A new Russian gas pipeline to China will curb its appetite for LNG imports, having a ripple effect on markets since the latter’s surging demand had led to price spikes globally, experts said on Wednesday.
“The cost of this pipeline gas will be very competitive compared to LNG imports,” Yanyan Zhu, general manager of trading at Chinese firm CNOOC, said on the sidelines of the CWC World LNG Summit conference in Lisbon.
Russia is expected to start deliveries of 38bcm of gas to China via the Power of Siberia pipeline in December 2019, the first of three pipelines that are planned totalling 80-110bcm/year, though the timing and capacity of the two other pipelines remains uncertain.
That compares to Chinese LNG imports in the first 10 months of 2018 of 41.6m tonnes (57bcm), a 43% surge year on year to a record high, above the 39m tonnes record set in 2017 when the country became the second biggest importer after Japan, overtaking South Korea.
End of surge
“I don’t think China will let that happen again,” said David Ledesma, an independent gas and LNG consultant, referring to last year’s surge in LNG imports.
LNG price evolution, domestic production and how quickly Russia ramps up flows, are likely to weigh on the volume of LNG imports to be replaced by Russian piped gas.
“Will they increase 10bcm per year? Or will they reach 38bcm in two years? We don’t know but the trend we’ve seen recently [in terms of LNG], will not continue,” Thierry Bros, senior researcher in Oxford Institute for Energy Studies, told Montel.
Russia would clearly have a “crucial role” to play, however, in meeting a Chinese “import requirement that is expected to rise from import 91bcm in 2017 to 170-340bcm by 2030”, added the institute in a recent report.
Chinese government policies to raise domestic gas production would also dent LNG imports, although many analysts cast doubt on the target of producing 247bcm by 2020, from 169bcm last year.
Zhu of CNOOC believed it would happen. “If the Chinese government wants to do something, their support is quite influential by offering favourable policies,” she said.
Indeed, China will raise its gas production and increase pipeline supplies, but LNG imports “will play a especially important role,” agreed Steve Hill, executive vice president of Shell. “Everything will grow, [although LNG imports] are going to slow down a bit.”
At the same time, however, while LNG supply could jump in the next five years amid a new wave of project builds, demand from key player Japan would decrease by a third as nuclear generation increases, said Keiji Takiguchi, deputy director of oil and gas in the country’s Ministry of Economy, Trade and Industry.
In 2019, the final investment decision 100m tonnes/year of LNG production (136bcm) would be made, said Hiroki Sato, senior executive vice president of the world’s biggest LNG buyer, Jera of Japan. “2019 is the start of drastic changes for our industry.”
In October, Montel reported that falling spot prices for LNG in Asia increased shipments of the fuel to Europe.
by Andrés Cala, November 29, 2018
via Montel https://www.montelnews.com/en/story/russian-gas-pipeline-to-curb-chinas-lng-appetite–experts-/958065
Having dominated pipeline natural gas supplies to Europe for decades, it’s taken Russia less than a year to become one of the region’s biggest sources of tanker-borne fuel.
That’s thanks to Yamal LNG, which last December started chilling gas into liquid in harsh Arctic conditions – a rare case of a production plant starting ahead of schedule. While market forces explain why so much of Yamal’s supply is ending up in Europe, instead of its main intended markets in Asia, the development may strengthen calls that Russia is too dominant in European energy.
“It makes sense to go to Europe, the market is there for us,” Mark Gyetvay, chief financial officer of Novatek PJSC, the majority shareholder of Yamal LNG, said last week in an interview at the CWC World LNG Summit in Lisbon.
The $27bn Yamal LNG project is liquefying gas at all three of its planned production units, which were brought online within less than a year. The whole project was built seven months quicker than originally planned, with the third plant setting a world record for LNG train construction, according to partner China National Petroleum Corp
While the buyers of that fuel can ship it anywhere in the world, the plant’s output is increasingly staying in the region, driven by market signals. In November, Russia was the biggest single supplier of LNG to northwest Europe.
LNG from the plant travels where prices are highest and it’s the buyers of the fuel who decide where the tankers unload. Last winter and to some extent in the summer, Yamal cargoes were mainly transferred in Europe from specialised ice-breaking tankers onto cheaper-to-operate conventional vessels for further journeys to Asia, South America and even the US Those moves have slowed as Asian benchmarks slid since October.
The European Union gets about a third of its gas from Russia and has looked at LNG, including from the US, as a way to diversify its supplies. That comes as Moscow-based Gazprom PJSC delivers record volumes by pipelines and starts building the Nord Stream 2 link, which will double direct supplies to Germany.
“Russian gas is flooding Europe, both via pipeline exports and new supply from Novatek’s Yamal LNG project,” Leslie Palti-Guzman, president of New York-based gas advisory Gas Vista LLC, said by e-mail. “With LNG demand sluggish in Asia, narrowing EU-Asia price spreads, and record-high tanker rates, Yamal LNG cargoes that would be re-exported to Asia under normal conditions will stay in Europe this winter.”
Europe, including Turkey, imported a record amount of LNG in November, according to Kpler SAS, which tracks commodity shipments.
“The perception of LNG dependency is lower, given that it can be sourced from the global market and doesn’t link the buyer to a particular supply route, like the Nord Stream 2 pipeline project would do,” Dumitru Dediu, an associate partner at McKinsey Energy Insights, said by telephone.
Novatek doesn’t rule out that more LNG will stay in Europe this winter due to the high cost of transporting cargoes via the Suez Canal while sea ice closes the Northern Sea Route for the season, Gyetvay said. The company may consider swapping arrangements for Asian delivery, he said.
“Eight years ago many people were saying ‘I don’t understand where Yamal is and I don’t understand how you are going to be able to ship from that location to market successfully,’” Gyetvay said. “Yamal is a tremendous success not only for Novatek, but for Russia, and now provides the country with a brand-new platform for LNG, the fastest-growing segment of the gas market.”
December 3, 2018
via Hellenic Shipping News Worldwide, reporting after Bloomberg https://www.hellenicshippingnews.com/russia-secures-top-spot-in-europe-lng-supply-december/
Some liquefied natural gas sellers aren’t in a rush to deliver their multimillion-dollar cargoes.
With uncertain demand and no signs yet of bitter cold, some traders are preferring to keep their fuel inside vessels in the hope prices will rise. While the sight of stationary cargoes might not be unusual in the more-established oil market, technology has only recently made it feasible to keep LNG at minus 162 degrees Celsius (minus 260 degrees Fahrenheit) for longer periods.
From Pipes to Tankers
LNG to overtake pipeline gas in global gas trade
“There are cargoes parked close to Singapore, apparently waiting for the right market conditions to be delivered,” said Dumitru Dediu, an associate partner at McKinsey Energy Insights, which monitors LNG flows. “Some of the players are speculating.”
There are about 30 vessels currently flagged as floating storage globally, two-thirds of which are in Asia, the biggest LNG consuming region, according to cargo-tracking company Kpler SAS. That’s still a fraction of a global fleet of more than 500 vessels.
The practice of using tankers as floating storage is common in the more developed oil market. It happens during periods of contango — when storage on land is used up, immediate demand is weak and the cost for later delivery is high enough to cover the expense of storing crude on a tanker.
Trading houses and oil majors from Vitol Group and Glencore Plc to BP Plc and Royal Dutch Shell Plc collectively made billions of dollars from 2008 to 2009 stockpiling crude at sea. At the peak of the floating storage spree, sheltered anchorages in the North Sea, the Persian Gulf, the Singapore Strait and off South Africa each hosted dozens of supertankers.
LNG, the fastest-growing fossil fuel, is starting to resemble the oil market in that sense. Holding it back is that some LNG is lost to keep it cool during its journey, known as boil off, and that most sales are through traditional long-term contracts without destination flexibility.
But that’s rapidly changing. Modern tankers are capable of serving as floating storage, especially for markets such as China that lack that capacity. They have lower boil-off rates, bigger capacity and re-liquefaction units on board to keep the cargoes cool.
The global LNG fleet has transportation capacity of about 44 million tons, which pales beside the 372 million tons of the crude oil tanker fleet, according to Clarkson Research Services Ltd., a unit of the world’s biggest shipbroker. LNG tankers working as storage can tie up transport capacity, even if volumes are not significant in a global context, Alastair Maxwell, chief financial officer of LNG ship owner and operator GasLog Ltd., said earlier this month.
The biggest contributor to flexible supplies is the U.S., where destination-free LNG exports started in 2016. The nation is adding production terminals and will compete with Australia and Qatar for a top place in LNG trade, which the International Energy Agency expects will overtake volumes delivered by pipelines in the middle of the next decade.
LNG spot shipping rates surge to record
Developers of U.S. LNG export projects will be among key speakers at the annual CWC World LNG Summit which starts Tuesday in Lisbon and gathers executives and traders of the super-chilled fuel.
If a cold snap suddenly comes and the spot price rises, a well-diversified player storing fuel may boost earnings by $2 million to $5 million, despite current high shipping rates and boil off, Dediu said.
“Playing contango on LNG has not been traditionally popular, but given the price volatility for gas we do see a lot more players doing this,” he said. “With higher volatility and given the unpredictable winter weather patterns, from one week to another, it might be a real option for some of the players.”
By Anna Shiryaevskaya, November 27, 2018
via Bloomberg https://www.bloomberg.com/news/articles/2018-11-27/tankers-going-nowhere-indicate-lng-market-becoming-more-like-oil
Okra Energy has announced that it has been shortlisted for the 2018 LNG Technological Innovation Award.
This will be awarded to a company that has made a significant change in the production, transportation or regasification of LNG through a technological improvement or change.
The CWC World LNG Awards have celebrated excellence in the industry since 2005, recognising the outstanding achievements of companies and their executives in the LNG sector. In addition to Okra Energy, other contenders for the award include Shell, Golar, MOL, Inpex and CMA CGM. Okra Energy is the only US company that has been nominated for this year’s honour. The award will be given at the World LNG Summit, which is being held this week in Lisbon, Portugal.
In the statement, Okra claims that it has been nominated for its proprietary design and installation of the first small scale natural gas liquefaction plant for the nation of Perú. This plant resulted in significant economic and environmental benefits for the country, as well as throughout the entire Latin America region, as markets move away from CNG and diesel. The plant’s LNG output represents 83% of the natural gas supply available to the country’s northern regions, and 20% of the total LNG accessible to the nation.
via LNG Industry https://www.lngindustry.com/small-scale-lng/27112018/okra-energy-shortlisted-for-lng-technological-innovation-award/
Published by David Rowlands, Deputy Editor
Tuesday, 27 November 2018
Key stakeholders and contributors of the global gas and LNG industry have confirmed their participation at the annual CWC World LNG Summit & Awards Evening taking place in Lisbon, Portugal, on 27-30 November 2018. Now on its 19th year, the World LNG Summit continues to attract a stellar representation from the world’s biggest LNG players, allowing for unrestrained and candid debate and commentary about the current state of the global LNG market.
Recognised for its consistent high-level networking, the Summit will providing extensive functions for delegates to expand their network and conduct business including: pre-summit Masterclasses, welcome drinks, daily breakfasts and coffee breaks as well as the unmissable CWC LNG Awards Evening – a much anticipated evening in the LNG calendar recognising excellence and outstanding contributions the Industry.
Gathering experts in the LNG and gas industry world-wide, the Summit welcomes the presentations of more than 50 representatives, including:
View the full list of speakers here: https://world.cwclng.com/speakers2018/
This year’s Summit programme, spearheaded by a distinguished Steering Committee of experts, will address new trends shaking up the industry, as well as current proven models and their place in the transforming market. Topics to be addressed include:
View the full programme here: https://world.cwclng.com/brochure_download/
The 19th CWC World LNG Summit & Awards Evening is hosted with the support and participation from a spectacular pool of world-class companies: Galp, Cheniere, NextDecade, Tellurian, Venture Global LNG, Uniper, BP, Total, Vopak, Sempra LNG, GTT, Baker Botts, King & Spalding, Poten & Partners, Comet, Höegh LNG, Hanas, Gas Strategies, ABS, H-Energy, RWE, Berkeley Research Group, Bechtel, and PGP.
For further information please visit: https://world.cwclng.com/
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Interviews with Tokyo Gas, Shell, NOVATEK, Cheniere, JERA and more!
Ahead of the CWC World LNG Summit, we interviewed 13 LNG leaders who will be speaking at the Summit. They shared with us their current views regarding industry trends, innovations and forecasts. Read on for a taster of what’s to come at the CWC World LNG Summit this November.
Read the LNG Leaders’ Interviews Here
Article by Vincent Demoury, General Delegate of GIIGNL – International Group of LNG Importers
In 2016, global LNG trade reached 263.6 MT, compared with 245.2 MT in 2015 (+18.4 MT). LNG now accounts for 30% of international gas trade vs 25% in 2000.
18 countries exported LNG to 39 importing countries. 4 new countries joined the ranks of LNG importers during the year and 11 new regasification terminals were commissioned, with 5 terminals based on floating solutions.
LOWER THAN EXPECTED BUT ROBUST SUPPLY GROWTH
On the supply side, 2016 was marked by a lower than expected but still robust supply growth (+7.5%). The year did not see any “wave” of LNG breaking over the market, despite a number of favorable development: the resumption of production in Angola and Egypt, the start-up of exports from the US Gulf of Mexico, the commissioning of five new liquefaction trains in Australia and of a 9th train in Malaysia.
Due to the slow ramp-up of several Australian projects, the combined new nominal liquefaction capacity of 36 MT worldwide starting up in the course of the year, only added 18 MT of actual new supply in 2016. Australia alone produced 15.4 MT of additional quantities essentially from new production from APLNG Train 1 and 2, Gorgon Train 1 and 2 and GLNG Train 2.
As a result, the Pacific Basin reconquered the top position among producing regions with 45% of global supply, followed by the Middle-East (35.5%) and the Atlantic Basin (19.5%).
In the Atlantic Basin, declines in Algeria, Nigeria and Trinidad were offset by the restart of production in Angola and Egypt and by the start-up of Sabine Pass Train 1 and 2 in the United States. In the Middle East, Yemen was offline all year, but the share of the Middle East remained however stable. Qatar remained the largest producing country with 30% of global LNG supply.
CHINA, INDIA AND EMERGING IMPORTERS DRIVING DEMAND GROWTH
Demand growth returned to Asian countries, mainly thanks to China and India who accounted for almost 12 MT of incremental LNG demand. After a moderate growth performance in 2015, Chinese LNG imports experienced a strong rally in 2016, with an impressive 37% growth due to the rise of gas-fired power generation and to demand from the industrial sector. Indian imports also jumped (+30%) thanks in part to low spot prices and to a price sensitive LNG demand, confirming the country’s rank of 4th largest LNG buyer worldwide.
Emerging importers also recorded strong gains in 2016. For their second year as LNG importers, Egypt, Pakistan and Jordan imported a combined 13.5 MT in 2016 compared to 5.5 MT in 2015.
The Middle East is now the 3rd largest importing region behind Asia and Europe and before the Americas. Growth was led by Egypt, who almost recorded a threefold increase in LNG imports compared to 2015 via spot and short-term imports. The situation may change as domestic production may rise again in the coming years following the recent discoveries in the country.
In contrast, demand in mature importing markets such as Japan, South Korea and Europe remained sluggish. In Japan, LNG imports declined for the second year in a row to 83.3 MT (-1.7 MT) due to the restart of several nuclear units, to energy conservation efforts and to the uptake in renewable power generation.
Against expectations, Europe did not function as a sink for the production increase in 2016 and European countries only absorbed 9% of the new exports from the Gulf of Mexico.
TOWARDS A MORE FLEXIBLE MARKET
Despite the addition of new supplies, the share of spot and short-term transactions (defined as transactions under contracts of 4 years or less) remained stable, at around 28% of total trade.
As in 2015, international LNG flows remained largely intra-regional due to the large quantities having been contracted long-term with fixed destination and to relatively low price differentials between the different basins, which in turn held back cargo diversions during most of the year.
Intra-Pacific Trade still holds the lion’s share (43%) of global LNG flows. As a result of the long-term contracts in force, the largest flows of 2016 included shipments from Australia to Japan (22.4 MT) and China (12.7 MT), from Malaysia to Japan (15.5 MT), and from Qatar to Japan (12.1 MT), South Korea (11.9 MT) and India (11.4 MT).
In the meantime, other signs indicate an evolution towards a greater flexibility in the trade and a reshaping of commercial patterns. As destination-free volumes increase and new buyers and sellers join the market, new routes are also emerging. In contrast to a limited appetite for spot and short-term volumes in most mature markets, the Middle East expanded its spot and short-term imports to 17.4 MT in 2016 compared with 6.4 MT in 2015.
The share of “pure” spot trades – defined by GIIGNL as trades whereby cargoes are delivered within 3 months from the transaction date – is estimated for 2016 at approximately 18% of total LNG volumes, up from a share of about 15% in 2015.
For more information, the full report “The LNG Industry in 2016” by GIIGNL is available for download at: www.giignl/org/publications
GIIGNL (International Group of LNG Importers) is the worldwide association of LNG importers. Founded in 1971, at the outset of the LNG industry, its membership has grown to 78 companies worldwide, comprising nearly all companies active in LNG imports or in the operation of LNG terminals. The association constitutes a forum for exchange of experience among its members, with a view to enhance safety, reliability and efficiency of LNG imports. GIIGNL members are coming from 25 countries located in the main three regions: Americas, 11 members, Asia, 36, Europe, 31.
Lennart Luten, Director, Galway Group, Dubai
The predicted LNG supply overhang over the coming years is starting to show its effects as the beginning of 2017 witnessed a sharp drop in LNG spot prices. This encourages aspiring LNG buyers in emerging markets to consider LNG import projects. LNG suppliers and portfolio companies are keen to catalyse the development of such markets as a sustained imbalance in supply and demand does not bode well for their shareholder value. Emerging markets can thus expect an overwhelming interest from parties to develop LNG value chains aimed at unlocking these new demand centres. However, this can be a risky endeavour with many hurdles to be overcome and the prospect of capital destruction always present.
Notwithstanding each country’s individual characteristics, emerging markets tend to share a number of traits that make the development of LNG infrastructure projects high-risk in nature. Once successfully completed however, the risk profile should dictate that expected returns can be above-average as well, especially as these new projects are typically supposed to drive economic growth spurts. Drawing on our experience with recently proposed LNG import projects in both Asia and Africa, we can say that off-taker creditworthiness, the fledgling state of the domestic gas market and an opaque or underdeveloped regulatory environment are amongst the top concerns for project sponsors. Political dynamics and noise from potentially competing projects are likely to add to the insecurity. Lastly, and certainly if we look at the tenders recently published or expected to be published in countries like Indonesia, Pakistan and South-Africa, bidders tend to be invited to propose integrated value chain solutions, bundling molecule supply, import infrastructure, connecting gas pipeline and sometimes gas-fired power generating capacity. This can load significant development risk on the solution providers, whilst sovereign or corporate guarantees in return are by no means a given.
Parties with deep pockets and established partnerships to deliver the separate value chain components are clearly at an advantage to consider taking on these projects. They will seek out those project opportunities with the best credentials, and preferably with World Bank support. Asian export credit agencies seem to be especially keen to provide secondary funding as well. Provided that the project sponsors and financiers can rely on take-or-pay contracts with the key off-takers, emerging markets may see the realization of fast-track, fit-for-purpose but scalable LNG import terminals without having to sink a dime in the upfront capital outlay themselves: the ideal scenario.
In our view, this will be the model that will bear fruit over the coming decade. Portfolio companies, large trading firms and cash-rich private parties are already starting to implement this strategy, not seldom leveraging existing relationships built over past decades, notably on the back of other commodity trading or infrastructure development credentials.
The term emerging LNG market is however not reserved only for new import centres. Rather, it also applies to those regions that seem to be well-positioned to export LNG at some point, or indeed potentially do both (import and export). Notable examples include Mauritania and Senegal on Africa’s west coast, the Mediterranean, specifically off the Egyptian coast, and Tanzania and Mozambique on Africa’s east coast. Collectively the fields in these regions are estimated to hold around 300 trillion cubic feet of recoverable gas. Indeed, upstream parties with a long-term view on the market are actively positioning themselves to secure stakes in these fields for future development. It may be true that the LNG market will be oversupplied up until the second quarter of the next decade, but inevitably new LNG export facilities need to be built to satisfy the growing global demand for gas. These reserves could contribute to the next wave of export projects, provided they can be developed in low-cost fashion.
Field development for export is however only part of the story. The mentioned countries are projected to experience significant demographic and economic growth. This growth needs to be facilitated by increasing levels of electrification, preferably on the back of low-cost and clean power generation capacity. Gas has an important role to play in this respect and so it would make sense to earmark part of the gas reserves found offshore in notably east and west Africa for domestic and regional consumption. At the same time, we observe that the legal and fiscal frameworks to guide the development of such fields may still have some ways to go in terms of development, although Tanzania and Mozambique are reportedly making good progress here. Another important element in catalysing the development of domestic gas resources and creating sustainable wealth for the national economies is inter-state cooperation. Mauritania and Senegal need to work together to accommodate the monetization of the offshore gas finds as well as to address the associated environmental, social and political challenges that typically accompany large-scale infrastructure projects.
World Bank-funded domestic programs are already in swing to successfully bring online the first gas-to-power projects in Mauritania. In addition, other facilitators, such as consultants, lawyers and investors, have an important role to play in rolling out the right type of frameworks and structures to help un-lock the gas resources and build a constructive investment climate which will also ensure long-term economic benefit to the domestic economies.
From a more generic perspective, we believe that proposed LNG export projects in emerging markets that want to successfully take FID in the period leading up to 2025 would have to focus notably on the following criteria: sticking to a very low-cost development philosophy; designing fit-for-purpose, scalable facilities; enhancing/building relationships with (new) off-takers; possibly allowing for more flexible off-take and pricing arrangements; leveraging G-to-G relationships to catalyse projects; securing access to low-cost sources of finance; potentially partnering with other proposed projects; and seeking collaboration with long-term buyers & trading houses. Diversification of supply and securing access to lowest-cost sources of gas will always remain top-of-mind items with buyers as the supply landscape continuous to change and fragment; we are now starting to see the signs of buyer collaboration to optimize bargaining leverage as well strategic positioning to take maximum advantage of current market dynamics. The CNOOC-KOGAS-JERA cooperation is perhaps the clearest example of this. It is very conceivable that such consortia will also take an active role in new upstream investments and export projects to prepare for the future.
The theme that both early-stage import and export projects in emerging LNG markets have in common is an increased focus on risk management, aimed at ensuring minimal risk of potential capital destruction and ensuring maximum exposure to reward upside. Even as we are entering a period in which LNG buyers have a distinct bargaining advantage, we advocate that parties continue to seek win-win solutions with their sell-side counterparts. Opportunistic buying behaviour will likely ensure more competitive pricing and flexibility terms in sale and purchase agreements. However, and notwithstanding that the LNG market is in fact commoditising, the nature of the industry is still such that short-term gains can easily be undone by long-term short-sightedness.
King & Spalding (Singapore) LLP
27 March 2017
Richard Nelson and Nick Kouvaritakis
Introduction / synopsis
The growth of ‘LNG-to-power’, by which we mean the use of regasified LNG as a feedstock fuel for power generation, is largely attributable to a combination of economic, political and technical factors, which can be broadly categorised as follows:
Importantly, a number of integrated LNG-to-power projects under development are opting to utilise FSU or FSRU technology.
The growth of FSRUs as a leading solution for LNG import projects has been well documented over the past few years. Of the four countries that began importing LNG in 2015, three of them—Pakistan, Jordan, and Egypt— opted to do so using FSRUs rather than building full-scale onshore regasification facilities. Similarly, of the five countries that began importing LNG in 2016, three involve FSRUs, two of which are deployed in integrated LNG-to-power projects. As depicted in Figure B below, many more FSRU-to-power projects are currently envisaged. In this paper, we will examine some of the critical issues to consider in structuring LNG-to-power projects utilising a marine based LNG regasification solution (FSRU or FSU).
Financing structure: Integrated vs separate financing models?
A crucial ingredient for the success of integrated LNG-to-power projects is the alignment of multiple components from fundamentally different industries: long-term LNG supply, offshore regasification vessels, midstream transportation / pipelines (and in the case of FSUs, onshore regasification facilities), power plants and associated transmission infrastructure. It is essential that the risks associated with each component part of the value chain are fully understood and allocated appropriately between the various stakeholders: the host government, the project developers, the suppliers and contractors and the project lenders. In most cases, project finance lenders will require detailed assurances from project sponsors that all technical and operational interface issues between the various project components have been addressed: for example, synchronising (i) completion, testing, commissioning and acceptance of the FSRU with the power facility and interconnecting infrastructure; and (ii) FSRU maintenance / dry-docking with scheduled power plant maintenance to minimise any potential delay or outage penalties under the power purchase agreement.
The treatment of the FSRU is a critical bankability issue that has fundamental implications for any project financing structure. The approach to the FSRU needs to be fully considered, as conventional FSRU project financing differs significantly from a traditional IPP project finance model.
Invariably the FSRU is essential to the viability of the overall LNG-to-power project, as such projects are often located in areas where no alternative gas/fuel supply is available and the costs of a land-based regasification terminal are deemed prohibitive. To address this interdependency, the equity and financing interests should ideally be as aligned as possible, meaning that the same or similar equity (shareholders) and debt providers (lenders) are involved in the FSRU and the power generation owning entities, which in most cases are project special purpose vehicles (SPVs). In this way, IPP sponsors and IPP lenders derive the control they require over the FSRU to prevent gas supply interruptions and preserve downstream (PPA) revenue flows.
Principally we have seen two distinct project finance structures emerge.
Firstly, the “fully integrated” financing structure whereby the FSRU and power plant are financed by the same group of lenders. This can be achieved either through a “co-borrower” model (IPP SPV and FSRU SPV both take out loans from the same group of lenders), or an “on-lending” structure whereby IPP SPV borrows the entire amount of the debt for the power plant and the FSRU from a single lending group, and then subsequently on-lends a portion of that debt to the FSRU SPV to finance the FSRU. Under both structures, a single group of lenders would seek to take security over both the FSRU and the power project assets, which is essential for the bankability of the integrated project. An example of such integration is the 1.5GW Sergipe power project in Brazil in which Golar (as FSRU sponsor) recently invested directly as a shareholder. The project represents the first time an FSRU sponsor has taken a direct equity investment in the downstream power project.
Figure A – on-lending structure diagram
In contrast, FSRU sponsors typically favour a “non-integrated” financing structure which envisages IPP sponsors obtaining financing for the power plant and FSRU sponsors separately raising financing for the FSRU. The fundamental disadvantage of this structure is the lack of integration between the power plant and the FSRU, which in turn is likely to create inter-creditor issues between the two sets of lenders. Typically, the lenders to the IPP (if different) will seek preferential step-in rights and some form of security over the FSRU, which may not necessarily be compatible with the terms of the financing to the FSRU. Also, each lending group will most likely seek quiet enjoyment rights over their respective project (i.e. the power plant or the FSRU). This friction between two sets of lenders can cause significant delays to achieving financial close for the project. The project involving the Penco Lirquén LNG terminal and the Central El Campesino power plant in Chile is an example of a “non-integrated” structure which envisages separate groups of lenders for the FSRU and the power plant.
Electricity dispatch: LNG procurement and FSRU inventory management considerations
The dispatch merit order and profile of the power plant to which regasified LNG is supplied (i.e. peak, mid-tier or baseload), is likely to have significant ramifications with respect to the LNG procurement and inventory management strategy for IPP sponsors.
Power plants dispatched on a peaking basis (often based on daily or seasonal demand fluctuations) create a degree of uncertainty as to the level of LNG demand and consequentially the required level of inventory to be maintained on-board the FSRU. Careful consideration of the power purchase agreement is required to understand precisely how the power plant is dispatched (i.e. whether on a firm or non-binding basis and whether daily, monthly, or yearly). However, in many cases, a ‘peaker’ PPA may not be prescriptive in terms of how the offtaker may dispatch the plant (or individual units) or what level of gas may be nominated in a given period. The challenge therefore is modelling sufficient LNG volumes to meet electricity demand / dispatch requirements throughout the year: in other words, what baseload (LNG) volume is required and how will any shortfall or surplus (of LNG) be addressed.
There are various ways for IPP sponsors to mitigate against fluctuations in dispatch levels via its LNG sale and purchase agreements, including annual contract quantity (ACQ) reductions/increases, downward and upward quantities tolerances, call options for additional quantities, cargo cancellation rights, cargo deferment rights, diversions, and variations to LNG ship sizes. The ability to procure spot cargoes is also an important mitigant to address a shortfall scenario (where the baseload LNG volumes are insufficient). This calls for a highly specialised LNG procurement strategy and a bespoke LNG SPA or SPAs which fit the specific demand profile and requirements of the power facility in questions.
However, it is important to note that not all LNG sellers will be willing to accommodate a high level of LNG supply flexibility. LNG portfolio suppliers are generally better placed to meet a more flexible procurement profile than a point-to-point/project seller. It should also be noted that LNG sellers are more likely to price in any increase in purchasing flexibility.
Peaking power plants present significant challenges in relation to the inventory management of the FSRU. Modern-day FSRUs have limited storage capacity: new-build FSRUs typically have a capacity of between one hundred and seventy thousand cubic metres (170,000 cbm) and one hundred and eighty thousand cubic metres (180,000 cbm), although MOL is set to take delivery of a two hundred and sixty three thousand cubic metre (263,000 cbm) FSRU later this year. The usage of a single floating solution (FSU or FSRU) for a peaking power plant presents IPP sponsors with material inventory constraints, which can prove especially challenging to manage if the power purchase agreement permits short-term (intra-day) fluctuations in dispatch levels. The IPP sponsor will need to ensure that sufficient LNG quantities are scheduled and available for delivery to meet short-term demand peaks and also that the FSRU owner is able to vary the regasification nominations at short notice. Typically FSRU owners will be able to provide meet these short-term variations, but in return they may require relief from certain performance warranties under the time charter party (“TCP”) or bareboat charter (“BBC”), such as the fuel usage warranty (depending on the extent of the regasification nomination fluctuations).
Alternative mitigation strategies include: (i) utilising the FSU/FSRU in LNG carrier mode to help manage the potential scheduling and inventory management constraints and (ii) developing supplemental storage capacity, either via an additional FSU facility offshore, or onshore storage tank(s).
In the case of (i), in order to mitigate against LNG supply related failures (or, as the case may be, force majeure events) the FSRU could potentially be deployed as an LNG carrier and utilised to receive cargoes on a free-on-board (FOB) basis. Further, if there are predictable periods where short-term downstream demand is zero, the FSRU could switch to operate in LNG carrier mode so as to sell any surplus LNG to a third party buyer. From an operational standpoint, the switch from FSRU mode to LNG carrier mode (and subsequent demobilisation) is manageable, with the mobilisation/demobilisation process typically taking between 24 and 30 hours, based on a conventional mooring system.
However, from a contractual standpoint there are a number of issues that need to be considered, namely that the FSRU sponsor would usually seek to be held harmless by IPP sponsor (as charterer) in respect of any incremental costs arising as a result of the operation of the FSRU in LNG carrier mode (i.e. taxes, port charges, etc.). The FSRU sponsor and IPP sponsor would in most cases agree a separate charter party agreement which relates to the operation of the FSRU in LNG carrier mode, which would contain a number of market standard concepts including: (i) a procedure for the mobilisation/demobilisation of the vessel as an FSRU, (ii) an acknowledgement that the regasification/boil-off warranties that apply to the FSRU in regasification mode would not apply to the use of the vessel in LNG carrier mode, and (iii) dispensation from the permitted maintenance/dry-docking regime (i.e. the requirements for a vessel operating in dual-usage mode may not be the same as for a vessel operating solely in FSRU mode).
A fundamental issue for IPP sponsors to consider is the disproportionate nature of the contractual liabilities faced by IPP sponsors (under the PPA) and the FSRU sponsors (under the TCP or BBC). The scale of penalties and damages potentially payable under a PPA are of a much higher order of magnitude than those payable under a TCP or BBC.
Whilst IPP sponsors will need to assess how to allocate liability for the failure of multiple parties (LNG supplier(s), FSRU owner(s), EPC and O&M Contractor(s), electricity offtaker(s)), the FSRU owner will in most cases seek to limit its liability to events caused by its own failure; that is to say, performance of the FSRU.
The problem that IPP sponsors face is that a performance failure of the FSRU (for example, a failure to regasify LNG at the rate nominated by IPP sponsor) can lead to IPP sponsors incurring significant liabilities under their upstream (LNG SPA) and downstream (PPA) contractual arrangements. However, the liability of the FSRU owner(s) under the TCP or BBC will almost always be capped at a percentage of the total hire amount payable, meaning that the IPP sponsors are unlikely to have recourse against the FSRU owner(s) for the full amount of the liabilities that they are exposed to under the LNG SPAs and/or the PPA.
In the pre-operational phase, a failure of the FSRU supplier to successfully commission the FSRU by the required commercial start date can potentially expose IPP sponsors to take-or-pay liabilities under their LNG sale and purchase agreement (subject to mitigation measures such as a diversion, rescheduling of the cargo/cancellation etc.) and delay liquidated damages (“LDs”) under their power purchase agreement.
In the operational phase, a performance failure of the FSRU vessel could result in IPP sponsors incurring outage penalties under their power purchase agreement, if the IPP sponsors are unable to meet the dispatch requests of the electricity buyer.
Historically, FSRU owners have been reluctant to accept LDs for performance failure that exceed the daily rate of hire (i.e. capital costs plus operating costs). This mind-set is largely derived from LNG shipping market practice whereby the risks that the vessel owner is willing to take on should be commensurate with the return that it receives under the charter party. Generally speaking, this mind-set is slowly changing as there are more instances, particularly in the context of integrated LNG-to-power projects, of FSRU owners agreeing to assume some (but only some) responsibility for liabilities incurred by IPP sponsors resulting directly from FSRU-related performance failure.
Notwithstanding this shift towards a more favourable liability regime under the charter party agreement, IPP sponsors are often left with significant residual liabilities, some of which they may be able to mitigate via insurance, such as delay-in-start up insurance (pre-operational phase) and business interruption insurance (operational phase), but it is unlikely that such insurances will fully cover such residual liabilities as the policies will contain various deductible periods, sub-limits and exclusions. Project finance lenders may require that IPP sponsors themselves cover any remaining residual liabilities that cannot be covered by the FSRU owner or insurance.
Payment in advance vs payment in arrears
A further challenge for IPP sponsors is to align the payment mechanism under its power purchase agreement(s) with its payment obligations under the FSRU charter agreement (i.e. to ensure that IPP sponsor receives payment from the power purchaser prior to hire payments being due under the FSRU charter agreement). In the FSRU industry this is often referred to as a “pay-when-paid” regime. FSRU owners typically require payment of hire in advance, to ensure that the FSRU owner has sufficient available cash to cover all operating expenses (including payments to be made to third party service providers). In an integrated project context, the IPP sponsors will be using revenues received under the PPA to make those hire payments to the FSRU owner (subject to the relevant payment waterfall).
Project finance lenders will typically prefer that IPP sponsor is first put in funds by the power purchaser before it is obliged to make payments to the FSRU sponsor, or, if this is not achievable, that the payment terms (i.e. periods) are aligned and/or that IPP sponsor maintains a working capital/hire reserve account to ensure that it is able to meet its hire payment obligations to FSRU sponsor. Also, to the extent that the underlying payment obligations under the PPA are supported by credit instruments such as SBLCs or sovereign / government guarantees, lenders would prefer that the IPP SPV borrower retains the ability to call on such credit instrument(s) before becoming liable to pay the hire instalments, subject to a requirement to pay the FSRU owner any amounts recovered under those instruments.
The FSRU-to-power market is still evolving in this regard, and from our experience FSRU sponsors are moving towards a broader “pay-when-paid” regime subject to IPP sponsor agreeing to certain conditions with respect to the credit support/guarantee arrangements, such as posting a SBLC in respect of [x] months of hire and agreeing to claim against and to pass through the benefits of any credit support provided by the power off-taker.
Emergence of a multi-user terminal model?
A further notable development is the advent of ‘multi-user’ FSRU-IPPs (i.e. where the FSRU is intended to be utilised by the IPP and also by other downstream customers). This could be as a result of mandatory or regulated third party access requirements under the laws of the jurisdiction in which the project is being developed.
Multi-user FSRUs present a number of technical and operational challenges, particularly given the size and storage constraints of FSRU vessels. From a credit perspective, the FSRU owner would likely prefer that a single (creditworthy) charterer stands behind the hire payment obligations, as opposed to multiple charterers with separate hire payment obligations (although, in the final analysis this will depend on the creditworthiness of the proposed charterers). Multi-user FSRU terminals also give rise to complicated storage and send-out capacity allocation issues, as between the various users, as well as LNG quality and contamination issues in the context of potential commingling of LNG supplies in a single storage tank.
In structuring multi-user FSRUs, a robust terminal use agreement is imperative to the bankability of the project. This may follow the form of onshore RGT terminal use agreements, although particular consideration will need to be given to the specification and configuration of the individual FSRU facility. However, despite the notable challenges, multi-user FSRUs may be favoured in geographically remote locations (for example, the archipelagos in Indonesia and Philippines) where a ‘storage and reload’ model to deliver to multiple plants utilising small or smaller scale LNG ships is preferable.
FSRU-to-Power project opportunities on the horizon
Despite the multitude of technical, legal, financial and commercial challenges facing integrated LNG-to-power projects and the tension between the conventional business model of the FSRU owners on the one hand and the IPP sponsors (and project finance lenders) on the other, we expect that, assuming the fundamental economics remain viable, the number of these projects to grow exponentially over the next few years. We have set out below a brief snapshot of some selected FSRU-to-power project opportunities currently in the market.
*Based on certain assumptions on gas required for power gen and plant efficiency
 Annex IV to the Arrangement on Officially Supported Export Credits dated 1 February 2017 (Sector Understanding on Export Credits for Coal-Fired Electricity Generation Projects) limits the ability for export credit agencies of OECD member countries to finance new coal-fired power plants. Available at http://www.oecd.org/officialdocuments/publicdisplaydocumentpdf/?doclanguage=en&cote=tad/pg(2017)1
 World’s Commitment to LNG, Energia16, Mar. 27, 2017. Available at http://www.energia16.com/worlds-commitment-to-lng/?lang=en
 The five countries are Poland, Jamaica, Indonesia, Barbados and Finland, and the LNG-to-power projects are those in Jamaica and Indonesia. See Karen Thomas, Supply Glut Opens New LNG Markets, LNG World Shipping, Oct. 6, 2016. Available at http://www.lngworldshipping.com/news/view,supply-glut-opens-new-lng-markets_44890.htm
 Golar Power reaches a Final Investment Decision on Sergipe Power Project and signs a 25 year FSRU agreement, Stockhouse. Available at http://www.stockhouse.com/news/press-releases/2016/10/17/golar-power-reaches-a-final-investment-decision-on-sergipe-power-project-and
 Karen Thomas, Höegh LNG secures financing for its seventh FSRU, LNG World Shipping, Feb. 29, 2016. Available at http://www.lngworldshipping.com/news/view,hegh-lng-secures-finance-for-its-seventh-fsru_42038.htm; Central El Campesino Financing in Flux, Latin Finance, Feb. 6, 2017. Available at http://www.latinfinance.com/Article/3659292/Central-El-Campesino-financing-in-flux.html#/.WNjDtU1MpaQ
 MOL finalizes charter deal for Uruguay FSRU project, LNG World News, Jul. 22, 2016. Available at http://www.lngworldnews.com/mol-finalizes-charter-deal-for-uruguay-fsru-project/
 LNG in World Markets, Vol 28, No.10, Poten & Partners (supplemented with select additional projects)
 Summit Group wins contract to build $500m LNG terminal offshore Bangladesh, ONG Update. Available at http://ongupdate.com/2017/01/07/summit-group-wins-contract-to-built-500m-lng-terminal-offshore-bangladesh/
 Verity Ratcliffe, Kenya Revives Mombasa FSRU Plan, Interfax Global Energy, Interfax Global Energy, Oct. 18, 2016. Available at http://interfaxenergy.com/gasdaily/article/22417/kenya-revives-mombasa-fsru-plan
 Large Scale Power Station Project Takes Off, Central America Data, Jan. 19, 2016. Available at http://www.centralamericadata.com/en/article/home/El_Salvador_Large_Scale_Power_Station_Project_Takes_Off
 Petronet LNG Plans $3 billion Investment Outside India, Energy Sector, Jul. 15, 2016. Available at https://www.energysector.in/petroleum-news/petronet-lng-plans-3-billion-investment-outside-india
The LNG oversupply situation looks set to be sustained for longer and at a greater magnitude than previously thought likely. What impact might this have on gas markets and on future investment in the sector?
LNG oversupply larger and longer than before
Will Europe absorb the excess LNG supply?
LNG is likely to become a competitively priced fuel into medium and long term. What will this mean for the challenges of developing LNG to power projects in new gas markets?
Increasing demand form other existing large gas and LNG markets
Potential new LNG markets
Countries with existing large gas markets are expected to continue to increase their reliance on LNG. But it is now also an opportune time for more countries with little or no existing gas market to turn to LNG. There is no shortage of LNG supply at competitive prices out to 2030.
In the US alone, in addition to the 60 mtpa under construction, plus the 60 mtpa with approval, there is close to 160 mtpa of projects which are in the planning stage but have not yet received approval. Further supply competition will be provided by Iran, Russia and others.
With a well-supplied market out to 2030 and possibly beyond, LNG is no longer a niche product but likely to become a globally traded, competitively priced fuel into the medium and long term.
QED provides a comprehensive consultancy service to the international gas and LNG industry specialising in strategy implementation, project realisation and negotiating commercial agreements.
To discuss how the above may impact on your project or business (import or export):
Website: www.qedgas.com Phone: +44 (0)20 7936 4385 email: email@example.com
“I think of where we are today it’s actually surprisingly a reasonably balanced market, with supply and demand looking in balance this year.”
Watch the interview with Andy Flower, Independent Consultant, Flower LNG
“In this current buyer market situation the Greenfield project is struggling to come online into the market. Because as you may be aware, low coal price means reducing the gas flow for the produce and oversupply capacity in the market means a low price.”
Watch the Djohardi Angga Kusumah, Senior Vice-President Gas & Power, Pertamina here.
“At the moment there is a lot of LNG supply coming on the market. The market is more a buyers market. It’s expected to remain the same for some years.”
Watch the interview with Geoffroy Hureau, Secretary General, Cedigaz here.
“There are 2 main lines of challenges. First is the whole low commitment to low carbon economy and that has a significant impact on the gas industry in general. But also, of course, on LNG. There is also an issue that has been raised about the sustainability of gas production that goes then in to LNG and the whole LNG value chain.”
Watch the interview with Monika Zsigri, Policy Officer, DG Energy European Commision here.
“I think if we start creating systematic shifts in demand then the global LNG business has a very promising future. At the moment there is a lot of gas swirling around and not enough demand so the pressure on us is demand creation above all else.”
Watch the Philip Lambert, CEO, Lambert Energy Advisory interview here.
“If you look at even the last 3-4 years, the number of new entrants to the LNG industry and the number of new buyers, the number of new countries that are becoming involved.”
Watch the full interview with Richard Nelson, Partner, King & Spalding here.
” I think the main issue now is that we’re really in a transition phase in this industry. The economic crisis has put a lot of pressure on pricing.”
Watch the interview with Patrick Janssens, Vice President, Global Gas Solutions, ABS here.
“What we’re seeing this year and probably carrying forward in the next couple of years is that there is a change of landscape, especially on the buyers side.”
Watch the full interview with Li Yao, CEO, SIA Energy here.
“The industry is clearly entering a period of evolution. We have growing supply. We have growing flexibility. We have growing liquidity; fragmentation of the LNG supply chain. We have diversification of markets; diversification of pricing. So it’s an exciting time to be in the LNG industry.”
Watch the interview with Andrew Walker, VP Strategy, Cheniere Energy here.
“In Jordan, 2 years ago, we didn’t have any percentage from renewable energy on our energy consumption. Nowadays if you’re talking about 2016, we have 5-6% from renewable energy.”
Watch the interview with Amani Al Azzam, Secretary General, Ministry of Energy & Mineral Resources, Jordan here.
“The LNG industry is on the verge of a big revolution. It’s an opportunity for us now to capture the new demand that we known exists in many existing markets but also many new markets. “
Watch the interview with Martin Houston, Co-Founder, Tellurian Investments here.
“By 2020 we will have almost doubled production since 2013. The good thing is that it’s going to be very positive but there are questions due to the low oil price environment. The question is what is going to happen from 2020 onwards.”
Watch the interview with Debbie Turner, Director, SSY Gas here.
“I would love to see many more countries move away from coal and oil for energy production and go towards LNG.”
Watch the interview with David Colson, Commercial Vice-President, GTT here.
“The LNG industry has been growing numerous times over by expanding markets. Ultimately that’s the next step we need to take again.”
Watch the Steven Miles & Jason Bennett, Baker Botts LLP interview here.
“The business environment is certainly much better than people predicted this time last year. There’s been a lot of new supply which a lot of people forecast but we’ve seen a really strong demand response as well.”
Watch the interview with Steve Hill, Executive Vice President for Gas & Energy Marketing & Trading, Shell here.
“I think for next year the flood of US LNG should materialise. It was already predicted for this year but it was a little bit delayed. What the industry has to do to cope with that is to create new demand and further reduce the costs.”
Watch the interview with Stefaan Adriaens, Commercial Manager, Gate terminal B.V. here.
“We had an opportunity at the time when we were designing a new ship to choose a new fuel. We know that there are new regulations coming and we really wanted to be able to future proof our vessel.”
Click here to watch the interview with Tom Strang, VP, Maritime Affairs, Carnival Corp & PLC
“I think the industry is quite exciting right now. I think supply and demand is changing. I think the United States is going to play a very important role going forward.”
Watch the Kathleen Eisbreener, Chairman & CEO at NextDecade interview here.
View the 2016 CWC World LNG Summit Post Event Summary. Including:
23 January 2017, London, Singapore: Tullett Prebon, one of the world’s leading interdealer brokers, is collaborating with Singapore Exchange (SGX) to develop a spot pricing index for the Middle East and Indian liquefied natural gas markets (LNG) to enhance price discovery and risk management in the region. Following industry consultation, the new index will provide a transparent and trusted reference price for LNG Delivered Ex-Ship under flexible terms to key ports in Dubai, Kuwait and India (DKI).
The new DKI Sling Index will be published every Monday and Thursday by SGX, Asia’s leading and trusted market infrastructure. As the LNG market moves towards an oversupply, the role and relevance of spot and shorter-term contracts has increased. However, the industry still lacks transparency and credible price references. The Middle East and India region in particular has seen a boost in spot trade, but lacks an accepted price marker and market participants are often relying on tenders for price discovery. Those hedging physical exposures have limited options, and are using Far East LNG and/or UK oil and gas benchmarks to manage risk. The new index aims to provide a credible, consistent and transparent pricing mechanism, as the volume of LNG trades in the region continues to rise. It could also serve as a first step towards standardising LNG trade in the region.
With the launch of the new index expected in the second quarter of 2017, Melissa Lindsay, Global Head of LNG at Tullett Prebon, said:
“We are thrilled to be partnering with SGX to launch this new index. The group’s efforts in Asia and credibility as a Benchmark Administrator, coupled with our experience building liquidity in LNG derivatives, makes this a strong partnership. Over recent years we have seen an increase in the volume of spot trade into the Middle East and India region and this new index will provide better price discovery and fair value to our clients. Over time there will be moments where the regional price decouples from the Far East LNG or European Gas prices, so it is important for an independent and trusted regional price.”
Janice Kan, Head of Commodities at SGX, said:
“Singapore Exchange is pleased to collaborate with Tullett Prebon to introduce the new Dubai-Kuwait-India Sling index. The winning combination of Tullett Prebon’s extensive network and deep understanding of the LNG market, along with SGX’s transparent and trusted methodology, will help the new index to develop as a benchmark for the region. We look forward to continue building industry support to enhance price discovery in the LNG market.”
The DKI Index will form part of the SGX LNG Index Group or ‘Sling’ series of indexes that follows the trusted methodology of collecting an average price from participants. It will be the first of its kind to use high-level terms of physical trade approach, ensuring submission of prices are on the same assumptions.
Amreeta Eng, Group Director for Trade Promotion at International Enterprise Singapore, the Singapore government agency that promotes international trade, said:
“It is encouraging to see Singapore Exchange extending its service offerings in the LNG space. As LNG markets become more spot-based, this strategic partnership between SGX and Tullett Prebon will pave the way towards more transparent, trusted and reliable price discovery benchmarks. Singapore is emerging as a key LNG hub, with storage, trading, shipping and price discovery activities, and we look forward to more industry-led initiatives to develop the LNG markets.”
Pia Stephenson, TP ICAP Communications
+44 (0) 20 7200 7009
Kate Holgate, CJ Lin
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Kim Fletcher, Eilis Murphy, Craig Breheny
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Yee Kai Pin, Vice President, Media Communications
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Note to editors:
Tullett Prebon is a leading interdealer broker and operates as an intermediary in wholesale financial markets. Aided by market-leading technology, Tullett Prebon’s expert voice brokers facilitate the trading activities of clients across seven major product groups: Rates, Volatility, Treasury, Non-Banking, Energy & Commodities, Credit and Equities. In addition to its brokerage services, Tullett Prebon Information provides independent real-time price information from the global OTC financial and commodity markets. Tullett Prebon is part of TP ICAP Group. For further information see www.tullettprebon.com.
Singapore Exchange is Asia’s leading and trusted market infrastructure, operating equity, fixed income and derivatives markets to the highest regulatory standards. As Asia’s most international, multi-asset exchange, SGX provides listing, trading, clearing, settlement, depository and data services, with about 40% of listed companies and 75% of listed bonds originating outside of Singapore.
SGX is the world’s most liquid offshore market for the benchmark equity indices of China, India, Japan and ASEAN and offers commodities and currency derivatives products. Headquartered in AAA-rated Singapore, SGX is globally recognised for its risk management and clearing capabilities. For more information, please visit www.sgx.com.
Buying and selling LNG is set to become more standardised in the next few years as greater volumes are shipped by an ever-widening pool of market players, executives from some of the world’s largest LNG-trading companies said at the CWC World LNG Summit last week.
However, the range of price indices that LNG is linked to is preventing the fuel from being treated in the same way as other commodities such as oil, delegates were told.
To read the full article, please click here.
LNG has a huge opportunity to become a key shipping fuel because of its abundant supply, environmental advantages and relatively stable price, experts in the gas and shipping industries have said. However, equipment costs, regulatory uncertainty and the lack of LNG bunkering facilities are weighing on the minds of shipowners.
Equipment costs could be the determining factor governing whether the shipping industry adopts LNG, Tom Strang, senior vice president of maritime affairs at cruise giant Carnival Corp., told the CWC World LNG Summit in Barcelona last week. “For example, [LNG] tanks are very expensive. We would love to see cost of equipment coming down,” he said.
To read the full article, please click here.
Declining domestic demand is pushing Japanese and South Korean LNG buyers towards short-term and more flexible contracts, but these alone cannot support new export projects. It is therefore up to a new set of buyers in countries expecting long-term LNG demand growth to sign the foundation contracts for new projects.
Japan’s Jera, the world’s biggest LNG buyer, is unlikely to sign many long-term contracts for additional LNG supplies because of the declining demand it is facing on the domestic market, according to Hiroki Sato, Jera’s senior executive vice president and chief fuel transactions officer.
To read the full article, please click here.
The sheer size of new shale discoveries in West Texas means producers could pay customers to take associated gas output and still make a profit from the oil production, according to an executive at LNG project developer NextDecade. The Wolfcamp and Alpine High finds in the Permian Basin are also a game-changing for Texas’s LNG exports.
“There is so much associated gas in Texas, we can literally afford to pay people to take it away so we can produce oil,” Kathleen Eisbrenner, chairman and chief executive of NextDecade, told the CWC World LNG Summit in Barcelona on Wednesday. The executive said the hypothetical scenario was based on a Brent benchmark price of $50-60 per barrel.
To read the full article, please click here.
Senior executives from BP and Shell are optimistic about the future of global gas and LNG demand, as well as the industry’s ability to manage the new wave of demand growth.
Speaking at the CWC World LNG Summit in Barcelona on Tuesday, Jonty Shepard, chief operating officer of BP’s LNG division, said that while supply would not be an issue for the foreseeable future, growing demand presents certain challenges. “It’s a healthy market and demand is growing – but the sources of that demand are changing,” said Shepard.
To read the full article, please click here.
Oversupply looks set to dog the LNG industry for the next five years with a consequent need to create fresh demand to absorb surplus product — and this could see new opportunities for shipping.
Top of the list are floating storage and regasification units (FSRUs), which were mentioned by nearly every speaker at CWC’s World LNG Conference in Barcelona last week. Small-scale LNG, gas-to-power projects, and marine bunkering also got more than their usual airplay.
But what was most noticeable at this end of year meeting, which serves as something of an annual barometer for the industry, were the proclamations by LNG producers and sellers that they need to take positions in business areas they might not previously have looked at, in an attempt to find new buyers.
“FSRUs are the solution,” Total’s president for gas Laurent Vivier told the audience. “We need players
upstream to move downstream. We need today to do our share in developing this demand and invest in infrastructure.”
LNG is already a buyer’s market but the new wave of incoming supply — much of it from the US — is set to be a game changer.
Global LNG production for 2016 looks set to top out at about 264 million tonnes.
A further 110 million tonnes per annum (mtpa) of liquefaction capacity is already under construction, part of a 720 mtpa of planned LNG projects worldwide. This new LNG will start coming onstream next year but in 2018 US producers alone are scheduled to bring 11 new production trains online.
Hiroki Sato, senior executive vice-president and chief fuel transactions officer for trader JERA, said in 2018 some 50 to 70 mtpa will come onto the market with “no permanent destination”, allowing it to be traded globally.
By 2025, LNG production is set to reach 380 million tonnes.
Speakers at the Spanish gathering largely agreed that they expect the market to return to balance from 2022 onwards as this supply is absorbed and new demand starts to kick in.
However, in the interim this near doubling of production is expected to fundamentally change the way the LNG industry operates.
Traders who are already much more active players in the sector are flagging up what they believe will be a surge in LNG spot trading, with one claiming this could rise from current levels of about 25% of the market volumes to up to 50%, or about 150 to 160 mtpa by 2020.
The definition between buyers, traders and sellers is beginning to blur with players moving into each other’s domains.
Speakers from Egypt, Malaysia and Indonesia, all originally LNG producers, spoke of their new dual roles as importers and exporters and the potential opportunities this could create.
There was talk of a move to a more commoditised trading market and the need for more collaboration between market players.
The shifts are bringing calls for a new business model in the industry that will need more flexible contracts, and new pricing mechanisms as short-term and spot trading grows.
Petronet managing director and chief executive Prabhat Singh said there is a “huge need” to optimise on the miles that LNG travels, detailing that cargo swaps with US shipments destined for India could offer a potential annual saving of $1.5bn.
Eric Bensaude, managing director, commercial operations and asset optimisation, for the US’ newest producer Cheniere Energy, said that Asian utilities and Far East trading houses have contracted for about half of the 60 mtpa of the US LNG production sanctioned to date. But he told delegates that of the three mtpa exported from Cheniere’s two trains to date, 45% has been delivered to South America and the Middle East. “It shows that the flexibility is working,” he said.
“Demand patterns are changing — potentially a huge opportunity for LNG,” BP chief operating officer for gas Jonty Shepard told the audience.
So, in 2017 the LNG industry is likely to see some fairly serious muscle making a move into the floating regasification space as majors and producers look to find new buyers for their surplus product.
Total has already shown its hand by investing in an FSRU for the Ivory Coast and others are likely to follow.
The moves on small-scale LNG might be less dramatic but some big names are already hard at work on it. Shell executive vice-president for gas and energy marketing Steve Hill was quick to flag up the company’s early mover status after sanctioning a first project in Gibraltar.
LNG bunkering is also starting to drift onto the radar of some of the industry’s key players. Bomin Linde LNG chief executive Mahinde Abeynaike believes this sector — which currently consumes just 250,000 tonnes of LNG, may account for one mtpa by 2020 but has the potential to be “huge” by 2030.
Just as supply prepares to flood the market, the industry is also being urged to invest in the next wave of LNG production in an environment where finance is limited. With these needed to come online after the anticipated market rebalancing from 2022, final investment decisions need to be made soon.
Article courtesy of Lucy Hine, TradeWinds
Martin Houston and Charif Souki’s new LNG-producing company Tellurian Investments is set to go public next month and quadruple its staff in 2017.
Former BG Group chief operating officer Houston, who founded the company with ex-Cheniere Energy chief executive Souki, says the company will be listed on Nasdaq following its reverse takeover of Denver exploration and production company Magellan Petroleum, announced in August.
Houston says Tellurian employs around 50 staff but has just taken out new office space in Houston and will probably boost its numbers to nearer 200 next year.
Asked whether Tellurian, which is gearing up for a big reveal at next year’s Gastech meet in Japan, would take a position in shipping, he said it would more likely partner with a provider.
Speaking this week at CWC’s World LNG Summit, chief executive Meg Gentle said the industry was going through one of the greatest periods of change ever seen. Detailing current market pricing, she said the market was finally gaining some momentum.
Tellurian announced last month that GE Oil & Gas was ploughing $25m into the company, which is developing a 26 million tonnes per annum (mtpa) project, Driftwood LNG. Gentle said the two companies would work together to design “the lowest-cost liquefaction for the global market”.
Tellurian is building the project in blocks of 1-mtpa single trains and has spoken about being able to price the LNG it produces at $5 per MMBtu.
Article courtesy of Lucy Hine, TradeWinds
A small commissioning cargo has been lined up for a new LNG floating storage unit (FSU) in Malta.
Industry sources say the 174,000-cbm newbuilding GasLog Glasgow will ship around 90,000-cbm of LNG to the FSU Armada LNG Mediterrana, which is waiting to fire up the Mediterranean island’s LNG imports.
The shipment is scheduled to arrive off Malta in early January. The Maltese unit, which is a conversion from the 125,877- cbm LNG carrier Wakaba Maru (built 1985), arrived off its new location at the east-coast port of Delimara in October.
Industry players have been watching for incoming shipments to see when the unit will start commercial operations.
The Bumi Armada-owned FSU is berthed at Marsaxlokk and is capable of receiving cargoes from visiting LNG carriers of up to 155,000 cbm.
It is to be used in conjunction with an onshore regasification unit to supply gas to ElectroGas’ 215-MW gas-fired Delimara power plant.
Article courtesy of Lucy Hine, TradeWinds
Speculation is mounting as to which LNG carrier will be used to lift the first cargo produced afloat after Petronas announced it has started production from its PFLNG Satu unit.
Ahmad Adly Alias, Petronas vice-president of LNG trading and marketing, speaking at CWC’s World LNG Summit in Barcelona this week, told TradeWinds that the company most likely would use the first of MISC’s recently delivered newbuildings, the 150,200- cbm Seri Camellia (built 2016). He said that whichever vessel finally lifts the historic shipment, a Moss-type ship will be deployed to handle the transfer of the cargo from the 1.2-million-tonne perannun (mtpa) LNG floater to the visiting LNG carrier.
“If you are going to do a ship-toship, you need a more robust containment system,” he said.
Ahmad said the first commercialcargo would be shipped early in 2017, as the first LNG was produced only last week. Company officials had previously indicated the shipment would leave this year.
Talk also has been circulating that Petronas may utilise the 65,000-cbm LNG Lerici (built 1998) for shipping cargoes from the floater to fulfil its supply contract with Chinese trader Jovo Group.
Ahmad disclosed that the company had been thinking about break-bulking LNG from a mothership into a smaller vessel in either Subic Bay in the Philippines or Labuan in eastern Malaysia.
“We are very innovative in the way we try to satisfy the customer,” he said. “The customer wants small shipment sizes, so we are considering those kinds of options.”
The PFLNG Satu arrived at its production location 180 kilometres (112 miles) off Bintulu in eastern Malaysia at the end of May. It is being used to develop the Kanowit gas field there. Ahmad said it had taken 12 years to bring the world’s first floating LNG (FLNG) project to market.
He said Petronas had chosen to delay its second, slightly more deepwater, 1.6-mtpa floater, which it has on order at Samsung Heavy Industries in South Korea, because it did not want to contribute to the overhang of LNG supply in the
market. This unit, the PFLNG Dua, is now due to be completed in 2020.
Petronas is also looking at diversifying its LNG activities. Ahmad said the company was currently considering a move into floating storage and regasification units (FSRUs), although this project is still “under wraps” right now.
He said the company is working on forming a consortium where Petronas would provide the LNG and possibly take an equity project stake while another party would take on the FRSU.
“We are looking at the options,” he said.
Ahmad also revealed that Petronas was looking at branching out into LNG bunkering.
He cited the company’s landbased LNG receiving terminal at Pengerang on Malaysia’s southeast coast as a possible location for these activities. He explained that the terminal had reload facilities but operations would likely entail loading cargo onto a vessel and then transferring as bunkers offshore by ship-to-ship operations.
Article courtesy of Lucy Hine, TradeWinds
Dutch infrastructure provider Gasunie is partnering up to develop what looks set to be Germany’s first LNG terminal.
Ulco Vermeulen, who is a member of the executive board and director participations & business development for Gasunie, told CWC’s World LNG Summit that development work will start in 2017 on a midscale sized LNG terminal Hamburg LNG.
He told TradeWinds that the new terminal will have capacity of 2-3-million tonnes per annum and that an announcement would be made on the project in the next few weeks.
Vermeulen said the facility would have a jetty for marine bunkering and a small scale distribution of cargoes. He detailed that it would also have capacity for truck loading.
The Gasunie director said the new terminal would likely be sited in either Brunsbuttel or Stadt on the River Elbe to the north of Hamburg.
We are focussing on north western Europe – that is our home base – and are quite confident that the German market will grow, Vermeulen told TradeWinds.
He said Gasunie is also now starting to look at similar project in southeast Asia. “We try to develop a project with infrastructure companies and co-operate with anyone who wants to participate,” he explained, adding that this could include shipowners.
Plans have been in the works to install an LNG terminal in Germany for many years but none have been realised. But the country moves to shift away from nuclear power and coal and interest in LNG fuelling have given fresh impetus to LNG terminal proposals.
Article courtesy of Lucy Hine, Tradewinds
Discussions are underway in Poland to install a floating storage and regasification unit (FSRU) as the country moves to diversify its supply.
PGNiG Supply & Trading managing director Uwe Bode told delegates to the CWC World LNG Conference in Barcelona that plans are ongoing to install an FSRU near Gdansk that would be up and running by 2022.
This would be in addition to Poland’s land-based terminal, which is controlled by state run Polskie Gornictwo Naftowe i Gazownictwo (PGNiG). This facility started up in the last 12 months and has seen nine cargoes imported since late December 2015.
Bode explained that the FSRU’s planned start-up would dovetail with the end of Poland’s long-term pipeline gas contracts with Russia, which currently supplies around 70% of the country’s gas. He said post 2022 the country’s gas demand is expected to accelerate.
He said Poland is keen to diversify its gas supply but also wants to distribute gas to neighbouring countries both via pipeline and as LNG.
The MD also revealed that PGNiG’s trading arm PST LNG will open an office in London, at 48 Dover Street near Green Park, in February.
He said this office will do short-term LNG trading for the PGNiG Group.
Photo: The 210,000-cbm Q-flex LNG carrier Al Nuaman (built 2009) docks at Polskie LNG’s new Swinoujscie LNG receiving terminal with the first of two commissioning cargoes.
Article courtesy of Lucy Hine, TradeWinds