A logo of Brazil’s state-run Petrobras oil company is seen at their headquarters in Rio de Janeiro, Brazil October 16, 2019. REUTERS/Sergio Moraes/File Photo Acquire Licensing Rights
RIO DE JANEIRO, Sept 28 (Reuters) – The head of Brazil’s state oil firm Petrobras (PETR4.SA) said on Thursday it will sign a memorandum of understanding with mining giant Vale (VALE3.SA) to study potential joint ventures in renewable energy, even as looks to new suppliers for diesel.
“Vale is a consumer (of energy) and probably very interested in hydrogen production, it has some activities in energy transition that are interesting,” Petrobras CEO Jean Paul Prates told reporters, saying the companies would look for synergies.
The partnership would come at a time when Petrobras is pushing to move into renewable energy. Earlier this month, the state-run firm unveiled plans to develop offshore wind farms.
Regarding diesel, Prates said Petrobras could if necessary and strategic import the fuel from abroad as bans on Russian imports – the main source of imported diesel in Brazil – could force the country to look for suppliers elsewhere.
Russia surpassed the United States as Brazil’s top supplier this year.
“We’re going to import to meet our contracts and possibly one or two more quotas that are necessary and that we see as an opportunity to enter a new market or a new customer that is good for us,” Prates said.
Meanwhile, spiking oil prices have widened the gap between Petrobras’ refinery prices and those charged abroad, which analysts say is discouraging third-party imports. Petrobras last adjusted its gasoline and diesel prices in mid-August.
“The models, for the time being, indicate it’s possible to maintain the same level with absolutely no risk to the company’s profitability,” said Prates.
Petrobras’ refinery utilization factor is currently at a rate of 94%, he added.
Reporting by Marta Nogueira; Editing by Steven Grattan and Sarah Morland
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LITTLETON, Colorado, Sept 19 (Reuters) – The deepening debt crisis in China’s construction sector – a key engine of economic growth, investment and employment – may trigger an unexpected climate benefit in the form of reduced emissions from the cement industry.
Cement output and construction are closely correlated, and as China is by far the world’s largest construction market it is also the top cement producer, churning out roughly 2 billion tonnes a year, or over half the world’s total, data from the World Cement Association shows.
The heavy use of coal-fired kilns during manufacturing makes the production of cement a dirty business. China’s cement sector discharged 853 million tonnes of carbon dioxide in 2021, according to the Global Carbon Atlas, nearly six times more than the next largest cement producer, India.
The cement sector accounts for roughly 12% of China’s total carbon emissions, according to Fidelity International, and along with steel is one of the largest greenhouse gas emitters.
But with the property sector grinding to a halt due to spiralling debt worries among major developers, the output and use of cement are likely to contract over the next few months, with commensurate implications for emissions.
HOUSING SLUMP
The property markets account for roughly a quarter of China’s economy, and for years Beijing has used the sector’s substantial heft to influence the direction of the rest of the economy by spurring lending to would-be home buyers and fostering large scale construction projects.
But the big property developers racked up record debt loads in recent years that have forced borrowing levels to slow, stoked concerns among investors, and slowed spending across the economy.
China Evergrande Group, once the second largest developer, defaulted on its debt in late 2021, while top developer Country Garden has drained cash reserves to meet a series of debt payment deadlines in recent months.
Fears of contagion throughout the property industry has spurred households to rein in consumer spending, which has in turn led to deteriorating retail sales and further economic headwinds.
Beijing has stepped in with a slew of measures designed to right the ship, including easing borrowing rules for banks and lowering loan standards for potential home buyers.
But property prices in key markets remain under pressure, which has served to stifle interest among buyers and add to the pressure on investors and owners.
CEMENT CUTS
With construction activity across China slowing, and several major building sites stopped completely while tussles over debt payments among developers continue, cement output is likely to shrink to multi-year lows by the end of 2023.
During the March to August period, the latest data available, total cement output was 11.36 million short tons, down 2 percent from the same period in 2022 and the lowest for that period in at least 10 years, China National Bureau of Statistics data shows.
In addition to curtailing output in response to the bleak domestic demand outlook in the property sector, cement plants may be forced to curb output rates over the winter months as part of annual efforts to cap emissions from industrial zones during the peak season for coal heating.
Some cement producers will likely look to boost exports in an effort to offset lower domestic sales, and in July China’s total cement exports hit their highest since late 2019.
But Chinese firms will face stiff competition from lower-cost counterparts in Vietnam, which are by far the top overall cement exporters and already lifted overall cement shipments by close to 3% in the first half of 2023, data from the Vietnam National Cement Association (VNCA) shows.
Some Chinese firms may be prepared to sell exports at a loss for a spell while they await greater clarity over the domestic demand outlook.
But given the weak state of global construction activity amid high interest rates in most countries, as well as the high level of cement exports from other key producers such as India, Turkey, United Arab Emirates and Indonesia, high-cost Chinese firms may be forced to quickly contract output to match the subdued construction sector.
And if that’s the case, the sector’s emissions will come down too, yielding a rare climate benefit to the ongoing property market disruption.
The opinions expressed here are those of the author, a columnist for Reuters.
Reporting By Gavin Maguire; Editing by Miral Fahmy
Our Standards: The Thomson Reuters Trust Principles.
Opinions expressed are those of the author. They do not reflect the views of Reuters News, which, under the Trust Principles, is committed to integrity, independence, and freedom from bias.
People walk along the beach on the Suffolk coast as the Sizewell B nuclear power station can be seen on the horizon, near Southwold, Britain, January 31, 2019. REUTERS/Russell Boyce Acquire Licensing Rights
LONDON, Sept 18 (Reuters) – Britain on Monday opened the search for private investment in the Sizewell C nuclear project, inviting potential investors to register their interest.
The building of the plant by French energy giant EDF in southeast England, capable of producing around 3.2 gigawatts of electricity or enough to power around 6 million homes, was approved in July 2022.
“The government, the Sizewell C Company and EDF, the project’s lead developer, are looking for companies with substantial experience in the delivery of major infrastructure projects,” a statement from the Department for Energy Security and Net Zero said.
The British government announced last year that it would support Sizewell C with around 700 million pounds ($895 million) while taking a 50% stake during its development phase.
“The launch of the formal equity raise opens another exciting phase for the project, following a positive response from investors during market testing,” said Sizewell C Company Joint Managing Director, Julia Pyke.
Reporting by Kylie MacLellan, writing by William James
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BEIJING, July 13 (Reuters) – China’s crude oil imports in June jumped 45.3% on the year to the second-highest monthly figure on record, customs data showed on Thursday, with refiners building up inventories despite tepid domestic demand.
Crude imports in June totalled 52.06 million metric tons, or 12.67 million barrels per day (bpd), the data from the General Administration of Customs showed.
It was a substantial increase on the 8.72 million bpd imported in June last year, when the economy was battered by widespread COVID-19 lockdowns.
Crude imports also held their upward momentum on a month-on- month basis, up 4.58% from May’s 12.11 million bpd.
Total imports for the first half were 282.07 million metric tons, up 11.7% from 252.52 million in the corresponding period last year.
Teapot refiners in the eastern province of Shandong stepped up runs as authorities lifted curbs on the import of diluted bitumen in late June, helping to ease inventory pressure at its ports.
More broadly, however, inventories continue to rise against an uncertain macroeconomic backdrop. Commodities consultancy Vortexa estimated onshore crude inventories at 980 million barrels at the end of June, just 20 million barrels below an all-time record in August 2020.
While kerosene demand is up strongly on the year, boosted by a resumption in flights after the removal of curbs on travel, weakness in the manufacturing and property sectors has hurt demand for diesel, despite government stimulus measures.
“The long-haul spot barrels were booked when (arbitrage) windows were open, despite soft demand when the cargos arrived in June,” said Emma Li, a China oil markets analyst at Vortexa in Singapore.
China imported 10.39 million metric tons of natural gas in June, up 19.2% from 8.72 million a year ago when importers cut spot purchases amid high global liquefied natural gas (LNG) prices. Total gas imports for the first half stood at 56.63 million metric tons, a 5.8% increase on last year.
Refined fuel exports rose 40.6% to 4.51 million metric tons from 3.21 million in June last year, but down from the previous month’s 4.89 million metric tons.
Reporting by Andrew Hayley; Editing by Himani Sarkar, Shri Navaratnam and Jamie Freed
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Feb 13 (Reuters) – Freeport LNG sought permission from federal regulators on Monday to restart commercial operations at its long-idled liquefied natural gas (LNG) export plant in Texas, a move that could soon provide the world with another much needed source of the super-cooled fuel.
The amount of gas flowing from U.S. pipelines to Freeport jumped on Monday to its highest since the facility was shut by a fire in June 2022 after the company restarted one of the plant’s three liquefaction trains, which turn gas into LNG for export.
But energy regulators and analysts have said they do not expect Freeport, the second-biggest U.S. LNG export plant, to return to full commercial operations for months.
In a filing with the U.S. Federal Energy Regulatory Commission (FERC) on Monday, Freeport asked for permission to put what it called Phase 1 of its restart plan into commercial operation.
Phase 1 includes the full restart of the plant’s three liquefaction trains, two storage tanks and one LNG loading dock.
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Freeport said it would appreciate an answer from FERC on Monday “if at all possible,” as it was ready to restart liquefaction Train 2 now and expects to be ready to restart Train 1 in the next few weeks.
Gas flows to the plant were on track to reach 0.5 billion cubic feet per day (bcfd) on Monday, according to data provider Refinitiv, up from an average of 43 million cubic feet per day since federal regulators approved Freeport’s plan to start cooling parts of the plant on Jan. 26.
That is still only a fraction of the 2.1 bcfd of gas Freeport can turn into LNG when operating at full power. One billion cubic feet of gas is enough to supply about 5 million U.S. homes for a day.
Despite the increase in feedgas flows to Freeport, U.S. gas futures fell about 5% on Monday, putting the contract on track to close at a 25-month low.
That is because the gas market was more focused on a decline in domestic demand for the fuel for heating with the weather expected to remain mostly warmer than normal for the rest of February.
FULL OPERATIONS STILL MONTHS AWAY
On Saturday, Texas residents grilled U.S. energy regulators over their supervision of Freeport and other LNG plants.
Bryan Lethcoe, a regional director at the U.S. Pipeline Hazardous Materials Safety Administration (PHMSA), said it would take “a number of months” for Freeport to return to full operation.
That is similar to the “mid-March or later” timeframe many energy analysts have projected for Freeport’s full return.
Officials at Freeport had no comment.
A couple of Freeport’s customers – Japan’s JERA (9501.T), (9502.T) and Osaka Gas (9532.T) – have said they do not expect to get LNG from the plant until after March.
Freeport’s other big buyers include units of BP PLC (BP.L), TotalEnergies (TTEF.PA) and SK E&S.
BP’s Kmarin Diamond was the first vessel to pick up LNG at Freeport since the plant shut.
The tanker, which has already left the facility and is on its way to the Suez Canal in Egypt, picked up LNG to create space in Freeport’s storage tanks for new LNG expected to be produced.
There is already another vessel at the plant – Prism Agility – operated by South Korea’s SK E&S, according to Refinitiv and other ship tracking data.
Reporting by Scott DiSavino; Additional reporting by Deep Vakil in Bengaluru; Editing by Marguerita Choy and Paul Simao
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MANILA, Feb 10 (Reuters) – Citicore Renewable Energy Corp, one of the Philippines’ biggest solar power producers, is planning to go public this year to fund a $4 billion investment in new solar projects over the next five years, its CEO said on Friday.
“For a country such as ours with limited oil and coal but have abundant sun, wind and water, it is imperative we deploy capital investment into renewable energy,” Citicore President and CEO Oliver Tan told reporters.
Citicore will file documents for an initial public offering in the second quarter and complete its listing within the year, Tan said, adding it will be large enough to attract foreign investors for an international tranche.
Fresh capital from the listing will allow Citicore, which has an installed capacity of 241 megawatts via solar panels, to invest $800 million this year to increase output to 1 gigawatt (GW), and around $4 billion to reach 5 GW within five years, Tan said.
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The Philippines, an archipelagic country among the most vulnerable to climate change, aims to increase renewables in its power mix to 35% by 2030, from 21% in 2020, and to 50% by 2040. Coal accounted for nearly 60% in 2020.
Citicore is also pursuing seven offshore wind projects with a total capacity of 3 GW.
Citicore is the parent firm of Citicore Energy REIT Corp (CREIT.PS) and is a sister company of Megawide Construction Corp (MWIDE.PS).
Citicore REIT on Friday listed its maiden ASEAN Green Bond in the Philippines’ fixed income trading platform. It raised 4.5 billion pesos ($82.6 million) from its bond sale to fund acquisition of land for its renewable energy portfolio.
($1 = 54.50 Philippine pesos)
Reporting by Neil Jerome Morales
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Jan 31 (Reuters) – Japanese trading firm Marubeni Corp (8002.T) started commercial operation based on the feed-in tariff program for renewable energy at Akita Port offshore wind farm on Tuesday, it said in a statement.
Japan’s offshore wind power market, part of the country’s goal to be carbon neutral by 2050, is set to grow as the government eyes installing up to 10 gigawatts of offshore wind capacity by 2030, and up to 45 gigawatts by 2040.
Marubeni’s 100 billion yen ($768 million) project of two wind farms with 140 megawatt capacity at Akita Port and Noshiro Port in northern Akita prefecture is Japan’s first large-scale commercial offshore wind power project.
With its Noshiro Port offshore wind farm operating since late December last year, the launch of the Akita Port farm brings the project to the full-scale operation, Marubeni said.
Power from the two wind farms will be sold to Tohoku Electric Power for 20 years under a power purchase agreement based on the feed-in tariff program.
Marubeni’s 12 partners include Obayashi Corp, Tohoku Sustainable & Renewable Energy Co, Cosmo Eco Power Co, Kansai Electric Power Co and Chubu Electric Power Co.
($1 = 130.2900 yen)
Reporting by Katya Golubkova, Editing by Louise Heavens
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LONDON, Dec 22 (Reuters) – China’s imports of primary aluminium jumped to a one-year high of 110,700 tonnes in November in a significant reversal of the recent trend.
The country flipped to net exporter in the first half of 2022, with primary metal shipped as far as Europe and the United States to capitalise on sky-high physical premiums.
The premiums are now much reduced. That for duty-unpaid in Europe collapsed from over $600 per tonne in May to a current $250 over the London Metal Exchange (LME) cash price.
While European smelter output declines under the weight of high energy prices, the region is also bracing for a recessionary hit to demand.
China appears to be taking up some of the slack as its own production momentum stalls just as the country tries to open up from quarantine and lockdown.
TRADE FLOWS FLIP AGAIN
China’s primary aluminium export surge has passed. Outbound shipments totalled 190,000 tonnes in the first eight months of the year, the highest volume of exports since 2010.
Exports have since shrunk to 5,000 tonnes over the September-November period with high-volume shipments to Europe and the United States replaced by a trickle of material to African destinations.
Until last month, imports had been subdued relative to the previous couple of years and largely comprised Russian metal shunned by Western buyers after Russia’s “special military operation” in Ukraine began in February.
Russian imports hit a fresh 2022 high of 56,000 tonnes in November but its share of imports dropped to 51% from 85% in June. The balance was sourced from a range of countries, suggesting more Chinese pull than Russian push.
It’s worth noting that China’s imports of unwrought aluminium alloy have remained consistently strong at around 100,000 tonnes per month since a structural shift higher in 2019.
The step change coincided with a slump in imports of aluminium scrap ahead of a planned ban in 2020. The ban was pulled at the last moment and replaced with tighter purity thresholds.
Scrap imports have since rebounded, up 60% so far this year, but without any impact on alloy flows.
SLOWING MOMENTUM
China’s renewed import appetite for primary aluminium looks at odds with the combination of lockdown-weakened demand and strong domestic production growth.
Headline national output was up by 7.2% year-on-year in November with cumulative production up 3.1% in the first 11 months of 2022, the latest estimates by the International Aluminium Institute (IAI) showed.
However, the year-on-year comparison is accentuated by a low base in the closing months of 2021, when multiple producers were forced to reduce run-rates during a rolling energy crunch.
Expressed in terms of annualised production, China’s collective run-rate has dropped by almost 1.2 million tonnes since August. That’s not as much as the 2.0-million tonne decline in late 2021 but still a significant dissipation of the early-year production surge.
Energy is again the culprit.
Although there are no national blanket power restrictions over the winter heating season this year, provinces have delegated powers to manage their local power balances and the smelter hits have been mounting up.
Sichuan briefly rationed power to industrial users, including aluminium smelters, in August because of a protracted drought in the hydro-rich province.
The following month Yunnan ordered its smelters to reduce operating rates by 10% for the same reason, lifting the mandate to 20% in October.
Last month saw several smelters in Henan province reduce output by 10% on a combination of weak market conditions and pressure from local winter heating restrictions, according to consultancy AZ Global.
The seasonal power pressures have spread to the province of Guizhou this month with local smelters taking cuts of up to 31% of capacity, AZ Global reports.
Guizhou is a relatively small aluminium province with annual production of around one million tonnes but Yunnan is a growing hub of production on the basis of its green energy credentials.
Hongqiao, China’s largest private operator, is undeterred by this year’s power constraints and is moving more of its capacity there.
However, the concentration of smelters in Yunnan and Sichuan leaves China’s domestic supply chain facing a new source of instability in the form of seasonal rainfall levels.
SHIFT TO SURPLUS
The scale of the cumulative production hit in China has been masked by impact of rolling lockdowns and a foundering property sector on domestic demand.
The partial lifting of COVID-19 restrictions, although fraught with the danger of a wave of Omicron infections, is expected to revitalise Chinese growth over 2023.
Any recovery impetus will require an aluminium restock. Visible inventory on the Shanghai Futures Exchange has slumped by 71% since the start of January and at a current 92,373 tonnes is around the lowest levels since 2016.
It is too early to say if last month’s jump in imports is an early sign of domestic recovery in the aluminium sector but it signals a shift in market flows.
The Western deficits earlier this year attracted significant volumes of metal from Asia, including China. The supply-chain tension has accordingly eased and the market focus has shifted to weakening demand and the potential for large amounts of aluminium to head to LME warehouses.
The east-west pendulum is swinging back again and it’s China that looks de-stocked and in need of some top-up metal from the spot market.
How much will depend on how China’s many provincial authorities balance their power systems over the next few winter months.
The opinions expressed here are those of the author, a columnist for Reuters.
Editing by Barbara Lewis
Our Standards: The Thomson Reuters Trust Principles.
Opinions expressed are those of the author. They do not reflect the views of Reuters News, which, under the Trust Principles, is committed to integrity, independence, and freedom from bias.
SAO PAULO, Dec 15 (Reuters) – Brazilian power company Eletrobras (ELET6.SA) and Shell (SHEL.L) have signed a cooperation agreement to exchange information as they mull a potential co-investment in offshore wind power in the South American country, Eletrobras said on Thursday.
The move marks another step for Shell in the sector in Brazil, where it already has several offshore wind projects pending approval from environmental authorities.
It is also a new development in renewable energy for Eletrobras, Latin America’s largest utility, which said it was seeking to diversify its strategy in the sector after being privatized earlier this year.
“Offshore wind energy has proved to be, all over the world, an expanding source for renewable power generation,” Eletrobras said in a securities filing.
The company, which is mostly focused on hydroelectric power plants, noted that offshore wind farms have been recently boosted by energy policies related to environmental concerns.
Earlier this year, Brazil’s government published a set of regulations for the sector that may allow an auction for offshore areas to happen as early as next year.
During his unsuccessful re-election bid, President Jair Bolsonaro mentioned Northeastern Brazil’s potential in offshore wind power several times.
He was defeated by President-elect Luiz Inacio Lula da Silva, who has a key advisor in Senator Jean Paul Prates, responsible for a bill in the upper house of Congress setting up a framework for the sector.
Shell, one of the world’s largest oil companies, is currently awaiting for environmental agency Ibama to approve projects it has for offshore wind plants totaling 17 gigawatts in six Brazilian states.
Reporting by Gabriel Araujo and Leticia Fucuchima; Editing by Steven Grattan
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SEOUL/TOKYO, Dec 7 (Reuters) – South Korean and Japanese power utilities are sustaining heavy losses, kept from passing rising generation costs on to customers and, according to analysts, forced to reconsider the timing of green investments.
The industry is squeezed between high costs of imported fuel, exacerbated by weak currencies, and government unwillingness to displease voters and worsen inflation with price rises.
During the first nine months of this year, state-run electricity distributor Korea Electric Power Corp (KEPCO) reported record operating losses of 21.83 trillion won ($16.69 billion) on revenue of 51.8 trillion won, compared with a loss of 1.12 trillion won a year earlier.
KEPCO is staying afloat with bond issuances and bank loans. Debt had already reached 223% of equity capital at the end of 2021.
However, President Yoon Suk-yeol’s approval rating, just 39% this month, is too low for him to dare to allow a bigger rise in electricity prices than the approximately 13% approved for this year and a similar one for 2023, analysts said.
“In order for KEPCO to swing to profit, we estimate electricity prices must be at least 30% to 40% higher than last year, or the Dubai oil spot price must fall to pre-COVID levels,” said Na Min-sik, analyst at SK Securities.
KEPCO said it had no plans to cut maintenance budgets or facilities investments.
But analysts told Reuters that KEPCO’s capital spending would drop about 20% next year. Items likely to be cut would be improvements to transmission grids to support highly variable electricity flows from renewable sources, they said.
“Since renewable power fluctuates, investment is necessary in transmission infrastructure to grow the portion of renewables in energy mix,” Na said. “But it’s a burden, as 30 trillion won in losses are forecast this year, and continued losses next year.”
Another analyst said: “Out of new power plant construction, maintenance of existing plants and power grid infrastructure, the biggest delays will be in new power plant construction, especially in renewables.”
WHOLESALE PRICE CAP
Moreover, South Korea this month decided to cap for at least three months the base rate at which KEPCO buys electricity wholesale from generation firms.
This will discourage investment in renewable generators, according to an industry association.
“We estimate this could cost us revenues of 90 won per kilowatt. If this cap is extended for a year, it would cost a 10 megawatt generator 100 million won,” said Jung Woo-sik, an executive at lobby group Korea Photovoltaic Industry Association. “We’ll lose investments. This will cripple the renewables industry.”
As for Japan, nine out of 10 key regional electricity utilities booked a net loss for the April-September half-year, with five companies reporting record losses for the period.
All eight utilities that have announced an annual forecast for the fiscal year to March 31, 2023, have warned of a net loss. Tokyo Electric and Kyushu Electric did not provide full-year outlooks.
Most of those that have applied for price rises have said they would maintain green investment, but analysts expect some deferral.
“Investment towards decarbonisation by Japanese utilities may be delayed as the companies seeking to hike prices are saying that they would review all new investments,” said Toshinori Ito, president of Ito Research and Advisory which specializes in energy markets.
By the end of November, five out of 10 major regional utilities had applied to raise prices by between 28% and 46% from April.
They said their financial situation had deteriorated sharply due to soaring fuel prices due to Russia’s invasion of Ukraine and the yen’s plunge against the U.S. dollar. That could hinder stable supply of electricity, they said.
The Japanese industry ministry will examine whether each company’s efforts to improve management efficiency, such as reducing labour costs, are sufficient.
($1 = 1,308.2600 won)
Reporting by Joyce Lee in Seoul and Yuka Obayashi in Tokyo; Editing by Bradley Perrett
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