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LNG demand may fall post 2040 due to global GHG emissions policies

Cheniere Energy expects LNG demand to increase until 2040, though it may decline beyond that due to continued global action to reduce greenhouse gas emissions, presenting risks for existing US liquefaction terminal operators and project developers, the company said April 9.

The conclusions were issued in a report assessing the long-term impact of climate change mitigation policies and trends that are in process or under consideration globally.
North American exporters are under pressure to show that LNG produced from shale gas can bridge the energy transition to greater use of cleaner-burning fuels and aid rather than impede buyers' carbon reduction goals. At the same time, they must address how a future of lower demand for fossil fuels will impact their growth goals. Some developers have delayed or canceled new projects.
"Cheniere can minimize the risk beyond 2040 to its business from peak demand by maintaining a disciplined capital investment and return strategy, consistent with expected market trends," the company said in the report.
Cheniere's analysis relied on three scenarios. One produced by the International Energy Agency accounts for existing policy frameworks and announced policy intentions, including the Paris Agreement, and reflects the potential impact of these on the energy sector out to 2040. The second, also published by the IEA, involves sustainable development more generally. The third, by consulting firm McKinsey, is part of its global gas outlook to 2050.
In addition, Cheniere incorporated cost-curve analysis of LNG projects based on projected supply, demand, costs and carbon pricing.
"Under all three scenarios, demand for LNG increases from 2020 levels through 2040, resulting in supply gaps to varying degrees," the report said. "Additional LNG supply, i.e., beyond existing and under construction liquefaction projects, would be needed to meet this demand."
The report added that "continued action to reduce global GHG emissions may cause LNG demand to decline beyond 2040."
Cheniere hopes to be producing LNG from its ninth and, for now, final liquefaction train by the end of this year.
Source: SP Global
Uganda, Tanzania, oil firms sign accords to build $3.5bln pipeline

Uganda, Tanzania and oil firms Total and CNOOC on Sunday signed agreements that will kickstart the construction of a $3.5 billion crude pipeline to help ship crude from fields in western Uganda to international markets.

France's Total and China's CNOOC own Uganda's oilfields after Britain's Tullow exited the country last year.
The signatories have now agreed to "to start investment in the construction of infrastructure that will produce and transport the crude oil," said Robert Kasande, permanent secretary at Uganda's ministry of energy.
Ugandan President Yoweri Museveni and Tanzania's new leader Samia Suluhu Hassan, on her first official visit, attended the signing of the three accords that included: a host government agreement for the pipeline, a tariff and transportation agreement and a shareholding agreement.
Uganda discovered crude reserves in the Albertine rift basin in the west of the country near the border with the Democratic Republic of Congo in 2006. Government geologists estimated total reserves at 6 billion barrels.
However, the landlocked east African nation needs a pipeline to transport the crude to international markets.
The planned East African Crude Oil Pipeline (EACOP), with a length of 1,445 kilometres (898 miles), will run from the oilfields to Tanzania's Indian Ocean seaport of Tanga.
Uganda's crude is highly viscous, which means it needs to be heated to be kept liquid enough to flow.
Total has said EACOP could potentially be the longest electrically heated crude oil pipeline in the world.
"It's a very large project, one of the largest we should develop on this continent," Total's CEO, Patrick Pouyanné said, adding they expected oil production to commence in early 2025.
To get the Ugandan crude flowing, Pouyanné said investments of more than $10 billion were required.
The pipeline has met resistance from environmentalists who argue it will threaten ecologically sensitive areas along its route, including wildlife reserves and water catchment areas for Lake Victoria.
About 263 non-governmental organisations (NGOs) from around the world have urged the chief executives of 25 banks not to extend loans to fund the pipeline.
The project, they say, would pose immense threats to local communities, water supplies, and biodiversity in Uganda, Tanzania, Democratic Republic of Congo and Kenya.
"This pipeline project can be a core of bigger deployments," said Museveni, adding investors could use the EACOP land corridor to put up another pipeline to ship gas from Tanzania and Mozambique to consumers in Uganda, Rwanda, Congo and other countries in the region.
Source: Zawya
Indonesia’s Balongan refinery returns to normal

Indonesian state-owned refiner Pertamina's 125,000 b/d Balongan refinery has returned to normal operations following a shutdown after a fire at its storage tanks.

Balongan's start-up process began on 31 March by first restarting its crude distillation unit and its secondary units, including the gasoline-producing unit, the residual catalytic cracker. The refinery has started to operate normally since 7 April, according to Pertamina.
A fire broke out at one of Balongan's tanks on 29 March, forcing the refinery to be shut down to prevent the spread of the blaze.
Balongan accounts for about 12pc of Indonesia's refining capacity and supplies oil products for the capital Jakarta, Banten and west Java. Pertamina's 348,000 b/d Cilacap refinery increased production to help meet the shortfall during Balongan's closure.
Asian gasoline margins rose above $7/bl for the first time this year supported by the Balongan fire but edged down following news of the restart. The margins, or Argus' 92R gasoline premium against Ice Brent crude, rose from $5.78/bl on 26 March to $6.17/bl on 29 March, the day of the fire. They rose to a high of $7.27/bl on 31 March but then fell to $6.59/bl, a day after the restart.
Source: Argus
Opec raises 2021 demand growth forecast, weighted to 2H

Opec has raised its forecast for oil demand growth this year to take into account a stronger economic recovery than in previous estimates.

The group's latest Monthly Oil Market Report (MOMR) puts global oil demand at 96.46mn b/d this year, up by 190,000 b/d from its previous report and 5.95mn b/d higher than last year.
"The upward revision mainly takes into account a stronger economic rebound than assumed last month, impacting primarily OECD oil demand in the second half of 2021, supported by stimulus programmes and a further relaxation in Covid-19 measures, amid an accelerated vaccination roll out," the report said. It sees the "bulk of consumption growth" this year taking place in the second and third quarters, when respective global demand will rise by 12.0mn b/d and 6.5mn b/d on the year.
But Opec revised lower its oil demand estimates for the first half this year because of new virus waves and resulting lockdowns in Europe, as well as "sluggish" first-quarter demand data for the non-OECD region. It said the "fragile" and uncertain recovery will require "vigilant monitoring of market developments", which include the possibility of new Covid-19 variants, rising sovereign debt in most economies, and a potential further rise in inflation that may tighten monetary policies.
The report sees non-Opec liquids supply for 2021 at 63.83mn b/d, up by 930,000 b/d from 2020. The previous MOMR put non-Opec supply growth at around 950,000 b/d on the year. Opec expects US liquids supply to grow by 160,000 b/d on the year to 17.78mn b/d, but Opec said that higher oil prices could result in a further production increase this year.
Opec has revised higher the call on its own members' crude by around 160,000 b/d from its previous projections to 27.42mn b/d. This is up by 4.94mn b/d from 2020. Opec crude production averaged 25.04mn b/d in March, up by 201,000 b/d from February according to secondary sources that include Argus.
Opec said that there have been "sizeable drawdowns" in global inventory levels since the middle of 2020, which it expects to continue in the coming months. Citing preliminary data, it said that OECD commercial stocks fell by 44.9mn bl in February from January to 2.978bn bl. This is up by 94.1mn bl from a year earlier, and 57mn bl above the 2015-19 average. In January, the Opec+ group recommended keeping the 2015-19 period as the basis for gauging the five-year average of OECD commercial oil stock levels, saying 2020 was an "exceptional year" that would distort the figures.
Source: Argus
China’s crude imports rebound in March

China's crude imports rebounded sharply in March from a year earlier, when demand was hit by a nationwide Covid-19 lockdown, and held largely steady from February as strong margins boosted demand.

Imports were 11.69mn b/d last month, up by 20.8pc from March 2020, preliminary customs data show.
Deliveries were only slightly lower than February's 11.73mn b/d. China imported 11.29mn b/d of crude in the first quarter, up by 10pc on the same period last year.
Chinese refiners stepped up their crude purchases ahead of the lunar new year in mid-February on signs of strengthening demand and rising refining margins. Most refineries were also raising operating rates ahead of the typical maintenance season in the second quarter, which is heavier than usual this year.
China has also ramped up its imports of Iranian crude this year, to almost 500,000 b/d in the first quarter, although this is not reflected in the official data.
A full breakdown of imports by origin will be published later this month.
Source: Argus
U.S. shale oil output to rise 13,000 bpd to 7.61 million bpd in May

U.S. oil output from seven major shale formations is expected to rise for a third straight month, climbing by about 13,000 barrels per day (bpd) in May to 7.61 million bpd, the U.S. Energy Information Administration said on Monday.

The biggest increase is set to come from the Permian, the top-producing basin in the country, where output is expected to rise by 52,000 bpd to about 4.47 million bpd, the highest since April 2020, the EIA said in a monthly forecast.
Output from other top producing basins such as the Bakken and Eagle Ford are expected to slide by 12,000 bpd and 9,000 bpd, respectively. Production in the Bakken basin of North Dakota and Montana is expected to drop to 1.1 million bpd, the lowest since July 2020, according to the data.
Oil producers in the United States have begun to slowly add drilling rigs as prices rebound, but tepid demand recovery and investor pressure to reduce debt have kept companies from rushing to increase production. [RIG/U]
Natural gas production from the major shale basins was expected to decline about 0.1 billion cubic feet per day (bcfd) to 82.8 bcfd in May, according to EIA’s drilling productivity report.
That compares with a monthly record high of 86.9 bcfd in December 2019.
Gas output in Appalachia, the biggest shale gas basin, was expected to decline 0.1 bcfd to 34.1 bcfd in May, its lowest since October 2020. That compares with a monthly record of 35.2 bcfd in December 2020.
If correct, that would put output in Appalachia down for a record fifth month in a row, according to EIA data going back to 2007.
Gas output in the Haynesville, meanwhile, rose 0.1 bcfd to a record 12.2 bcfd in May.
EIA said producers drilled 464 wells and completed 641 in the biggest shale basins in March. That left total drilled but uncompleted (DUC) wells down 177 to 6,912, their lowest since November 2018.
That was the most for drilled and completed wells since April 2020 and put DUCs down for a record ninth month in a row, according to EIA data going back to 2014.
Source: Hellenic Shipping
Gulf of Mexico crude oil production will increase with new projects in 2021 and 2022

EIA forecasts U.S. crude oil production in the U.S. Federal Gulf of Mexico (GOM) to increase in the next two years, according to the latest Short-Term Energy Outlook (STEO). By the end of 2022, 13 new projects could account for about 12% of total GOM crude oil production, or about 200,000 barrels per day (b/d).

The GOM accounts for 15%–16% of U.S. crude oil production. In 2020, GOM crude oil production averaged 1.65 million b/d. Production is forecast to exceed 2020 levels, reaching 1.71 million b/d in 2021 and 1.75 million b/d in 2022. Since 2000, the highest crude oil production year was 2019 at 1.9 million b/d.
Large offshore projects take several years to develop. Four of the new projects will likely begin production in 2021 and nine more in 2022, according to Rystad Energy. Crude oil production is subject to geologic conditions, economics, and project timelines. The future oil markets still remain uncertain, so future projects’ timelines may change accordingly.
Hurricanes are a critical element in the GOM forecast. The Atlantic hurricane season is typically June 1–November 30. Although eight new projects started crude oil production in 2020, annual production was lower than 2019 levels because of pandemic-related shut-ins and the most active Atlantic hurricane season on record. Hurricane Delta shut in 1.6 million barrels of oil production over two days in October, the highest peak shut-in of the hurricane season. However, the combined effects of Tropical Storm Marco, followed quickly by Hurricane Laura, led to 15 days of shut-ins, which more than doubled the total shut-in production from Hurricane Delta and resulted in the most shut-ins since 2008.
Colorado State University’s Seasonal Hurricane Forecasting forecasts that the 2021 Atlantic hurricane season will be above average, compared with the 40-year average. The university estimates 8 hurricanes and 17 named storms. The National Oceanic and Atmospheric Administration will release its Atlantic Hurricane Season Outlook for 2021 in May. A hurricane’s actual impact on the GOM oil and natural gas industry is challenging to determine because the hurricane path has a significant effect on the size of the impact. Hurricane paths cannot be determined until the weather pattern is established, which happens days before the hurricane hits.
To forecast hurricane outages in STEO, we use historical data to determine an average percentage of outages for the Atlantic hurricane season. Historically, most GOM shut-ins occur in October. In 2020, hurricane-related disruptions started earlier than normal with Tropical Storm Marco and Hurricane Laura in August.
Source: Hellenic Shipping
Japan’s Tsuneishi develops LNG-fuelled Kamsarmax

Japanese shipbuilder Tsuneishi Shipbuilding has completed development of an LNG-fuelled Kamsarmax dry bulk carrier, which it deems vital to bridge a transition period from conventional marine fuels to alternatives such as ammonia and hydrogen.

Tsuneishi said today it has obtained approval in principle from international classification society Lloyd's Register for its Kamsarmax GF class, an 80,000-85,000 deadweight-tonne (dwt) bulk carrier equipped with a dual fuel engine that will run on LNG or marine fuel. This allows the company to begin marketing the vessel class and smooth out a process to work out a detailed design for its customers. Kamsarmax is larger than a Panamax, designed for berthing at the Port of Kamsar in Guinea.
The LNG-fuelled Kamsarmax bulk carrier is designed to achieve a 40pc energy efficiency design index (EEDI) reduction, exceeding the International Maritime Organisation's 30pc EEDI phase 3 reduction requirement for bulk carriers after 2025.
Japanese firms are gradually expanding their fleet of LNG-fuelled commercial vessels to meet the IMO's sulphur cap on marine fuel following the launch last year of the car carrier Sakura Leader, the first LNG-fuelled commercial vessel to operate in the country. The government has also backed LNG bunkering operations in in Tokyo bay and central Japan's Ise bay.
Tsuneishi last year started developing LNG-fuelled vessels as it expanded efforts to meet the global shipping industry's increasing environmental requirements. The company said it plans to speed up development of other commercial vessels running on LNG as well as zero-emissions vessels.
It specialises in the construction of 30,000-180,000dwt commercial vessels, such as oil tankers, bulk carriers and container vessels, at its shipyards in Japan, China, the Philippines and Paraguay. It is targeting to acquire a 49pc share in rival Japanese shipbuilder Mitsui E&S Shipbuilding by October this year.
Tsuneishi Craft & Facilities, which specialises in construction of boat and ferries, as well as electric-powered ships, is building a hydrogen-fuelled passenger ferry for Belgium shipping firm CMB. The hydrogen-powered HydroBingo is targeting to start operating in Japan's Seto inland sea this month.
Source: Argus
Flex LNG secures new term charters - April 15, 2021

Norwegian shipowner Flex LNG has secured new term charters for at least four of its carriers, with all but one of its six current term charters set to expire in 2021-22.

The new charters, pending any further agreements, are not set to significantly change the proportions of Flex LNG's 12-strong fleet that operates on the spot and term charter markets, with the owner historically keeping a large section of its fleet on the spot market. All of the firm's carriers have two-stroke propulsion and capacities of around 173,400-174,000m³, putting them in the top echelon of the carrier merit order.
Flex LNG has signed the charter agreements with US operator Cheniere, which will receive two carriers from the owner in the third quarter of this year and another in the third quarter of 2022, with an option to take a fourth in the third quarter of 2022. Cheniere will also take Flex LNG's sole remaining undelivered newbuild — the 174,000m³ Flex Vigilant — when it is delivered by South Korea's Hyundai Samho Heavy Industries in May. The four firm charters are for 3-3.5 years, with charterer's option to extend each by up to two years.
The shipowner has two carriers under long-term charters that are set to expire in the third quarter of 2021 — both with Spain's Naturgy — though it is unclear whether these carriers will be used for the new charters starting in that same period with Cheniere. Flex LNG also has six carriers operating on the spot market, which could potentially be used to fulfil these obligations instead.
Cheniere has been picking up under long-term charter a significant portion of the recent newbuild additions to the global LNG fleet. Since April 2020, the firm has received under term charter at least six new carriers, and is slated to receive at least a further four by August this year, on top of its Flex LNG newbuild.
The charterer has in recent years had to rely heavily on spot additions to its fleet, as the volume of LNG marketed by itself has grown substantially with the buildout of liquefaction capacity at its 25mn t/yr Sabine Pass and 15mn t/yr Corpus Christi liquefaction projects on the US Gulf coast. Tonnage demand from firms marketing US cargoes on a des basis can vary greatly according to the inter-basin des price differential and prevailing spot charter rates, with delivery to northeast Asia via Panama requiring around twice as many days of sailing as delivery to Europe.
Source: Argus
Singapore receives first carbon-neutral LNG cargo

Singapore importer Pavilion Energy has imported the country's first carbon-neutral LNG cargo, joining other Asian buyers that have purchased cargoes whose carbon emissions have been offset by the purchase of carbon credits.

Pavilion has received the cargo but declined to reveal the delivery date and the size and seller of the cargo. The firm said that carbon emissions associated with the LNG cargo and that are generated through extraction, production, transportation, and regasification will be offset by retiring a corresponding amount of high-quality carbon credits sourced from its portfolio of carbon offset projects. The carbon dioxide emissions for an LNG cargo from the gas wellhead to the customer's storage tank are approximately 60,000t, based on a 70,000t cargo.
The carbon credits used to offset the cargo's emissions came from the Evio Kuinaji Ese'Eja Cuna and Liangdu Afforestation projects in Peru and China respectively. The projects are certified under the Verified Carbon Standard and Climate, Community and Biodiversity Standard.
Pavilion's carbon-neutral LNG purchase follows Japanese utility Toho Gas' receipt on 8 April of a 64,000t carbon-neutral LNG cargo that it bought from Mitsubishi unit Diamond Gas International. Other Asian buyers that also bought carbon-neutral LNG cargoes include Japanese utilities Tokyo Gas and Hokkaido Gas, China's state-controlled CNOOC, Taiwan's state-owned CPC and South Korean utility GS Energy.
Commitments by various countries including Japan, South Korea and China to attain carbon neutrality by 2050-60, together with increasing company shareholders' focus on environmental, social and governance issues have likely spurred the these carbon-neutral LNG purchases.
Pavilion has also signed term deals with Chevron and Qatar's state-owned QP as part of its decarbonisation and offset strategies. Each cargo delivered under the respective agreements will be accompanied by a statement of their carbon emissions, measured from wellhead to discharge port. Pavilion's deal with Chevron is for 500,000 t/yr over six years. Its deal with QP is for 1.8mn t/yr over 10 years. Both start from 2023.
Pavilion is also planning to work with its partners, including Chevron and QP, to co-develop and implement a methodology for quantifying and reporting carbon emissions.
Source: Argus
Sinochem, ChemChina merger finally wins approval

Chinese state-owned firms Sinochem and ChemChina have finally received merger approval from the state-owned assets supervision and administration commission (SASAC), kicking off a long-awaited consolidation of the two companies with a combined asset value of $245bn.

The merged company's leading business will be chemicals, covering biosciences, materials science, basic chemicals, environmental science, rubber and tires, machinery equipment, urban operations and industrial finance, Sinochem and ChemChina said in a joint statement.
A new, unnamed entity wholly owned by Sasac will be created, with the Sinochem and ChemChina groups as two separate subsidies.
Energy was not even mentioned in the announcement, leaving it unclear whether the sector will retain a core position in the merged company's strategic blueprint. Sinochem has built up a broad presence in the domestic storage and retail sectors and global crude trading, while the two companies operate combined refining capacity of 670,000 b/d in China.
Ning Gaoning, who was appointed chairman of both Sinochem and ChemChina in 2018 as part of merger plans, has been working to change the core business approach of both companies to focus on higher value-added chemicals and materials. This followed several overseas chemical acquisitions by ChemChina in recent years, including the $43bn purchase of Swiss agrochemicals firm Syngenta.
ChemChina's 2017 acquisition of Syngenta led to an increase in its debt burden, complicating the planned tie-up with Sinochem but providing an incentive to lower overall debts through the merger.
Total assets at Sinochem and ChemChina were 710.5bn yuan ($109.9bn) and Yn874.1bn ($135.2bn) respectively at the end of September last year, according to the most recent company figures from the Shanghai Clearing House. ChemChina's debt-to-asset ratio was 79.6pc, higher than Sinochem's 70.7pc. ChemChina's long-term borrowing and bonds rose to Yn325.5bn as of September from Yn80.4bn at the end of 2015, before the Syngenta acquisition.
Sinochem and ChemChina started work on merging their agricultural and chemical assets in 2019 but have made little progress combining oil assets, where there appear to be fewer synergies in operations or location. ChemChina and Sinochem have consolidated their remaining agriculture-related business units under the Syngenta group umbrella.
Sinochem Energy, the trading and refining arm of Sinochem, said in February it is making another attempt to list on the mainland Chinese A share market to raise funds for an expansion of refining and storage operations, around 2½ years after it started planning for a previous initial public offering in Hong Kong. The listed assets cover the company's crude and oil product trading, refinery, product sales and storage assets, while its upstream operations are excluded and will remain under its parent company Sinochem group.
Source: Argus
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