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Uganda oil project faces final hurdle

TotalEnergies, formerly known as Total, plans to take a final investment decision (FID) on Uganda's 230,000 b/d Lake Albert oil project this month, despite coming under pressure to justify another giant greenfield oil development in its energy transition strategy and in the face of environmental opposition and growing insecurity in the neighbouring Democratic Republic of Congo (DRC).

At least 55 people were killed in attacks on 31 May that targeted camps for internally displaced people near the DRC villages of Boga, in Ituri province, and Tchabi, in North Kivu province, the UN says. The villages are located around 150km from Lake Albert, where TotalEnergies is developing its 190,000 b/d Tilenga oil field. The attacks are blamed on the Allied Democratic Forces, an Islamist militant group fighting to overthrow Ugandan president Yoweri Museveni. More than 1,200 civilians have been killed in the insurgency and over 2mn people have been displaced since 2017, according to the UN.
DRC president Felix Tshisekedi declared a month-long state of emergency in the country's eastern region in May. The governments of DRC and Uganda have agreed to fight the insurgents jointly. Kampala has deployed over 2,000 troops inside the DRC to further strengthen security, and plans to raise this to 2,500. This is partly to ensure that the $20bn Lake Albert development does not suffer the same fate as TotalEnergies' 13.1mn t/yr LNG project in Mozambique, where Islamist attacks prompted the company to declare force majeure on the $30bn scheme in April.
The DRC government last month suspended the civilian administrations of North Kivu and Ituri provinces following the escalation in insurgent attacks, and enforced martial law. Its intervention has given TotalEnergies more confidence to go ahead with the Tilenga and 40,000 b/d Kingfisher projects. With no threat seen to its workers, FIDs for the upstream projects and associated infrastructure are still on track to be taken before the end of June, the firm says.
TotalEnergies and China's state-owned CNOOC are joint-venture partners in the project, which will include a 1,445km crude export pipeline from Hoima in the Lake Albert region to Tanga port on Tanzania's Indian Ocean coast. More than 260 civil society organisations from around the world have called on banks not to fund the East African Crude Oil Pipeline (EACOP) because of ecological and humanitarian risks. The Tilenga development lies within the Murchison Falls National Park, home to endangered species such as chimpanzees.
Don't bank on it
The EACOP consortium plans to source around $2.5bn of the $3.5bn cost of building the pipeline from banks. Some banks have indicated that they will not finance the project, but the African Development Bank is among those willing to do so. The IMF has also agreed to lend the country $900mn, of which $480mn is intended for Uganda's equity stake in the pipeline.
TotalEnergies chief executive Patrick Pouyanne last month tried to appease shareholders' concerns over the project's potential environmental harm by saying that the firm will do everything possible to ensure that its impact is minimised. And he defended the role of Ugandan crude within the company's energy portfolio, citing projected production costs of around $11/bl and CO2 emissions of 13 kg/bl, well below TotalEnergies' current averages of $20/bl and 20 kg/bl, respectively.
TotalEnergies holds a 56.67pc stake in the upstream portion of the Lake Albert project, CNOOC 28.33pc and Ugandan state-owned UNOC 15pc. Production is expected to start up in 2025, with 216,000 b/d carried through the EACOP for export and the rest to be supplied to the planned 60,000 b/d Albertine Graben refinery, to be launched in 2024 at Hoima.
Source: Argus
- June 07, 2021
Gladstone LNG export volumes fall to an eight month low of 1.88 million mt

Exports of LNG from Australia's Port of Gladstone eased to an eight-month low in May after settling at the highest level in April over the January-April period, data collected from the Gladstone Ports Corporation showed June 7.

The May figure was 1.88 million mt, which remained up year on year by 9%, but was down 6% month on month at the lowest monthly figure seen since 1.84 million mt in September of last year.
For January-May, LNG exports from Gladstone of amounted to 9.74 million mt, which is an annualized rate of 23.56 million. If eventuated, that would be the most LNG exported from Gladstone in a single year -- beating the previous record of 22.37 million mt set in 2020, the data showed.
Gladstone's LNG export terminals are the 9 million mt/year nameplate capacity Origin-ConocoPhillips-Sinopec Australia Pacific LNG, the 7.8 million mt/year nameplate Santos-led Gladstone LNG, and Shell's 8.5 million mt/year Queensland Curtis LNG.
This year will be the fifth full year of all six of Gladstone's LNG trains being online.
Exports from Gladstone to China fell for the second consecutive month to a four-month low of 1.32 million mt -- which was up 12% year on year and down 4% month on month, according to the data.
Volumes to Japan fell for the fifth consecutive month to an 11-month low of 64,286 mt, with that having edged 2% lower year on year and 1% month on month, it said.
LNG exports to Malaysia were also down, falling for the second month to 124,927 mt. That was down 49% year on year and 33% month on month.
South Korea was sent 231,223 mt, rising 2% year on year while dropping 22% month on month. And volumes to Singapore were at a seven-month high of 136,091 mt -- up from zero the same time last year and 88% stronger than April, the GPC figures showed.
Source: SP Global
India eyes 20pc ethanol blending by 2025

Mumbai has officially advanced its target for blending 20pc ethanol in gasoline (E20) nationwide to 2025 and published a roadmap for achieving the new mandate.

Prime minister Narendra Modi announced the earlier target during a biofuels-themed webcast to mark World Environment Day on 5 June. The target replaces a previous 2030 deadline for achieving E20, first set in the country's national biofuels policy in 2018.
Modi also released a "Roadmap for ethanol blending in India 2020-2025" at the event, which recommends E10 be made available nationwide by April 2022 until 2025, alongside a phased E20 rollout across the country from April 2023 starting in states with surplus ethanol production. Oil firms have earmarked 11 states including Uttar Pradesh, Haryana, Delhi, Goa, Karnataka, Maharashtra and Punjab where E20 will be launched in selected cities by April 2023.
Ethanol supply should reach 10.16bn litres for nationwide E20 in the December 2025-November 2026 supply year according to the report, though the actual volume needed may be lower depending on the penetration of electric vehicles by that year. The roadmap sees the central government's existing loan assistance scheme driving adequate growth in output capacity over the next five years, and expects a 78pc rise in molasses-based and 187pc hike in grain-based distillery capacity by 2025, to 7.6bn l and 7.4bn l respectively. "Special efforts" will be needed to attract investment in grain-based distilleries in India's northeast which lacks a sugarcane industry.
The report suggests a five-year ex-mill price floor for ethanol replace the current annual pricing cycle to give assurance to investors, with favourable ex-mill prices for non-sugarcane feedstocks to promote water savings. Cumbersome environmental clearance processes should be streamlined for new and expanding distilleries, with regulatory hurdles removed for smaller projects and those with zero liquid discharge.
To smooth supply and demand imbalances between regions, 15 of 29 state governments yet to do so should remove regulations blocking inter-state transport of the fuel, and oil companies should increase existing tankage facilities by half to reach 446.4mn l nationwide.
Flex fuel and vehicles compatible with higher blends should be launched and incentivised, with a rollout of E10 engine tuned vehicles from April 2023 and E20 from 2025 suggested in the roadmap. Tax breaks should ensure ethanol remains price competitive against gasoline at the pump even if petroleum costs drop from recent highs.
The roadmap has garnered mixed responses from producers: some have lauded the initiative as providing clear direction to encourage investment, while others point to the many obstacles on the road to nationwide E20.
Capacity addition forecasts may be overblown, as despite government loan aid and a tripartite mechanism with banks, most proposed projects are still refused loans due to poor financials. Only around 40pc of 606 molasses-based and 418 grain-based distilleries approved in-principle since 2018 are likely to materialise according to a leading consultant.
Favourable monsoons for the past few years have boosted sugar, grain and rice output to surplus levels, but a downturn in weather conditions may limit feedstock availability in future years. And some producers have concerns a change in government at the next general election pegged for 2024 may reverse recent pro-ethanol policies, leaving any new distillery investments stranded.
The current leadership frames biofuel blending as crucial to reducing fuel import dependence and drawing down its sugar glut while satisfying farmers. Achieving E20 could shave $4bn/yr off India's petroleum import bill, according to the roadmap. India's net petroleum receipts totalled 185mn t and cost $55bn during April 2020-March 2021, according to government data.
Source: Argus
India state-controlled refiners raise runs

India's state-controlled refiners have increased run rates in recent days, as parts of the country ease lockdowns in line with a fall in Covid-19 cases.

India's state-controlled refiner IOC is operating at about 85pc of capacity, a source familiar with plant operations said. IOC operated its refineries at an average capacity of 84pc during 1-17 May. Run rates since then are unclear, although one market participant estimated that some of the company's refineries' runs had increased by around 10pc to reach current average levels of 85pc. This could not be confirmed with IOC.
Bharat Petroleum (BPCL) has been operating at 75pc of capacity since the end of May, which the market participant also estimated to be up by around 5pc. BPCL said early last month that it would cut runs by 10pc in May after postponing a planned turnaround in April at its 240,000 b/d Mumbai refinery.
MRPL is operating its 300,000 b/d Mangalore refinery at around 75pc of capacity, an official close to the company said. The company cut rates to around 65-75pc last month, after shutting its smallest 60,000 b/d crude distillation unit (CDU) in April. That unit remains off line but the company has boosted rates at its other CDUs to full capacity, an analyst said.
The increase in runs comes despite high domestic retail fuel prices and continuing lockdowns. India's surging domestic transport fuel prices, underpinned by fuel tax rises implemented last year, are further weighing on the already waning demand. Gasoline prices in retail outlets were at around 95 rupees/litre ($1.30/l) in Delhi today, while it was around Rs101/l in Mumbai and the highest on record.
Demand is encouraging in June and July, an official at an state-controlled refiner said. Indian fuel demand is likely to recover from July as lower Covid-19 cases and a vaccination programme support consumption, the chairman of state-controlled refiner Hindustan Petroleum MK Surana told Argus last week. Some of the country's Covid-19 curbs have been eased as infections ebb, with new cases falling to slightly over 100,000 from a high of over 400,000 last month, according to government data.
India's fuel demand fell in May compared with the previous month, with demand for diesel, gasoline and jet fuel down by 20pc, 19pc and 28pc respectively, according to data compiled by state-controlled refiners that account for around 90pc of the country's fuel sales.
Source: Argus
OPEC+ lifts May output by 430,000 b/d as Saudi Arabia eases its voluntary cut

Crude oil production from OPEC and its allies jumped 430,000 b/d in May, the latest S&P Global Platts survey found, led by Saudi Arabia, which accounted for about 84% of the total monthly rise.

The OPEC+ alliance, which held almost 7 million b/d of production offline in April to speed the market’s rebalancing, began significantly relaxing its output quotas last month, in anticipation of rising summer oil demand and a healthier global economy.
OPEC’s 13 members pumped 25.71 million b/d in May, its highest since April 2020, when Saudi Arabia launched a brief price war after a breakdown in talks with Russia over how to manage the oil market through the pandemic.
Its nine non-OPEC partners, led by Russia, produced 13.21 million b/d, unchanged from the previous month.
Despite the production gains, the looser quotas meant OPEC+ compliance stayed mostly steady at 111.45% compared to 111.16% in April, the survey found.
Saudi Arabia saw the biggest rise month on month, adding 360,000 b/d, which included unwinding a quarter of its extra voluntary 1 million b/d production cut, as it had previously signaled, along with a higher quota.
The kingdom produced 8.50 million b/d in May, some 730,000 b/d below its official quota of 9.23 million b/d.
Take away the Saudi voluntary cut, and OPEC+ quota compliance would fall to 99.51%, according to Platts calculations.
Saudi crude exports were up sharply in the month, in response to strong demand from its key customers, while its crude inventories and refining runs also observed a sturdy rise, according to the survey.
Saudi Arabia has promised to further ratchet back its extra cut by 350,000 b/d in June, and 400,000 b/d in July, as it prepares to unleash more barrels on a market that is starting to show some robust economic signs.
Source: Hellenic Shipping
Exporters, buyers brace for normal flows of Iranian LPG, condensate

Iranian exporters aim to increase LPG exports to full capacity, if the Biden administration lifts sanctions that limited shipments from the country's petrochemical plants and gas refineries, adding to healthy Middle East supply, which could drive up freight, industry sources familiar with the sector said.

Assuming the US completely removes sanctions in second-half 2021, Iran can export 3.73 million mt during the period and at least 33 vessels will be needed for transportation, six more than currently, they said.
Removal of sanctions should the US resume the Joint Comprehensive Plan of Action, or JCPOA, after former US President Donald Trump withdrew in May 2018, could also allow Iran to export condensates, an ultra-light crude that yields better product margins, and put pressure on Asia's naphtha market.
South Pars condensate is expected to be competitively priced, allowing petrochemical makers to obtain cheaper feedstock naphtha from cracking this condensate.
"The market is worried the lifting of Iran sanctions would weigh on the naphtha market because condensate will be cheaper, so the Korean splitters will buy more condensate again instead of heavy full range naphtha," a petrochemical producer said.
Iran had previously exported condensates to South Korean end-users, where splitters switch between using condensate and various naphtha grades, depending on economics. If Iranian supply were to return to the market, it would impact other types of naphtha, sources said.
"Once Iran and the US come to an agreement, they [Iran] can export oil products again, and it will definitely affect the naphtha market," a Singapore-based source said.
"Last time, Iran used to export a lot of condensates for splitters like Hyundai, Hanwha, and others in Korea, and if this were to resume, then demand for heavy paraffinic naphtha will definitely go down," the source added.
Restored Iranian LPG exports would add to abundant Middle East supply this year, with major producers regularly accepting lifters' monthly term nominations without cuts or delays, while Kuwait and Qatar consistently sell spot cargoes. Whenever the US arbitrage window opens, ample supply in Asia would render LPG cheaper than naphtha, making propane and butane a favored cracker feedstock.
Source: SP Global
man LNG signs deal with Shell to ship Middle East first carbon-neutral LNG cargo

Oman LNG has signed an agreement with Shell to deliver the sultanate’s first carbon-neutral LNG cargo, the company announced in a series of Tweets June 8.

The shipment will be made from Oman LNG’s export facility in Qalhat, Sur.
“The cargo is the first carbon-neutral LNG from the Middle East using nature-based carbon credits to offset full lifecycle CO2 emissions generated across the LNG value chain,” the company said.
Oman LNG did not provide details on which company is responsible for offsetting the carbon by planting trees, or where this project would be located.
“When CO2 emissions are hard to abate, they can be compensated through offset from projects that are independently verified to capture or reduce CO2 emissions and create carbon credits, which can be retired to demonstrate an amount of CO2 emissions have been compensated for,” Oman LNG said.
In April, Shell announced it would spend $300 million over the next three years to plant 5 million trees in the Netherlands and Spain, as well as supporting forest regeneration in Australia. It has argued this plan would reduce its net carbon footprint by 2% to 3% by offsetting its emissions.
However, questions remain about the effectiveness of such plans. For instance, it can take decades for trees to be absorb sufficient carbon to have a material impact. Additionally, if the trees were to die, the carbon may be released back into the ecosystem.
“The concept of carbon offsetting is problematic as it does not tackle the core issue of carbon emission and is most often used as a form of greenwashing,” said Dania Cherry, a spokesperson for Greenpeace Mena, in a recent statement to S&P Global Platts. “Planting trees and waiting for more than a decade till they accumulate enough biomass to become net carbon emitters and hoping they remain despite the increased prevalence of drought, forest fires and disease due to climate change is not a solution.”
Oman LNG has been undergoing debottlenecking activities in the past two years to raise the capacity of its current facilities. Omani LNG exports were essentially at full capacity 2018-2020, when they averaged at about 12 Bcm/year, according to Platts Analytics. However, the debottlenecking will allow Omani LNG exports to expand by about 2 Bcm/year. Platts Analytics expects Omani LNG exports at around 14 Bcm/year over the coming five years.
Source: Hellenic Shipping
Iran prepared to ramp up oil output quickly if U.S. sanctions eased

Iran is planning a speedy increase in its oil output, a senior oil ministry official said on Wednesday, as talks continue between Tehran and six major powers to lift U.S. sanctions that have seen it pumping far below capacity since 2018. Iran and the six powers have been in talks since April to revive a 2015 nuclear deal that former U.S. President Donald Trump exited three years ago, reimposing sanctions that have hit Iran’s economy hard by sharply cutting its vital oil exports.

"If sanctions are lifted, most of the country's crude production will be restored within a month," Farokh Alikhani, production manager of the National Iranian Oil Company (NIOC), told the oil ministry's SHANA website.
"Careful planning has been done to restore oil output to pre-sanctions levels in intervals of one week, one month and three months."
However, Washington said on Tuesday that even if the nuclear accord were revived, hundreds of U.S. sanctions on Tehran would remain in place. That could mean additional Iranian oil supply would not be re-introduced into the crude market soon.
Iran emerged from years of economic isolation in 2016 when world powers lifted crippling international sanctions against the Islamic Republic in return for Tehran complying with the 2015 deal to curb its nuclear ambitions.
Tehran's oil exports increased to 2 million barrels per day (bpd) in 2016 and reached a peak of 2.8 million bpd before sanctions were re-imposed in 2018 by Trump.
Iran does not release figures for current exports, but some energy monitoring firms estimated them at around 700,000 bpd in April and 600,000 in May.
Alikhani said Iran hoped to further raise its output "to more than 4 million bpd in the next step".
"The average daily oil production of Iran after the implementation of the 2015 deal was 3.38 million bpd and we plan to return to that level if the sanctions are lifted," said Alikhani.
Source: Zawya
Fujairah data: Oil product stocks retreat across the board, light distillates near record low

Oil product inventories at Fujairah on the UAE’s east coast slipped to a two-week low as light distillates shrank to the smallest since the record low in October 2020 on growing demand for naphtha in Asia.

The total inventory was 22.335 million barrels as of June 7, down 5.7% from a week earlier and the lowest since May 24, according to Fujairah Oil Industry Zone data provided exclusively on June 9 to S&P Global Platts. All categories showed declines, with light distillates such as gasoline and naphtha down 4.7% to 4.978 million barrels, the lowest since Oct. 26, 2020, when they hit a record low of 4.198 million barrels. Middle distillates and heavy distillates also dropped to two-week lows.
Naphtha exports from Fujairah were 69,000 b/d in May, the biggest monthly total since February 2019, according to commodity data company Kpler. Shipments to Japan averaged a record 29,500 b/d for May and Sri Lanka was set to get its first naphtha cargo from Fujairah, according to Kpler. Taiwan, South Korea and Malaysia also took in the feedstock last month. Naphtha is used as a petrochemicals feedstock and in gasoline blending.
Fujairah’s naphtha exports rose sharply by 34.5% from April mainly due to a 59.46% month on month rise in shipments to Japan as domestic supply in the country was lower from refinery maintenance amid a time of high steam cracker run rates due to positive margins. Idemitsu Kosan, Japan’s second-largest refiner, shut its 190,000 b/d crude distillation unit in Chiba refinery over April 28 to June 6.
Export volumes may remain firm as Japan’s largest refiner, ENEOS, plans to shut its sole CDU at its 145,000 b/d Sendai refinery for scheduled maintenance over early June to mid-July. Furthermore, overall demand for naphtha as a petrochemical feedstock was firm, as not only are olefin margins positive, but also new steam cracker units are slated to come online as of mid-June, market sources said.
The key CFR Northeast Asia ethylene spread to benchmark C+F Japan naphtha cargo was last assessed at $330.125/mt on June 8’s Asian close, and has remained over the typical breakeven for integrated producers of $250/mt since May 12, 2021, Platts data showed.
In South Korea, the new LG Chem cracker is slated to start up on June 14-15 and will have an ethylene production capacity of 800,000 mt/year; GS Caltex’s new mixed feed cracker is slated to start June 20, with a capacity of 700,000 mt/year of ethylene, Platts earlier reported.
Both LG Chem’s and GS Caltex’s new crackers will take time to ramp up to 100% operating rates. Also, it is unclear if both crackers would use naphtha as its only feedstock: LG Chem’s new cracker can switch up to 40% of its feedstock requirements to LPG, while GS Caltex’s can switch up to 30% of its feedstock to LPG.
Inventories of middle distillates such as jet fuel and diesel dropped to 3.484 million barrels as of June 7, down 8.8% from a week earlier, while heavy distillates such as fuels used in power generation and for marine bunkers retreating 5.3% to 13.873 million barrels.
Source: Hellenic Shipping
Iran raises July Iranian Light crude oil price to Asia

Iran has set the July official selling price (OSP) of its Iranian Light crude oil grade for Asian buyers at $1.60 cents above the Oman/Dubai average, up 10 cents from the previous month, a source with knowledge of the matter said on Thursday.

The producer set the July Iranian Heavy crude OSP at 50 cents above the Oman/Dubai average, unchanged from the previous month, the source said.
Source: Zawya
India BPCL manages spot crude purchases as runs fall

Indian state-controlled refiner Bharat Petroleum (BPCL) plans to manage its spot crude purchases to balance a decline in throughput while keeping its term buying steady, the company said today.

BPCL has cut its throughputs to 86pc of capacity after a 30pc slump in fuel demand this month because of a resurgent Covid-19 epidemic, finance director N. Vijayagopal said.
The company, which operates 706,000 b/d of refinery capacity including its joint-venture 156,000 b/d Bina plant, does not expect to cut term purchases or store crude on floating tankers, as happened last year when the pandemic first struck India, Vijayagopal said. It will instead adjust spot purchases, including cargoes from the US and Africa, to balance imports with runs.
BPCL will displace US with Iranian crudes if sanctions are relaxed this year. The refiner used to buy around 40,000 b/d from Iran before the latest round of US-led sanctions was imposed.
BPCL bought around 24,000 b/d of US crude in the April 2020 to March 2021 fiscal year. It declined to comment on its more recent purchases of US crude.
"We will continue to depend on Middle East crude including Saudi, Iraq, UAE'' supplies, Vijayagopal said.
BPCL added US Eagle Ford, Brazil's Tupi and Iara, Australia's Ichthys, Norway's Ekofisk and Canada's Light Sour Blend (LSB) to its mix in the 2020-21 fiscal year. It is now less dependent on Middle East crude after changing its refinery configurations.
BPCL's term purchases account for less than 60pc of its total imports, down from around 75pc previously, with the rest sourced from the spot market. The company buys around 760,000 b/d of crude, with 60,000 b/d coming from the Mumbai High fields offshore west coast India and the remainder imported.
India's refining runs have been hit by the recent surge in Covid-19 cases, which has slashed fuel demand and led to local lockdowns being imposed. But runs may stabilise next month if states relax the curbs. India's daily coronavirus case count has dipped by nearly half to just over 200,000 from a peak of more than 410,000 earlier this month.
BPCL's capital expenditure (capex) was around 110bn rupees ($1.5bn) in 2020-21. Capex will rise to Rs120bn in the current fiscal year but the company has postponed any major new projects because of its privatisation plan. The pandemic has delayed the sell-off by over a year and Delhi now expects to complete the process by December.
Source: Argus