wison says building china’s first floating lng power …

LNG NEWS WEEKLY DATE 05

th FEBRUARY 2021

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(Sale and Purchase) (Gas projects)

WISON SAYS BUILDING CHINA’S FIRST FLOATING LNG POWER

PROJECT

Wison Offshore and Marine has recently started building what it says is China’s first floating LNG-to-power project. The firm says the works started on January 26 at its Nantong yard in southeastern Jiangsu province. According to Wison, the floating LNG-to-power project will consist of a floating LNG regasification unit (FSRU) and a 240MW combined cycle power barge. In addition, the FSRU will regasify LNG and transfer it to the power barge as fuel for power generation for onward distribution to the grid. Shanghai Electric will supply the 240MW turbines for the floating LNG-to-power project as part of a deal signed with Wison last year. Wison did not reveal any additional information on where it would deploy these facilities. The firm received approval in principle in 2018 from classification society Lloyds Register for a 300MW floating storage regasification and power generation barge (FSRP). Moreover, Wison said the FSRP could produce power starting as low as 7 cents per kWh. With a total storage capacity of 170,000 cbm in GTT membrane cargo tanks, the facility also features a CCGT power plant, available with an output of 150 – 450MW. source : www.lngprime.com

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SINOKOR PRESSES PAUSE ON THREE LNG NEWBUILDINGS

Hull numbers show ships ordered at SHI two years ago were due to deliver in 2021 and 2022. South Korea’s Sinokor Merchant Marine has cast doubt on whether it will proceed with three of four LNG newbuildings it contracted almost two years ago at Samsung Heavy Industries. Sources following the order said the company paid the deposit on one ship but asked the South Korean yard to delay the other three vessels and has not specified a date to proceed. The order for the quartet dates back to February 2019. SHI announced contracts for the four LNG carriers priced at close to $194m each, but did not disclose the identity of the party behind the ships. Brokers later named Sinokor as the contracting party. The four, 174,000-cbm X-DF vessels are listed on databases as Hull Nos 2315, 2316, 2317 and 2318. The first two were originally scheduled for delivery in the second half of this year, with the others to follow in 2022. This week, shipbroker Clarksons quoted LNG newbuilding prices at $186.5m. It emerged on Wednesday that SHI has reportedly made financial provisions of KRW 35bn ($31.4m) on the Sinokor newbuildings. Including those ships, the yard has an LNG carrier orderbook of 37 vessels. Sinokor was contacted for comment. Sinokor’s LNG play has focused mainly on the secondhand sector, where it has amassed a fleet of 13 ships, the bulk of which are listed as laid up. Two ships are currently trading. Last month, TradeWinds reported that the company was in the process of reactivating three of its laid-up vessels. Sinokor has also weeded out some of its purchases for scrap sales, apparently without ever trading the ships. The SHI berths were Sinokor’s second attempt at LNG newbuildings. In 2014, it looked set to make its break into the business when it contracted two vessels at Daewoo Shipbuilding & Marine Engineering to offer in on time charter business offered by Korea Gas Corp (Kogas). But Sinokor was unsuccessful on the Kogas charters and flipped its two LNG berths into four VLCCs slots. The yard later cancelled two of these orders and sold the other pair for its own account. In 2015, Sinokor turned its attention to the secondhand market for its first LNG carrier — the laid-up, 127,180-cbm LNG Swift (built 1989). The vessel, renamed Grace Energy, was reactivated for further trading recently. source : www.tradewindsnews.com TITAN LNG CHARTERS LNG BUNKERING VESSEL

Amsterdam-headquartered independent LNG supplier Titan LNG has reached an agreement to charter in NYK Line’s LNG bunker vessel Green Zeebrugge. Previously known as the Engie Zeebrugge, NYK renamed the vessel after becoming its sole owner. The agreement sees Titan LNG charter the Green Zeebrugge for several years from February 2021. The vessel will be used to supply LNG to larger LNG-fueled vessels in the Amsterdam-Rotterdam-Antwerp (ARA) region. With the vessel’s fuel cargo capacity of 5,200 cubic meters, the charter significantly increases Titan LNG’s delivery capabilities. The Green Zeebrugge joins Titan LNG’s two already operational barges (FlexFuelers 001 and 002) and will provide better loading economics for Titan LNG. Michael Schaap, Titan LNG’s Commercial Director Marine commented: “We are excited to announce the chartering of the Green Zeebrugge. January has proven exceptionally busy, underlining the timeliness of our decision to secure this additional capacity. Titan LNG carried out seven LNG operations during one weekend, three of which were to large crude shuttle tankers from Equinor, a term contract partner of Titan’s. Using the Green Zeebrugge we were able to ensure safe and timely deliveries to all the vessels.” Longer term, the charter will increase the accessibility and uptake of LNG as a marine





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fuel, as the cleanest available fuel today. “The use of LNG as a marine fuel has a multitude of benefits — not least its clear pathway to meeting decarbonization targets through the introduction of bio and synthetic LNG,” says Schaap. “Establishing agreements such as these will help provide greater accessibility to the fuel, enabling more shipping companies to start the journey towards a zero-carbon future today. The expansion of our service area provides excellent opportunities for Titan LNG to gain new customers and serve our current ones even better.” With the anticipated further acceleration of LNG bunkering demand, Titan LNG is nearing taking a Final Investment Decision on proceeding with the 8,000 cu.m vessel Titan LNG Hyperion, that would be available early 2023. Titan LNG says it expects to have the largest network of LNG bunkering vessels in Europe by 2025. The company says it will supply bio-LNG which can be dropped in and blended with LNG using existing infrastructure and engine technology. The next step of using green hydrogen to convert into E-Fuels (synthetic LNG) is under development by Titan for implementation in 2024. Of all available E-Fuels, including ammonia and methanol, says Titan LNG synthetic LNG is the only fuel with a global existing infrastructure and has the best energy density. source : www.marinelog.com

KNUTSEN FIXES LNG NEWBUILDING TO MYANMAR DEVELOPER

Norway’s Knutsen OAS Shipping has chartered a small-scale LNG carrier newbuilding to Chinese power developer CNTIC VPower.. Brokers reported that the 30,000-cbm Ravenna Knutsen has been chartered to CNTIC VPower for six to nine months from early March, starting from its delivery from Hyundai Mipo Dockyard in South Korea. The charterer is a joint venture between Chinese engineering procurement and development contractor CNTIC and power-generation system developer VPower Group. The Ravenna Knutsen was listed as due for delivery in January. Last year, CNTIC VPower put a first LNG import terminal into operation in Myanmar, where the military seized power in a coup on 1 February. The Chinese power developer has used a variety of small-scale tonnage to put this new facility into operation. But it is unclear whether the Ravenna Knutsen will go on station off Myanmar or to another project for the company. The LNG carrier was ordered in late December 2018 by Knutsen at a reported price of $77.5m. Norwegian shipowner Klaveness Marine, which has worked with Knutsen before on LNG carriers, later took a 41% stake in the ship. Chief executive Jon Chr Syvertsen bought into the vessel through his investment company, Adrian. An option to build a sistership appears to have expired. The Ravenna Knutsen is fixed long term to Italian energy company Edison and its partner for 12 years with an option to extend the hire for a further eight years. Edison said that starting from 2021, the vessel, which is fitted with a reliquefaction unit, will be used to supply a small-scale LNG facility it is building in Ravenna’s port in north-eastern Italy, along with 51% shareholder Depositi Italiani GNL. This will provide volumes to ships and trucks in the region. There are relatively few LNG carriers of this size in the global fleet. Last year, CNTIC VPower bought a 28,000-cbm newbuilding resale in China and used it as a floating storage unit for its Myanmar project. Dutch shipowner Anthony Veder snapped up another distressed Chinese resale in 2019. The 30,000-cbm Coral Encanto (built 2018) has been working for New Fortress Energy in the Caribbean. Veder is building another 30,000-cbm LNG carrier at Jiangnan Shipyard in China for delivery in 2022. source : www.tradewindsnews.com





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AVENIR LNG SETS SIGHTS ON ‘BUILDING UP A PRETTY MATERIAL LNG

SUPPLY BUSINESS’

Joint venture Avenir LNG has not yet put any numbers on its planned LNG supply portfolio, but chief executive Peter Mackey hints that the company has serious ambitions in this area. “We have an internal figure and it is not an insignificant sum,” Mackey said. “We see ourselves building up a pretty material LNG supply business. “I don’t see supply being the hard part. The key for us is to focus on areas of stranded demand that have unmet needs in terms of LNG supply in the right parcel sizes, at the right price, enabled by the right assets.” Mackey said Avenir plans to play in multiple sectors across bunkering and supply to the power generation and industrial sectors. He sees huge opportunities in each but added they have different characteristics and counterparties. He said buyers in the power and industrial segments want delivered gas and for a supplier to provide the LNG, shipping and import infrastructure to the point of use. In these businesses, Mackey said Avenir is not typically looked at through a chartering lens, but rather one of an integrated supplier. The LNG bunkering space is different again. Here, Mackey said, some LNG fuel suppliers may be looking for tonnage under a traditional shipping model. But increasingly, where newbuildings are being ordered, counterparties are looking for LNG delivered to their vessels as they are not necessarily in that product market. Energy majors such as Shell and Total, which are active in the big bunkering hubs of Rotterdam and Singapore, may be competitors in these areas. But Mackey said: “There is a huge volume of marine traffic out there that exists outside those main hubs and that’s a huge opportunity set for us.” Geographically, he sees the Caribbean, Central and Latin America as major areas of opportunity for Avenir. The Mediterranean will also be of key importance for the company with its anchor terminal in Sardinia. Mackey and his team are also eyeing potential projects in Asia and markets in South East Asia. Here, he said, the energy transition is prompting demand from smaller distributor power plants that either need small-scale supply solutions or are moving away from heavy fuel oil and diesel and towards natural gas. “Opportunity is not the challenge for us at the moment,” he said. “There is a lot of potential out there.” So, will the company need to expand its six-ship fleet? Shortly after founding Avenir, Golar LNG chairman Tor Olav Troim — a shareholder of Avenir — spoke about a possible 50-vessel fleet for the small-scale company. “We are being very thoughtful about how we grow the company,” Mackey said. “Being asset enabled is a huge differentiator for us. “As the business grows, we will keep our asset position under constant review. We would want to find ourselves in a position where we are having to have difficult conversations about growing the fleet. That’s a nice problem to have.” source : www.tradewindsnews.com

ZICOM SECURES US$45M LNG PROPULSION ORDER FOR TANKER

NEWBUILDS

Zicom said it will supply the LNG propulsion systems to Chinese shipbuilder Guangzhou Shipyard International Co between 2022 and 2023. While the European shipowner was not disclosed, Guangzhou Shipyard International has secured orders to build a number of dual-fuel tankers, most recently two LNG-powered LR tankers for Hafnia Shipping. “This order underscores the gathering momentum in the transformation of our marine sector,” said Zicom group chief executive Sim Kok Yew. “IMO 2020 rules mandate that all oceangoing vessels are required to reduce sulphur emissions… to 0.50% with effect from 1 January 2020. This has made it mandatory for existing vessels to install scrubber filtration systems or to use high grade low sulphur





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fuel in place of diesel to comply,” he said. “Each of these choices has proven to have its limitations. New vessels would install gas engines instead of diesel engines and use LNG propulsion to power the engines. The growth prospects for our technology are therefore expected to be strong.” In a way, the order itself grew out of Zicom’s own transformation, Mr Sim noted. “As our deck machinery products hit a downturn about five years ago, the group recognised that a transformation of our marine sector was critically needed. To continue to leverage on the group’s network and knowledge of the industry, it decided three years ago to develop technology for green energy propulsion systems for oceangoing vessels. This direction enables the group to expand its footprint to cover the entire shipping industry and not just focus on offshore marine applications.” While noting the offshore marine sector was showing some positive signs, Mr Sim said short-term prospects for Zicom’s deck machinery products was “not apparent,” but added gas processing projects remain strong. source : www.rivieramm.com

ZEEBRUGGE LNG TRANSSHIPMENTS SURGE IN 2020

The Zeebrugge LNG terminal in Belgium saw record activity in 2020, operator Fluxys reported on February 2, thanks to a surge in transshipment operations. Some 111 transshipment operations took place at the facility during the year, versus only 38 in 2019. Russian LNG exporter Novatek began using a new transshipment tank at Zeebrugge in December 2019 to handle cargoes from its Yamal LNG project. The tank was built specially for this purpose under an agreement between Novatek and Fluxys and has no pipeline connection with the Belgian grid. It enables the more expensive winterised vessels to be used for their primary purpose in the Arctic so that cheaper vessels can collect cargoes for final delivery. Unloading operations at Zeebrugge declined last year, to 50 cargoes from 71 in 2019, while small-scale reloading halved from 20 to 10. As in 2019, only one reloading operation took place at a conventional LNG carrier during 2020. Total vessel operations increased to 172 last year, from 130. Fluxys added that that some 3,195 trucks were loaded with LNG in 2020, representing a record high. A monthly record of 418 was also set in January 2021. source : www.naturalgasworld.com

THAILAND SELLS SURPLUS LNG TO JAPAN, EMERGING AS RE-

EXPORTER

Thailand's state-owned energy conglomerate PTT has shipped liquefied natural gas to Japan for the first time as it looks to re-export fuel for power plants to energy-hungry countries. The first shipment left a PTT terminal in central Thailand late last month and arrived this week in Japan, which is experiencing a seasonal supply shortage, Nikkei Asia has learned. The unidentified buyer is thought to be a major energy company. The cargo of roughly 145,000 cu. meters is enough to power 50 million households for one day, provided the entire volume is used for thermal power generation.PTT will "explore more opportunities," tapping the country's "infrastructure and proximity to Japan, South Korea, China and Taiwan, all of which are big LNG buyers," a source at the company told Nikkei Asia.Thailand has a glut of LNG due to a lack of winter heating demand and the pandemic, which is throttling industrial electricity usage.But demand is surging elsewhere, tripling spot prices in Asia over a one-month period through mid-January to a record high of more than $30 per million British thermal units at one point. PTT likely charged spot prices when selling the LNG to Japan after buying it at a lower cost under long-term agreements,





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thereby pocketing a hefty profit. As the biggest publicly traded company in Thailand by market capitalization, PTT buys LNG from Malaysia and Qatar, mostly under long-term contracts. Projecting more domestic demand for electricity, Thailand -- which mainly uses locally produced natural gas for its energy needs -- plans to increase procurement and is expanding import terminals, with a second facility slated for completion next year. But this strategy comes at the risk of being stuck with a surplus if demand declines at home.Re-exporting excess LNG to other countries solves this problem while creating a new source of income and reducing the cost of LNG storage. The Thai government even envisions transforming the country into an international LNG trading hub. source : www.asia.nikkei.com

ADRIATIC LNG READIES MASSIVE REGAS CAPACITY AUCTION

As much as 153 billion cubic meters per year (bcm/y) of LNG regasification capacity could be considered for the next 25 years during Adriatic LNG’s open season. All gas and LNG market players – both at national and international levels – will have access to Adriatic LNG proposals on www.adriaticlng.it/en and can send comments until 22 March 2021. The auction by Adriatic LNG complies with new rules put in place by the Italian Ministry of Economic Development and the Italian Regulatory Authority for Energy, Networks and Environment. As a result, Adriatic LNG will be able to offer products with a duration up to 25 years, with the start of open season during Europe’s summer 2021. Calling the open season “one of the most important events for the entire energy market” in the Mediterranean, Adriatic LNG law and market manager Sebastien Bumbolo said, “This is one of the largest regasification volumes ever auctioned, equivalent to over two years of natural gas consumption in Italy if we consider the average annual consumption of recent years.” Adriatic LNG said the capacity offered through the open season could reach 153 bcm/y, considering existing capacity (1.6 bcm/y and, from end 2034, 8 bcm/y), already technically available additional capacity (1 bcm/y) – as provided for in the project for additional terminal capacity submitted to the Ministry of Economic Development – and new capacity to be developed (0.5 bcm/y). Mr Bumbolo said “Our offer represents an extraordinary opportunity for national and international gas market players to diversify their portfolios by leveraging on the great potential offered by the global LNG market. In this way, Italy will have a new instrument to increase natural gas internal market’s competitiveness by attracting the intrinsic value of an energy source, the gas in the form of LNG, produced in many parts of the world and sold in a competitive market.” Operating since 2009 off the Veneto coast, the Adriatic LNG regasification terminal provides about 10% of Italy’s national gas consumption. Adriatic LNG has regasified and delivered to the national pipeline network more than 69 bcm of gas supplied by ships carrying LNG from Qatar, Egypt, Trinidad and Tobago, Equatorial Guinea, Norway, Nigeria, the United States and Angola. The Adriatic LNG terminal can accommodate LNG carriers with capacities from 65,000 m3 to 217,000 m3 of LNG. Adriatic LNG is operated by ExxonMobil Italiana Gas and Qatar Terminal Limited, a subsidiary of Qatar Petroleum, and SNAM. “In Italy, we are the only international hub in the liquefied natural gas market,” noted Mr Bumbolo. This is important to countries needing access to secure supplies of clean-burning natural gas for the energy transition, said Adriatic LNG external relations manager Alfredo Balena. “At Adriatic LNG, we feel part of this energy transition. LNG is a strategic source for achieving climate goals and for the diversification of sources through sea-transported competitive, flexible supplies.” source : www.rivieramm.com





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GAZPROM, NOVATEK "COMPETE IN EUROPE"

Gazprom faces competition in Europe from domestic rival Novatek, a leading Russian lawmaker has said, proposing that extra taxes or sales restrictions be imposed on the latter's Yamal LNG project to prevent this. This competition is causing serious losses to the state budget, said Pavel Zavalny, who heads the energy committee of the State Duma, Russia's lower house of parliament, on February 2. The Duma should create a working group to discuss potential measures. "We have to define conditions for target markets, volumes and price limits so that the budget does not lose out," he said at a meeting. "Otherwise, it appears that gas monetisation occurs for the sake of monetisation, and the state does not receive anything." Around 84% of Yamal LNG's supplies have gone to Europe since its launch in December 2017, he said, and 69% have been delivered to markets where Gazprom's pipeline gas is sold, citing Gazprom data. Novatek CEO Leonid Mikhelson hit back. "LNG is a global market. How can this be written into law?" He was quoted as saying by Russia's Tass news agency. The statistics cited by Zavalny are wrong, he added, estimating that more than 50% of Yamal LNG's cargoes had gone to Asia. The 16.5mn metric ton/year Yamal LNG project enjoys significant tax breaks and this undermines the budget, Zavalny said, proposing changes to maximise tax revenues from gas exports. Yamal LNG pays no mineral extraction tax, property tax or export duties for LNG. It also pays a reduced profit tax of 13.5%. Gazprom has complained about Novatek's expanding sales in Europe in the past, although this is the first time the Duma's energy committee has proposed measures against Novatek as a solution. But ensuring that Russia's two leading gas suppliers do not compete is easier said than done. "There is no way to ring-fence Gazprom's European gas franchise from the influence of rising LNG production by Novatek," Ron Smith, analyst at Moscow-based brokerage BCS Global Markets, told NGW. "Even if 100% of Novatek's LNG were to be sent to Asia, it would only displace other LNG to Europe." Gazprom also competes with Novatek in Asia, through the Sakhalin LNG project and the Power of Siberia pipeline, although on a smaller scale. Gazprom has a small stake in Novatek. source : www.naturalgasworld.com

QUEBEC LNG PROJECT COMMITS TO CARBON NEUTRALITY

GNL Quebec committed February 5 to making its proposed Energie Saguenay LNG project in the Canadian province of Quebec carbon neutral by offsetting all of the liquefaction terminal’s direct greenhouse gas (GHG) emissions. The 11mn mt/yr terminal will draw its compression and liquefaction power from the Hydro Quebec provincial grid, which is largely based on hydroelectricity. Still, annual emissions are expected to total 421,000 metric tons (mt) of CO2 equivalent – 420,000 mt of CO2 and 1,000 mt of fugitive methane emissions. In 2018, GNL Quebec commissioned the chair in eco-consulting at the University of Quebec at Chicoutimi (UQAC) to identify credible, effective and measurable actions to offset the terminal’s emissions. Its report, submitted in September 2019, identified four priority sectors to achieve carbon neutrality: reforestation in areas being actively harvested; capture, purification and use of CO2 emissions; purchase of renewable natural gas (RNG) produced from forest residues; and purchasing offset credits on regulated or voluntary markets. Reforestation was judged to be the least effective option, given the time required for trees to store CO2, while carbon capture and use offers the greatest potential, the study found. It might even be enough on its own for Energie Saguenay achieve carbon neutrality by 2030. “But





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it would require the development of an innovative eco-industrial park to recover both the CO2 and the industrial heat generated by the liquefaction terminal,” an executive summary of the UQAC report says. “This would require modifying the liquefaction facility and finding partners to utilise these resources using an eco-industrial approach.” Purchasing RNG to supplement Energie Saguenay’s feed gas supply also offers good potential, the report says, but the “technological readiness” of pyrolysis, the distances to transport the residues close to the Gazoduc pipeline (which will deliver gas to the terminal) where the RNG would be produced, and potential competition for other uses of the residues “make this potential very uncertain.” It’s unlikely RNG could contribute to carbon neutrality before 2030, the UQAC study concludes. Finally, the study found that the purchase of offset credits “will be necessary” for the terminal to achieve carbon neutrality. “There are enough credible serialized credits currently available on voluntary markets to ensure carbon neutrality at least for the period 2025-2030, and it is likely that, as other measures are deployed, it will be possible to supplement the balance of Energie Saguenay’s emissions through annual offset credit purchases for the duration of its operations,” the report says. Both the terminal project and the proposed 780-km Gazoduq pipeline are the subject of ongoing federal and provincial environmental reviews. The provincial review resumed in September 2020 after being halted due to Covid-19 protocols; a recommendation from the federal Impact Assessment Agency of Canada is expected by September or October, with a cabinet decision to approve unlikely before year-end. source :

www.naturalgasworld.com

INDIAN LNG FACES QUANDARY

Natural gas is seen as one of the key ways of reducing India’s high dependence on coal and mitigating the severe environmental problems caused by its use. In 2019, coal accounted for 55% of total Indian primary energy supply and 73% of its overall electricity generation, according to the BP Statistical Review of World Energy 2020.

The government’s strategy for reducing coal production and use is based in part on large-scale investment in renewable energy. The targeted installation of 510 GW of solar, wind, hydro and other renewable capacity by 2030 is officially projected to meet 60% of national electricity requirements in that year. But implementing the coal-reduction strategy is also predicated





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on raising gas’s share of total primary energy supply from 6.3% in 2019 to 15% in 2030.

The government reiterated its commitment to achieving the 15% goal on January 5, when Prime Minister Narendra Modi said that over the period to 2024 some $60 billion would be invested in gas infrastructure. This would include completion of the construction programme for 16,000 kilometres of trunk pipelines that began in 2014, as well as spending on city gas distribution networks, 10,000 compressed natural gas (CNG) fuelling stations, and LNG import terminals. The government’s target for gas use will require a very substantial and rapid increase in gas demand from the 59.7bn m3 consumed in 2019. Consultants Wood Mackenzie estimated in October 2020 that gas use would have to rise almost three-fold to 170bn m3 to meet the 15% target in 2030. Domestic production falters Most of that additional demand will have to come from imports. Indian natural gas production has declined markedly over the past decade, with output falling from 47.4bn m3 in 2010 to 26.9bn m3 in 2019. The period did see some growth in onshore production, while coalbed methane extraction also increased, albeit from a low base.





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However, these gains were more than offset by a slump in offshore production, driven by problems in the KG-D6 block of the Krishna Godavari basin. Offshore output almost halved in the April to October period of 2020, compared with the same seven-month period of 2012, and was 15.7% lower than for the same period in 2019. The 2020 decline in gas production partly reflected the impact of the Covid-19 pandemic on economic activity and energy use. Indian gross domestic product fell by 7.7% year on year in the April to October period, while industrial production fell 15.5% on year from April to December. Gas output had already been hit by lower, pandemic-affected demand from the industrial and other sectors towards the end of the financial year to March 2020, with annual production of 31.17bn m3 being the lowest recorded for two decades. But the long-run decline in Indian offshore output remained the underlying reason for the year-on-year fall in 2020. That said, some reversal of the long slide in Indian offshore gas production is likely in the future. The development by a 67/33 joint venture between the local Reliance Industries Ltd and BP of the R Cluster deep-water field in KG-D6 has been completed, with gas due to be sold from February and output expected to plateau at 12.9mn m3/d. The R Cluster will be followed this year by the Satellites Cluster and in 2022 by the MJ project. Output from the three projects, which have access to some 85bn m3 of resources and cost about $6 billion, is expected to reach 11bn m3 in 2023.

Nor are these projects isolated. For instance, ONGC is developing a separate suite of deep-water projects in the KG Basin that could produce up to 30bn m3 by 2024. LNG imports to rise However, these and other new developments appear unlikely to keep pace with the projected growth in gas demand. To achieve its social and economic growth objectives, India will have to become more reliant on imports, which at least in the near to medium term means more LNG. While the country has looked at importing gas from central and west Asia through cross-border pipeline projects for many years, few of the projects have made much progress. For instance, developments were reported sporadically in 2020 on the 33bn m3/yr Turkmenistan-Afghanistan-Pakistan-India project, but its implementation





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remains no more probable than over the past decade, not least in the case of India because of the security risks associated with its route. That has left the field open to LNG. India’s stock of operational LNG import terminals has increased to six with combined capacity in excess of 40mn mt/yr (55bn m3/yr), while a large number of other projects are at various stages of development. LNG imports almost tripled from 11.5bn m3 in 2010 to 32.9bn m3 in 2019, according to BP data. Indian LNG imports continued growing in the last nine months of 2020, despite the pandemic-induced slump in economic activity. LNG imports from April to December

grew by 0.7% year on year to 24.75bn m3. The 5.3% year-on-year fall in gas consumption to 45.2bn m3 during this period was more than offset by the 11.3% year-on-year drop in domestic gas output to 21.1bn m3. The growth in imports was assisted by the fact that for much of the period the global LNG market was awash with large volumes of low-priced spot cargoes. The Indian economy recorded a marked uptick towards the end of 2020 with, for instance, industrial production being down only 1.9% year on year in December. With energy demand indicators also moving upwards this suggested Indian LNG demand would grow strongly. Price sensitivity However, international spot LNG prices jumped at the end of the year. A surge in North Asian demand resulting from cold weather coincided with supply disruptions and some production constraints to push prices to record levels. Indian activity in the market dropped sharply thereafter, with several planned tenders for spot LNG being cancelled because of a lack of acceptable price offers.

One of the main issues here is that a large part of Indian gas is consumed in sectors which sell their products on the basis of artificially low, controlled prices. The fertiliser sector, which consumes around a third of Indian gas, has been one of the main problem areas in this respect. It has usually sought gas -- whether domestic or imported – at a price which is below cost when netted back to the gas supplier. And where fertiliser producers have paid a market price for gas, payment problems have





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occurred when government subsidies were delayed or not forthcoming. Gas sales to the Indian electricity generation sector have also had their fair share of problems as a result of controlled retail prices, but a key issue in the sector at present is the competition from power generated from low-cost coal and renewable energy plants. This is one of the reasons why the plant load factor of India’s 24 GW or so of gas-fired capacity is generally low at 25% or less – use of the fuel is uncompetitive at realistic gas prices. The low spot prices prevailing for most of 2020 did see Indian gas-fired generation increase as more spot LNG was burnt. This helped push gas-fired output over the period from April 2020 to January 15 this year to about 13% above the planned level for the period. Spot LNG accounted for a third or so of gas burn in several months including June and October, according to data from the Central Electricity Authority. This was well up on previous years, with much of the gas use involving spot purchases burnt in Gujarat state. However, the subsequent price rise is expected to curtail gas-fired generation again. How gas use evolves in the power sector in the next few years will be the key factor determining whether India can meet its 15% target for gas in 2030. Electricity generators use much larger amounts of additional gas than individual consumers in sectors such as industry and transport. They also already own a substantial amount of operational, but under-utilised capacity with existing links to the gas distribution network and LNG import terminals.The additional gas burn could also have a direct impact on reducing coal pollution, while gas-fired generators operating on intermediate load can help balance grids that will be increasingly reliant on supplies from renewable energy plants.However, to ensure sufficient additional gas is used these advantages will need to be factored into the relative price of gas-fired and other generation, for instance through carbon pricing and other measures to penalise coal use, or through payments for grid support. This will, in turn, largely determine how much additional LNG is imported, and whether the preference is for more term or spot volumes of the fuel. Gujarat state, where 25% of energy demand is already met by gas, shows that the 15% target for 2030 is attainable, if the necessary infrastructure and energy pricing structures are put in place.How much gas is used and LNG imported over coming years will come down to whether individual states and the country as a whole make more progress in these respects. Recent initiatives suggest moves are being made in the right direction, including the decisions to unify trunk pipeline tariffs and scrap domestic output price ceilings. Source : www.naturalgasworld.com

LNG IN VIETNAM'S POWER SECTOR

Hanoi last year prepared the Power Development Plan-8 (PDP-8) which was sent to the ministry of industry and trade (MOIT) in November, from where it will then go to the prime minister’s office for approval. The PDP-8 is expected to get the final green light from the prime minister’s office during the first quarter of this year, said Vi Le Nhuan from the Institute of Energy, which comes under the MOIT. Vi was speaking at an industry webinar mid-December. The PDP-8 indicates a move away from fossil fuel-based power generation towards renewables and LNG. It considers the 2021-2030 period with a vision to 2045. The plan envisages electricity production of 537 TWh in 2030 and 959 TWh in 2045, with commercial electricity at 478 TWh in 2030 and 861 TWh in 2045.The annual growth of commercial electricity demand is expected to be 8.3%/year this decade and 3.5%/yr during 2031-45. Total installed capacity is set to more than double from 2019 levels to 138 GW in



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2030 and reach 222 GW in 2040. Out of the total installed capacity of 56 GW at the end of 2019, gas had a 13% share, with coal being the dominant fuel with 36%. However, PDP-8 has cancelled or postponed up to 17 GW of coal-fired capacity, or nearly half of the pipeline up to 2030. The PDP-8 sees LNG-based power at 128.5 GW compared with just 16 GW in PDP-7R. Gas-based power projects will be the key source of power generation in the coming years, Vi said. North Vietnam is expected to have 27 GW of LNG-based projects, north central to have 14 GW, mid-central to have 21.9 GW, south central to have 22.1 GW with south Vietnam to have 46.15 GW. The share of gas and oil in the power mix will be 19% by 2030, which is forecast to rise further to 24% by 2045 as against 15% in 2020, he said, adding gas will be the dominant fuel and oil will have a very minor share. Potential for land-based and float ing LNG terminals Vietnam has a 3,260-km shoreline and, according to Vi, there are many locations fit for development of deep-sea ports. Land-based LNG terminals would be recommended for power plants with capacity bigger than 3 GW while floating storage and regasification unit (FSRU) would be recommended for power projects smaller than 3 GW, Vi said.North and south Vietnam are suitable for FSRU-based projects. There are four FSRU-based power projects under consideration in PDP-8: Hai Phong and Thai Binn projects each with 4.5 GW; the Ben Tre power project with capacity of 3-4.8 GW and the 3-GW Ca Mau project. LNG demand expansion Although domestic gas production is expected to increase over the next few years, there is a shortfall in demand that the government is anticipating will be filled by LNG. About 14.6bn m3/yr of domestic gas is likely to supplied to power plants by 2025, almost double the 7.7bn m3/yr now. This is expected to then fall to 9.2bn m3/yr by 2030 and again to 7.7bn m3/yr during 2035-2045. Demand for LNG in Vietnam’s power sector is expected to reach 8.5mn metric tons (mt)/year by 2030, the country's industry and trade ministry said in September last year. The ministry expects demand for LNG in the power generation sector to reach 1.2mn mt/yr by 2025. At present, Vietnam does not import any LNG. The southeast Asian country is promoting gas-fired power as it moves away from coal and oil-based generation. However, coal is expected to retain its dominant position. The ministry sees demand for coal in power generation reaching 35mn mt/yr in 2025 and 45mn mt/yr by 2030. In the period of 2021-2025, it is planned to build three to four LNG terminals with estimated capacity of 1-3mn mt/yr. During 2026-2035, Vietnam plans to build about five to six LNG terminals with the capacity of around 3mn mt/year each. The visibility of strong growth in the sector has attracted many global players, especially from the US, as well as local investors. In June last year, PetroVietnam Power, a subsidiary of state-run PetroVietnam, announced plans to build four gas-based power plants. In the same month, the Vietnamese government said the US major ExxonMobil was looking to invest in gas-to-power projects. US-based AES Corporation and state-run PetroVietnam Gas, another subsidiary of PetroVietnam, signed an agreement last year to develop the Son My LNG terminal. AES was granted approval by Vietnam’s government last year to





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develop a 2.2-GW combined-cycle gas turbine power plant in the south-central Binh Thuan province. The Son My 2 plant will have a 20-year power purchase contract with the government and is expected to achieve financial close in 2021 and begin commercial operations in 2024. The government said it will need $133.3bn in new power plants and transmission networks over the next decade to meet the country's rising demand. Of the total, $96bn would be needed to build new power plants and $37.3bn to enhance the power grid. Some questions remain According to US-based Institute for Energy Economics and Financial Analysis (IEEFA), the significant long-term question for PDP-8 is how the proposed LNG projects will develop. “PDP-8’s aggressive embrace of LNG comes at a time when there are is little clear information concerning Vietnam’s LNG development policies,” IEEFA said in late-September. “This embrace of LNG comes at a time when 80% of Vietnam’s offshore gas output is used for power generation. Domestic natural gas production has been expected to peak by 2026, although the recent announcement of a new offshore gas discovery by Eni may extend this forecast.” Eni announced last summer that it found resources at Ken Bau in the Song Hong basin, where it operates and wholly owns neighbouring Block 116. Estimates put resources between 7 and 9 trillion ft3 of gas in place with 400-500mn barrels of condensates. “The gas market in Vietnam is rapidly growing, driven by the country’s consistent GDP progress and the consequent development of gas-to-power plants supplied by domestic resources and, in the future, imported LNG. The Ken Bau discovery will potentially provide a fast-track solution to meet the increasing energy demand,” Eni said.IEEFA stated that despite clear signs of policy commitment, many fundamental questions about how the links in the LNG value chain will evolve in Vietnam have yet to be answered. “At a time when the global gas market is facing existential questions about long-term market structures, this is not a minor issue. As a result, the full cost of integrating a large commitment to LNG into Vietnam’s energy and power markets is not yet fully understood domestically, or by regional analysts,” it said.One of IEEFA’s biggest criticisms is that there is neither a comprehensive master plan nor a centralised management model for Vietnam’s LNG industry. LNG terminals and gas-fired power projects are governed under two separate sectoral master plans and integrated LNG-to-power projects proposals are scattered across the country. This underscores the need for systematic planning of LNG hubs to ensure that investment in the LNG terminals is linked efficiently to downstream power plants and industrial consumers, it said. Also, PetroVietnam’s role in the LNG sector is uncertain. Under the PDP-7R framework, PetroVietnam was given tasks such as developing the LNG importing model and partnering with domestic and foreign investors in LNG infrastructure development. This has not materialised in practice, however, IEEFA said.Citing examples from Bangladesh, Pakistan, Malaysia, and Thailand, PVGas has made the case that it should become the LNG aggregator to handle supply sourcing and distribution in the early stage of the LNG market development. PVGas has been granted the exclusive rights to import LNG through its Thi Vai terminal to fuel the group’s gas-fired power plants, but it remains unclear if those rights will apply elsewhere. Despite the lack of policy clarity, as mentioned earlier, there has been a surge of interest in integrated LNG-to-power project investments from foreign developers. IEEFA said that this apparent disconnect between





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planning and execution raises questions about state-owned utility Vietnam Electricity (EVN)’s ability to manage the cost of LNG-fired IPPs.“Building the necessary LNG infrastructure is destined to be costly. If history is any guide, MOIT will need to drive an extremely hard bargain with gas suppliers and should push back against the fixed contract terms that financially constrained US developers may seek,” IEEFA said. EVN's infrastructure cost burden IEEFA cautions that investors will need to pay close attention the question as to how much of the cost of the associated infrastructure – regasification, storage, and transport – will be passed through to EVN. Disclosures in the preliminary PDP-8 documents suggest that EVN’s LNG prices will only include a pipeline transportation charge but not a charge for the cost of LNG infrastructure. Recent IEEFA research into China’s gas market development experience suggests that this may not be a realistic expectation and that the development of China’s gas market may not favor high-cost American LNG producers over the long term. “The complex cost structure of US LNG, which includes anything from feedstock costs, liquefaction fees and shipping costs to regasification and pipeline transportation fees, means that any moderate increases in these cost omponents could easily make US LNG uncompetitive against cheaper pipeline imports, domestic gas or other global LNG suppliers,” IEEFA said.At this stage, the regulatory and market realities that will determine EVN’s ability to pay for a major shift toward gas-fired power capacity remain in flux. As a result, it will be crucial to track developments in the global LNG market, it added. Source : www.naturalgasworld.com

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