 2017 2018UAE Thailand Indonesia Malaysia Lithuania Pakistan Poland Malta Bangladesh

Netherlands Singapore Jordan Jamaica Panama

Israel Egypt Colombia


Historical and expected FSRU delivery scheduleWhy are FSRUs preferred in new emerging markets?The impetus for choosing floating over land alternatives is multi-fold, but financing constraints tend to be the most critical factor in developing countries. The immediate capital outlay for a mid-scale (c.3mtpa) land terminal and other onshore infrastructure usually falls in the range of US$600-750m, a substantial amount that necessitates foreign capital for project financing. However, financing tends to be costly for emerging markets with elevated country and default risks. Electing to use FSRUs can help developing countries circumvent financing challenges, since FSRU projects require 30-50% less outlay than a land terminal with similar specifications. Furthermore, chartering a FSRU, rather than an outright purchase, can reduce investment costs even further, and also mitigate potential cash flow mismatches, as the timing of revenue inflows will be more consistent with operating costs (which forms the majority of cash outflows).

Economic analysis of regasification conceptsProject feasibility aside (factors like minimum required send-out or storage capacity/land availability/regulatory constraints), the economic viability of the project is the most crucial factor in the selection process. On this basis, we anticipate FSRUs to continue to be the preferred option by markets seeking quick and short-term access to natural gas. This is substantiated by our project finance analysis which suggests that FSRUs are more cost-efficient for projects (assuming similar send-out and storage capacities) not exceeding 12 to 15 years, a moderately higher duration than IGU’s estimated breakeven period of 8 to 10 years, which was based on a simplistic undiscounted payback period analysis that assumes all capex would be incurred in year 0 and excludes all financing costs.

Global FSRU owner (left) and builder market share (right) as at Sep-2019 by count

Source: Clarksons, DBS Bank


37

Total cost comparison between land-based and floating terminals

Summit LNG FSRU cost component breakdown (figures in US$m)

Source: Excelerate Energy, DBS Bank


Outlook for FSRUsAs at June-2019, there was 28.4mtpa of offshore capacity in the construction phase, while proposed FSRU projects that have yet to reach the FEED stage totalled about 132mtpa. Despite a pause in FSRU newbuild contracts in 2019 thus far, we maintain a sanguine outlook on the development of FSRUs globally, and expect floating terminals to account for around 17% of total regasification capacity by 2025, from 11% in 2018. Future FSRU capacity could surpass our estimates as unsanctioned projects may start up during our forecast period due to the relatively short construction timeframe of FSRUs.

LNG Carriers

Demand for LNGCs to pick up in line with greater LNG use. Bullish LNG market conditions bode well for related shipping players and builders.

Owning 45% of the overall global LNGC fleet, European shipping companies currently take up 60% of global LNGC orders. As these companies are mostly owned by individuals or families, they tend to take a conservative stance towards technologies and markets, and hence there is typically less impact from optimism that continues to haunt other commercial shipping markets.

While spot contracts are increasing, long-term contracts still represent the lion’s share of the LNG shipping market. Long-term contracts suit the tastes of the conservative shipping companies, reducing the possibility of excessive LNGC order placement.


European ship owners typically take

conservative stance on technologies and

markets


39

Source: Clarkson Research, NH I&S Research Center


LNGC with membrane-based containment system

Breakdown of LNGC owners by nationality

LNG fleet by shipping company (existing + on order)

LNG shipping contracts by long term vs spot/ short term


LNG fleet by shipping company (existing + on order)

LNG shipping contracts by long term vs spot/ short term

Global marine LNG trade volume is set to expand at a CAGR of 9.5% over 2018 to 2019. Owing to the US-China trade dispute, LNG trade volume between the two countries over 2018c. 2019 is likely to tumble by 66% compared to before the dispute broke out. Despite this, global LNG trade volume remains on the rise, suggesting that issues such as the US-China trade dispute will not affect the changing global energy mix trend.

While LNGC orders upped over 2017c. 1H19, the rise was not excessive in light of the outlook for trade volume growth. Most of the recent LNGC orders are expected to be delivered by 2022. Over 2018c. 2022, LNG shipping capacity is predicted to climb 31.4%, on par with the projected LNG export growth of 28.4% over the same period.

We note that there are only a few orders for LNGCs scheduled to be delivered after 2022. Based on the average construction time for LNGCs, we believe LNGC orders between 2019-2022 will likely expand by 33.7% (shipping capacity basis) compared to the 2018-2019 average to meet demand in 2023-2025. Such an increase in newbuilding orders will benefit the shipbuilding market.

Amid rising LNG shipping demand, ship

supply appears to be still insufficient

Global LNGC supply-demand dynamics

2017 2018 2019E 2020F 2021F 2022F 2023F 2024F 2025FExport volume (mt) 288 317 358 387 402 409 421 443 485

New demand (mt) 25.2 28.2 41.9 28.6 14.9 7.1 11.8 22.2 41.9

Shipping demand growth (%) - A

9.1 9.8 13.2 8.0 3.9 1.8 2.9 5.3 9.5

Global fleet at beginning of year (mn m3)

64.3 69.2 73.7 82.0 88.5 96.9 98.2 97.8 97.2

Newbuilding (mn m3) 5.2 5.0 8.8 7.0 9.0 1.9 0.2 0 0

Demolition (mn m3) -0.3 -0.5 -0.5 -0.5 -0.6 -0.6 -0.6 -0.6 -0.7

Global fleet at yearend (mn m3)

69.2 73.7 82.0 88.5 96.9 98.2 97.8 97.2 96.5

Shipping capacity growth (%) – B

7.6 6.5 11.3 7.9 9.5 1.3 -0.4 -0.6 -0.7

Supply-demand balance (%) - (A-B)

1.5 3.3 1.9 0.1 -5.6 0.5 3.3 5.9 10.2



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Surge in US LNG cargoes to propel

demand for LNGCs


Source: Cheniere Energy, NH I&S Research Center

Global LNG export volume

US LNG export volume

Global LNGC supply forecasts (based on order backlog)

US LNG exports to China

Since the US began exporting LNG, approximately 1.8 ships have been needed for each 1mtpa of supply, which is considerably greater than the global average shipping multiplier of 1.3x. According to S&P Platts, the average distance covered by a laden LNG ship from the US stood at 9,268nm in 2018, compared to 3,936nm and 5,602nm for Australia and Qatar respectively, highlighting the vast distance between the US and central demand points. Hence, we expect the global average shipping multiplier to continue trending up as the US powers ahead in supply, which should further propel the demand outlook on LNGCs.


Global LNGC supply forecasts (based on order backlog)

US LNG exports to China

Demand for LNGCs is expected to pick up, and the market penetration of super-sized LNGCs is set to strengthen. At present, LNG shipping players mainly use shipping routes passing through the Panama Canal and Suez Canal. Thus, the global LNGC fleet is now mainly composed of 160c. 174kCBM Panamax vessels that are able to pass through the canals. However, expected changes in shipping routes should lead to greater demand for super-sized LNGCs (larger than Panamax ships).

Once more natural gas pipelines in the US are developed, LNG will be able to be exported from ports in the US West Coast, a development which would lower the need for LNG carriers to pass through the Panama Canal. Australia-Asia trade routes will also likely generate demand for bigger LNGCs.

With the anticipated rise in global LNGC orders highlighting the importance of LNG carriers’ containment systems, the holders of proprietary technologies in the area of LNG storage systems are drawing strong market attention. Given the high entry barrier to the LNG containment system market, players equipped with accumulated technological knowhow and boasting solid track records are to enjoy the benefits of the reviving global LNGC market for the long haul.

Shipping route changes to spark demand for

super-sized LNGCs

Rising LNGC orders will also spur demand for LNG containment

systems

No. of LNGCs required for each mtpa of US LNG has been increasing amid growing exports to Asia

Source: Gaslog Ltd, NH I&S Research Center


43

LNG containment system technology comparison

Note 1: Membrane: In the shipbuilding sector, ‘membrane’ refers to a design technology that installs insulation between the tank and the hull Note 2: BOR stands for boil off rate, the amount of liquid that is evaporating from a cargo due to heat leakage and is expressed in % of total liquid volume per unit time; the

lower the BOR, the greater the superiority of the containment system

Source: GTT, NH I&S Research Center

GTT (France) Moss (Norway) SPB (Japan) KC-1 (Korea)Technology Membrane1 Spherical tank Tank Membrane

Construction costs Requires less steel and aluminum than tanks for a given LNG capacity

Higher costs (versus GTT)

Higher costs (versus GTT)

Similar to GTT

Operating costs More efficient use of space

Australia 2018 3.6

LNGCs 453 130 4 2

Other factors Value added services High center of gravity; harder to navigate

Huge losses and delays on vessels in order book; no significant experience

Little experience at sea


The Korean shipbuilding industry will be a primary beneficiary of the anticipated increase in global LNG carrier demand. In 2018, Korean shipbuilders bagged more than 90% of global LNGC orders, and in 1H19, their share in the global LNGC market reached roughly 80%. We note that:

1. Almost all 1H19 LNGC orders (excluding those from China and Japan) were awarded to Korean shipbuilders

2. New large-scale LNGC orders are all expected to come from countries other than China and Japan

Korean yards have been dominating the LNG carrier market, which is widely recognised for its high technical barriers owing to characteristics of highly flammable LNG that needs to be stored at super low temperatures at below -160°C with low specific gravity (0.43 to 0.50). Korean-built LNG carriers (>40k cbm) account for c. 71% of the existing global fleet and their dominance has continued to climb over the past 10 years. Korean yards’ market share has expanded to 83% based on deliveries in 2015-2019 and further increases to a whopping c. 90% based on the current orderbook for LNG carriers.

On the other hand, Japanese yards’ market share of the LNG carrier newbuild market has plunged from c. 20% based on the existing LNG carrier fleet to a mere c. 2% by current orderbook. In general, Japanese yards have been losing cost competitiveness in shipbuilding as the nation struggles with an aging population and labour shortages, particularly for the shipbuilding industry, leading to yard closures and shrinking capacity. Japanese yards are now partnering with Chinese yards to lower cost. In view of the intensifying competition, Japanese shipyards are focusing on higher added-value tonnage and technological R&D as well as shifting production to China through JVs with Chinese shipyards to streamline cost.

A handful of established Chinese yards are also emerging in the LNG carrier shipbuilding market. Initially, they were beneficiaries of LNG carriers ordered by Chinese shipping company - China LNG Shipping International (CLNG) but have since then diversified their customer base to include other global LNG fleet owners.

Qatar Petroleum may consider giving some orders to non-Korean yards for its newbuild LNG carrier campaign. In April 2019, Qatar Petroleum, the world’s largest LNG producer, had issued

Beneficiary of Booming Demand for Gas Solutions

Korean shipyards set to be prime beneficiary

Leading Chinese and Singapore shipyards set to enjoy some spillover

effects


45

an invitation to tender for the reservation of ship construction capacity required for a fleet of over 100 LNG carriers, with plans to take delivery of 60 LNG carriers to support its current planned production expansion and the remaining over the next decade. The last time Qatar Petroleum embarked on orders of this scale for vessels was back in 2004-2007, and South Korea’s big three yards won all the contracts. However, we do not rule out the possibility of some spillover orders to the Japanese and Chinese yards this time.

In terms of FLNG orders, Korean yards – Samsung and DSME – enjoy first mover advantage in large scale newbuild FLNG vessels while Singapore’s Keppel successfully delivered the world’s first FLNG conversion vessel in October 2017. A Chinese yard, Wison, has successfully delivered a FLNG barge in 2017. FLNG vessel is a relatively new concept and is a cost-efficient alternative to onshore processing plants for gas fields that are further from the shore. There are currently four FLNG vessels in operation and four on order. Korean yards dominate the FLNG newbuild space, while Singapore yards focus on FLNG conversion projects. As Chinese companies play a major role in several FLNG developments, either as investors or off takers, we could expect some future order wins to be clinched by Chinese shipyards as well.

Potentially higher global LNG carrier demand also bodes well for technology and solutions providers. For example, regardless of which shipbuilding company wins a new LNG carrier order, the provider of LNG containment system technologies will receive royalties on its patents. In addition, suppliers of insulation systems for LNG carriers are also set to benefit from the flow of LNG carrier orders at shipbuilders.

Korea’s Winning Formula

We have identified three key critical factors that Korean yards exhibit which are hard to beat:

1. Cost Competitive

According to industry sources, Korean yards have been reducing the cost of building LNG carrier ships to as low as US$175m while Japanese ships are probably costing more than US$200m. Chinese yards’ lack of experience and economies of scale in building LNG carriers have offset the lower labour cost advantage.

2. Technological Edge

Korean yards have been fast in responding to the rapid technology shift, for instance shipowners’ growing preference towards membrane-type LNG cargo containment system, which utilises the hull shape more efficiently compared to the traditional moss-type tanks that became the industry norm since 1973. Korean yards are able to offer the Q-Max vessel, the largest class membrane-type carrier that can load up to 260,000 cbm of LNG versus 182,000 cbm on the largest moss-type tanker.


3. Track Record

Further cementing the grip for South Korean yards is their track record of building the most sophisticated vessels, which has made them the go-to yards for LNG carriers. SHI and DSME especially have strong competitiveness in vessels for North Pole Route since these yards have delivered several icebreaker LNG carriers and icebreaker drillships.

Source: Clarkson Research, DBS Bank

Korea yards delivered c. 25 large-sized LNG carriers (>150k cbm) a year in 2016-2019E


47


49


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Disclaimers and Important Notices

The information herein is published by DBS Bank Ltd (the “Company”). It is based on information obtained from sources believed to be reliable, but the Company does not make any representation or warranty, express or implied, as to its accuracy, completeness, timeliness or correctness for any particular purpose. Opinions expressed are subject to change without notice. Any recommendation contained herein does not have regard to the specific investment objectives, financial situation and the particular needs of any specific addressee.

The information herein is published for the information of addressees only and is not to be taken in substitution for the exercise of judgement by addressees, who should obtain separate legal or financial advice. The Company, or any of its related companies or any individuals connected with the group accepts no liability for any direct, special, indirect, consequential, incidental damages or any other loss or damages of any kind arising from any use of the information herein (including any error, omission or misstatement herein, negligent or otherwise) or further communication thereof, even if the Company or any other person has been advised of the possibility thereof.

The information herein is not to be construed as an offer or a solicitation of an offer to buy or sell any securities, futures, options or other financial instruments or to provide any investment advice or services. The Company and its associates, their directors, officers and/or employees may have positions or other interests in, and may effect transactions in securities mentioned herein and may also perform or seek to perform broking, investment banking and other banking or financial services for these companies.

The information herein is not intended for distribution to, or use by, any person or entity in any jurisdiction or country where such distribution or use would be contrary to law or regulation.


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