Jim Yong Kim abruptly resigned from his post as World Bank president recently, leaving a pillar of the international financial order without leadership or direction. Kim will join a private equity firm, where he believes he can “make the largest impact on major global issues like climate change.”
True, the private sector has an important role to play in mobilising funds for upgrading business models to address the threat posed by climate change. But governments and multilateral institutions remain indispensable to securing the comprehensive economic transformation that is needed.
The scientific evidence for global warming is unequivocal. According to conservative estimates, an increase in global temperature of more than 1.5°C above pre-industrial levels by the end of the century would cause widespread environmental devastation. Increasingly severe weather conditions would destroy biodiversity and livelihoods, while straining resources. Rising sea levels would cause coastal towns to disappear. All of this would contribute to social instability and large-scale migration.
With the human population expected to reach 8.6bn by 2030 – a billion more than today – the only way to achieve our climate goals is to transform the way the world does business. And here, Europe is well-positioned to take the lead by implementing a Green New Deal.
The idea of a Green New Deal – defined as a “national, industrial, economic-mobilisation plan” that would bring about a rapid transition “away from fossil fuels and toward clean energy” – is not new. Even US President Barack Obama included the concept in his 2008 campaign platform.
Under Obama’s leadership, from 2009 to 2016, the United States led the fight against global warming. At home, this meant promoting clean and renewable energy and introducing incentives to spur carbon-reducing innovations in products and services. Internationally, the Obama administration was integral to concluding the 2015 Paris climate agreement.
But, under Obama’s successor, Donald Trump, the US has gone from climate-action leader to climate-change denier. Now, Democratic members of the new US Congress – especially freshman Representative Alexandria Ocasio-Cortez – are working to renew the push toward a green economy. Over the next two years, however, Congress will probably be largely preoccupied by a broader battle over the legitimacy of the Trump administration.
This means that Europe now has an ideal opportunity to lead the world’s green structural transformation, much as it has led on privacy rules and competition policy over the last two decades. To that end, following the European Parliament elections in May, Europe’s liberal and progressive parties and movements should work to implement a Green New Deal.
Success will require, first and foremost, broad public support for a green social contract. But, despite some momentum – for example, the Green Party’s recent electoral success in the German states of Bavaria and Hesse – this will not be easy.
As the Yellow Vest protests in France demonstrate, people will not support making the world greener if it makes their daily lives harder. And there is no doubt that the structural transformation required by a Green New Deal for Europe would require vast funding that might otherwise be spent on programmes with more visible or immediate benefits.
Political leaders advocating a Green New Deal for Europe must therefore work hard to protect citizens’ interests. As French President Emmanuel Macron put it in an open letter intended to calm the protesters, “Making the ecological transition allows us to reduce spending on fuel, heating, waste management, and transport. But to make this transition a success, we need to invest on a huge scale and support our fellow citizens from the most modest backgrounds.”
Beyond practical pledges, political leaders must provide a convincing and even inspiring narrative to spur climate action. Cognitive scientists, such as George Lakoff, have long argued that people are more responsive to political arguments that are framed according to their own values (as opposed to those of the person making the argument). So, if liberal and progressive forces want a majority of the electorate to support the spending required to mount an effective response to global warming, they need to frame the Green New Deal – not unlike US President Franklin D Roosevelt’s original New Deal in the 1930s – in terms of security.
People need to be protected from the instability that increasingly extreme weather will create, and they need support during the transition to greener (higher-quality) employment. Meanwhile, businesses need incentives to pursue the long-term opportunities created by the economic transformation.
This unifying emphasis on long-term societal, personal, and economic security would contrast sharply with prevailing populist narratives, which frame security as an identity issue and thus tend to trigger emotional – and divisive – responses. And there is reason to believe that it could work. One of the key, albeit contested, legacies of Angela Merkel’s chancellorship in Germany, for example, is her government’s leadership of the Energiewende, or energy transformation, which gained traction after the 2011 Fukushima nuclear disaster raised questions about the long-term security of supplies.
Other European countries have also demonstrated leadership on global climate action. The Danish government, for example, recently pledged to phase out the sale of all gasoline- and diesel-powered cars by the year 2030, and a broad political consensus sustains the goal of reaching a carbon neutral society by 2050.
But, to achieve a safer and more prosperous future, all of Europe – and, indeed, the world – needs to pull its weight. A transnational compact uniting Europe’s liberal and progressive movements ahead of the European Parliament election can leverage the force produced by cross-partisan consensus and broaden popular support.
Europe desperately needs to take ownership of its future once again. A new vision centred on the Green New Deal can enable it to do just that. – Project Syndicate

* Massimiliano Santini is a fellow with the European University Institute and a senior economist on leave from the World Bank. Fabrizio Tassinari is Executive Director of the School of Transnational Governance at the European University Institute.

Oil explorers cut drilling in US shale fields, shrugging off oil’s rebound, as investors urge them to keep spending in check. American drillers idled 15 oil rigs last week, bringing the number of active equipment down to 847, the lowest since May, according to data released on Fri- day by oilfield-services provider Baker Hughes. Crude futures extended their rally in New York after the report was released, touching a two-month high of $55.66 a barrel. A rebound in oil prices since Christmas Eve has yet to turn the sentiment of explorers who saw a late 2018 price plunge blow up spending plans and led them to tighten belts across the industry. The biggest rig cut among major US shale plays came from the Permian Basin of West Texas and New Mexico, where the count dropped by 3 this week, to 481. Helmerich & Payne Inc, the biggest US provider of land rigs, said demand for its most expensive equipment has softened for the start of this year because of uncertainty over oil prices and more prudent spending. “Discussions with several customs- ers regarding capex outlook indicates a mix of increasing, decreasing, and flat spending budgets,” chief executive officer John Lindsay told analysts and investors this week on a conference call. “However, the consistent theme is discipline, principally keeping 2019 spending within cash flow.” Helmerich joined Halliburton Co and Schlumberger Ltd in slashing spending as their customers are under pressure from shareholders to keep budgets in check. North American explorers are expected to cut their rate of annual spending growth by half to 9%, analysts at Barclays Plc wrote last month in a note to investors. In kind, explorers have cut rig usage all but one week this year.

Exxon Mobil Corp and Chevron Corp bided their time, watching smaller independent drillers make the first moves in shale before placing their bets. Now they’re all in.
The two US supermajors are investing heavily in Texas pipelines and processing facilities as they build out their rig-to-refinery approach to the Permian Basin, demonstrating how shale is becoming a core driver of the world’s biggest oil companies’ future growth.
Both Exxon and Chevron nearly doubled production from the Permian over the last 12 months and expect strong expansion to continue. For Chevron, the region will produce a fifth of all its oil by the mid-2020s. But rapid growth brings transportation and refining challenges. This is where the supermajors think they can steal a march on rivals, who have until now stolen the show in the world’s premier shale field.
Exxon will “bring fundamental science and technology, bring large-scale efficient development and bring an integrated well-to-market approach” to the Permian, chief executive officer Darren Woods said during a call with analysts Friday. “We believe our approach will deliver the lowest-cost supply and give us a significant advantage over the rest of the industry.”
The supermajors only produce about 9% of Permian oil so “have a long way to run,” according to Raoul LeBlanc, a Houston-based analyst at IHS Markit. But they’re coming on fast. At the start of 2017, they spent less than 5% of drilling and well completion capital in the Permian and by the end of 2018 they had jumped to 15%, he said.
While the Gulf Coast refining hub is the natural destination for Permian oil, processing all that crude is not so simple. For years, refiners upgraded facilities to handle heavy, high-sulphur oil from Venezuela, Canada and Mexico as US production waned. But the shale boom brought an abundance of light, low-sulphur crude that isn’t optimal feedstock for heavy
refineries.
So more capacity is needed. To handle surging Permian oil flows, Exxon is expanding capacity at its Beaumont refinery in Texas by 65%, a move that will make it North America’s biggest. The cost will be about $1.1bn, according to analysts at Cowen & Co Exxon also signed off on a giant crude pipeline, developed with Plains All American Pipeline LP and Lotus Midstream LLC, that will ultimately carry 1mn barrels a day.
Keeping pace, Chevron agreed to buy a Houston-area refinery from Brazil’s Petrobras for $350mn, the company’s first refinery acquisition in decades. The ageing operation that mainly processes the light crude harvested from US shale will boost Chevron’s Gulf Coast refining capacity by almost a third.
“It is in a great location and that allows us to integrate increasing light crude production out of West Texas,” chief executive officer Mike Wirth said on a call with analysts.
For the sceptics, it’s about time. While smaller rivals were experimenting with fracking technology and buying up drilling rights in the now-prolific basin early in the decade, Exxon and Chevron didn’t really get going until years later.
Although Exxon’s inaugural foray into shale happened in 2010 with the $35bn purchase of XTO Energy Inc, that was a gas deal. The real money was in oil, spurring Exxon to spend a further $6.6bn in 2017 to amass Permian drilling rights from the Bass family.
As for Chevron, the California-based driller inherited a commanding 2.2mn acres of drilling rights, the second-largest behind Occidental Petroleum Corp’s, from its 2001 takeover of Texaco Inc.
Both companies have gone through steep learning curves, picking up techniques from smaller rivals. Still, there are worries they haven’t yet caught up.
“There are concerns that you are perhaps not as leading-edge as we might want you to be in terms of your Permian performance on a returns basis,” Paul Sankey, a New York-based analyst at Mizuho Securities USA LLC, said to Chevron’s Wirth on the call.
Wirth responded by saying returns are “very, very strong.”

The shale boom has created a world awash with crude, putting a lid on prices and markedly reducing U.S. dependence on imported energy. But there’s a growing problem: America is producing the wrong kind of oil.

Texas and other shale-rich states are spewing a gusher of high-quality crude — light-sweet in the industry parlance — feeding a growing glut that’s bending the global oil industry out of shape.

Refiners who invested billions to turn a profit from processing cheap low-quality crude are paying unheard of premiums to find the heavy-sour grades they need. The mismatch is better news for such OPEC producers as Iraq and Saudi Arabia, who don’t produce much light-sweet, but pump plenty of the dirtier stuff.

The crisis in Venezuela, together with OPEC output cuts, will exacerbate the mismatch. The South American producer exports some of the world’s heaviest oil and the Trump administration sanctions announced this week will make processing and exporting crude far more difficult. American refiners are scrambling for alternative supplies at very short notice.

“We still have some holes in our supply plan” over the next 30 days, Gary Simmons, a senior executive at Valero Energy Corp., the largest refiner in the U.S., told investors on Thursday. “We are not taking anything from Venezuela.”

Crude isn’t the same everywhere: the kind pumped from the shale wells of West Texas resembles cooking oil — thin and easy to refine. In Venezuela’s Orinoco region, it looks more like marmalade, thick and hard to process. Density isn’t the only difference — the sulfur content is also important, dividing the market into sweet and sour crude. Heavy crude tends to have more sulfur than light crude.

As Saudi Arabia, Russia and Canada cut production, and American sanctions force Venezuelan and Iranian exports lower, the market for low-quality crude is feeling the impact.

“The strength in the physical crude market continues, led by sour crude shortages,” said Amrita Sen, chief oil analyst at consultant Energy Aspects Ltd. in London, echoing a widely held view within the market.

For consumers and politicians focused on the headline oil price for Brent and West Texas Intermediate, the most popular benchmarks, it may not matter much. Car drivers could even benefit, because too much light-sweet crude often leads to too much gasoline, and lower prices. On the flip side, truckers may find themselves short-charged, as refiners prefer heavy-sour crude to make diesel.

To oil traders in the physical market, it provides opportunities to profit from the changing price spreads between different crude varieties.

Few oil executives see the market changing anytime soon. The supply and demand balance could deteriorate further as OPEC deepens output cuts next month — Saudi Arabia has warned it will reduce production even further in February. Saudi oil exports into the U.S. last week fell to the second-lowest level in nearly a decade.

“OPEC cuts will sustain the tightness of heavy-sour crude,” Alex Beard, the head of oil at commodities trading giant Glencore Plc.

At the same time, U.S. shale production keeps growing, feeding the glut of light-sweet crude. The proportion of light crude in U.S. total petroleum output has risen to nearly 57 per cent, up from 51 per cent in early 2017, according to Bloomberg calculations based on U.S. Energy Information Administration data.

In the physical market, oil price differentials for some important varieties of heavy-sour crude — including Russia’s main export grade, Urals, and Mars Blend from the U.S. Gulf of Mexico — are at the strongest levels in five years, according to data compiled by Bloomberg.

Mars crude on Tuesday traded at a US$5.85 premium to U.S. benchmark West Texas Intermediate, compared with a discount of US$1.60 a barrel a year ago. Earlier this month, Heavy Louisiana Sweet crude traded at a rare premium to its sister variety Light Louisiana Sweet.

“OPEC is having the impact that they wanted in the physical market, which is tightening,” Marco Dunand, chief executive officer of commodities trader Mercuria Energy Group Ltd.

Heavy-sour crude is becoming so expensive — and gasoline refining margins are so low — that some U.S. refiners are running their most sophisticated kit at low rates in an effort to save money. Others are likely to follow.

The cracking margin for heavy-sour crude for the most sophisticated refineries in the Gulf of Mexico has fallen to about US$2.50 per barrel in recent days, compared with a five-year average of US$12 a barrel, according to data from consultant Oil Analytics Ltd.

The global refinery has no option but to adapt almost in real time. Valero is “changing the way it’s sourcing crude on a weekly, daily basis to try to get the best netback we can on the plants,” Joe Gorder, chief executive officer, told investors on Thursday.

In a new development, Iran has invited Pakistan’s legal team to thrash out if sanctions are effective on gas transactions or not after getting 10-12 legal questions from Islamabad side. Iran is of the opinion that Pakistan needs to get waiver from US on gas as India and other countries managed. Pakistan and Iran signed GSPA (gas sales purchase agreement) in 2009 under IP gas pipeline project in era of Pakistan Peoples’ Party. Since then the project could not get the shape, rather this mega project witnessed many upheavals in the shape of US sanctions first by Obama administration, and under latest scenario more stern curbs by Trump administration. The project was to be implemented under segmented approach meaning by that Iran had to lay down the pipeline on its side and Pakistan had to build the pipeline in its territory. The project was to be completed by December 2014 and come on stream from January 1, 2015. Under the penalty clause it was agreed by both sides that if Pakistan fails to have intake of Iranian gas from January 1, 2015, it will have to pay $1mn per day as penalty. Pakistan has failed to lay down pipeline of 781km in its territory on account of failure in arranging the funding mainly because of the sanctions imposed on Iran for its nuclear ambitions. But in 2016, the Nawaz government had shelved the project apparently in the wake of pressure of one of the leading UAE countries, but the then Petroleum and Natural Resources Minister Shahid Khaqan Abbasi had confirmed saying: “The government had deferred the project as government wanted the private sector to invest in the LNG terminals and import LNG in the country and to this effect, both new LNG terminals are being erected. “Now under the latest scenario, we have sent to Iranian legal team about 10-12 questions contesting the opinion of Iran on gas sanctions and in return Iranian side has invited Pakistan legal team to hold in-depth talks with its legal wizards over sanctions on gas transaction,” a senior official of Petroleum Division said.

However, Minister for Petroleum and Natural Resources, Ghulam Sarwar Khan said, “Yes, both the countries are engaged on this issue, but advancement on IP gas line is conditional with the lifting of the sanctions. However, the decision will be made keeping in view the supreme interests of the country.” The law firm of known international law expert of Ahmar Bilal Soofi on behalf of Pakistan has carved out a questionnaire of 10-12 for legal team in Iran. When contacted Bilal Soofi confirmed saying his firm has sent its response asking for the legal framework under which the sanctions become effective on some commodities not on gas. However, he opted to avoid to response when asked about the details of the questions saying it will not be proper to unravel the details as it is the prerogative of the government of Pakistan. Tehran earlier in November, 2018 asked Islamabad in official engagement held in Islamabad to get the waiver from US sanctions as India has managed, to implement the much delayed Iran-Pakistan (IP) gas line project. Iranian side in November talks had also emphasised arguing that there exists no sanctions particularly on gas transactions, so Pakistan should come forward and start working for IP gas line implementation. The Iranian team had asked authorities to initiate concerted efforts to get waiver from US for implementation of the IP gas line project if Pakistan considers that US sanctions are also active on gas- related transactions. Iranian side in favour of its arguments also said that India has managed the waiver and Pakistan needs to follow the suit. The Trump administration on November 5 imposed a new raft of sanctions on Iran after backtracking from landmark 2015 international agreement on Iran’s nuclear programme. However, the US has granted exemptions to eight countries that include China, India, Greece, Italy, Taiwan, Japan and South Africa allowing them to continue buying Iranian oil. Pakistan response said that waiver for eight countries exists for 6 months. And after that they will have to arrange other sources for oil business. However, Petroleum Division had assured Iran that it will consult the law firm which is on the panel of Inter-State Gas System (ISGS) which will be in touch with legal minds of Iran on this particular issue. “There were three kind of sanctions imposed from UN, US and EU on Iran,” a senior official said adding that EU sanctions have turned mild, but still there are some selected parameters. However, we need to examine all the sanctions’ impact and their nature and will come up with professional opinion on the issue Iran has raised with Pakistan.” Iran in February, 2018, according to the official, threatened to move arbitration court against Pakistan for unilaterally shelving IP gas line project invoking penalty clause of the Gas Sales Purchase Agreement (GSPA). Tehran had asked for the payment of over $1.2bn as under the penalty clause from January 1, 2015, as Pakistan is bound to give penalty of $1mn per day if it fails to have intake of gas from Iran under IP project.

BP has agreed to broaden its disclosure on greenhouse gas emissions to show how it thinks future investments in oil and gas align with UN-backed climate goals, it said yesterday.
Following talks with a large group of investors, BP also agreed to back a shareholder resolution on the measures at its annual general meeting (AGM), further evidence of the way the energy industry and investors are engaging on climate issues.
The agreement with a group of investors with $32tn under management, known as Climate Action 100+, comes weeks after rival Royal Dutch Shell agreed to introduce broad carbon emissions targets linked to executive pay.
Unlike other companies, BP has agreed to detail how major future investments in fossil fuels will be consistent with the 2015 Paris agreement to reduce carbon emissions to net zero by the end of the century by phasing out fossil fuels.
It will set out new metrics to measure greenhouse gas emissions from its operations.
BP said in a statement it would link carbon targets to the remuneration of 36,000 of its employees, including executive directors.
If the resolution is approved at the AGM, BP will introduce these changes into its reporting for 2019 onwards.
But the joint agreement revealed a fundamental rift with investors over BP’s statement that its strategy today was in line with the Paris agreement.
“Investors remain concerned that the company has not yet demonstrated that its strategy, which includes growth in oil and gas as well as pursuing low carbon businesses, is consistent with the Paris goals,” Climate Action 100+ said in statement.
BP plans to rapidly grow oil and gas production over the next five years thanks to more than a dozen new projects launched in recent years, as well as the $10.5bn acquisition of BHP’s US shale portfolio last year.
“We will be open and transparent about our ambitions and targets as well as our progress against them,” BP chairman Helge Lund said in a statement.
BP chief executive officer Bob Dudley has repeatedly said that while the oil and gas sector needs to play a role in the transition to low carbon energy, it still needs to meet growing demand for fossil fuels, particularly in emerging economies.
“BP is committed to helping solve the dual challenge of providing more energy with fewer emissions. We are determined to advance the energy transition while also growing shareholder value,” Lund said.
Investors and analysts have said many oil and gas projects, such as complex and expensive investments in Canada or some deepwater basins, will not be needed in the transition to a low carbon energy.
While BP agreed to increase its disclosure around climate, it also rejected another resolution tabled by climate activist group Follow This calling for emission reduction targets for all its operations, including emissions from products it sells to customers, known as Scope 3.
BP announced in April plans to keep carbon emissions flat over the decade to 2025 even as its oil and gas output was set to grow.
It also plans to invest up to $500mn per year on renewable energies such as solar, wind and power storage.

LONDON (Reuters) – Freezing temperatures across much of the northern United States have caused barely a ripple in natural gas markets showing how plentiful supplies have become thanks to the shale revolution.

In a sign of improving resilience, the gas and electricity networks have come through the most recent polar vortex with far less stress on gas supplies and electric generators than during the last major vortex in January 2014.

While policymakers in Washington debate whether the increasing interconnectedness of gas and electricity systems poses a risk to reliability, both industries are improving their ability to cope with extreme cold events.

Temperatures across the Midwest fell to multi-decade lows this week and daily gas consumption is forecast to have hit record levels on Jan. 31 (“U.S. natgas use hits record during freeze”, Reuters, Feb. 1).

Even before the cold snap, gas stocks were 13 percent below the five-year average at the end of last week, according to the U.S. Energy Information Administration (“Weekly natural gas storage report”, EIA, Jan. 31).

But futures prices for gas delivered in March continued to fall and are now close to their lowest levels for the last four years, well below $3 per million British thermal units.

Gas stocks have remained reasonably comfortable as a result of a relatively mild winter so far and plentiful supplies that have ensured stocks have drawn down more slowly than in previous years for any given level of cold.

The winter heating season has now passed the half-way point and, so far, temperatures have been slightly warmer than the long-term average, according to government data.

Cumulative population-weighted heating degree days between July 1 and Jan. 30 were 3 percent lower than the long-term average (“Degree day statistics”, U.S. Climate Prediction Center, Jan. 31).

This winter has been significantly colder than the exceptionally mild winters of 2015/16 and 2016/17 but about the same as winter 2017/18 and is still warmer than average so far.

The current cold snap is expected to be relatively short-lived, with temperatures forecast to rise significantly in the next few days and heating demand expected to fall back below the seasonal norm.

The impact on gas stocks and prices of generally mild temperatures has been compounded by much smaller draws on stockpiles for any given level of heating demand this year than in either 2017/18 or 2016/17.

The limited drawdown on gas stocks reflects the tremendous surge in production which is easily able to meet growth in domestic demand including from electricity generators.

U.S. gas production hit a record 2.70 trillion cubic feet in October and another near-record 2.65 trillion cubic feet in November, according to the Energy Information Administration.

U.S. gas production has been growing at rates of around 13 percent per year, the fastest rate for at least two decades.

Production is growing so fast that even with some of the coldest weather in decades supplies have remained adequate with no spike in prices and no forced curtailments by generators or significant loss of load.

John Kemp is a Reuters market analyst. The views expressed are his own.

SINGAPORE, Jan 31 (Reuters) - Asian refining margins for 10ppm gasoil eased on Thursday, a
day after hitting a one-week high, as crude prices firmed, but posted their first month of gains
following two straight months of declines.
    Refining margins or cracks for gasoil with 10ppm sulphur content were at
$13.89 a barrel over Dubai crude during Asian trade, down from $14.22 a barrel on Wednesday. 
    Crude oil prices rose on Thursday, pushed up by lower imports into the United States amid
OPEC efforts to tighten the market, and as Venezuela struggles to keep up its crude exports
after Washington imposed sanctions on the nation.
    The benchmark gasoil margins have risen about 11 percent in January, the biggest monthly
gain since August 2018. 
    Lacklustre demand amid availability of ample supplies, however, has kept the current
refining margins for the industrial fuel about 15 percent lower than this time last year.
    Cash discounts for 10ppm gasoil GO10-SIN-DIF were at 42 cents a barrel to Singapore quotes
on Thursday, compared with a discount of 34 cents per barrel a day earlier.
    Meanwhile, cash discounts for jet fuel narrowed to their smallest in over two weeks, buoyed
by expectations for a tighter market going forward as some refineries in the region are
scheduled to go for spring maintenance.
    Jet cash discounts JET-SIN-DIF were at $1.42 a barrel to Singapore quotes on Thursday,
compared with a discount of $1.55 a barrel on Wednesday.
    The February/March time spread for the aviation fuel narrowed for the fourth
consecutive session to a discount of 40 cents a barrel on Thursday, their slimmest in three
weeks. They were at a discount of 57 cents on Wednesday.
    Refining margins for jet, which also determines the profitability of
closely-related kerosene, edged higher to $14.24 a barrel over Dubai crude, 18 cents higher from
Wednesday. 
    
        SINGAPORE INVENTORIES
    - Singapore onshore middle-distillate stocks fell 4.6 percent to 11.8 million barrels in the
week to Jan. 30, according to data from Enterprise Singapore released on Thursday.
    - The inventories have averaged 11.9 million barrels in the first five weeks of this year,
having averaged 9.6 million barrels a week in 2018. In 2017, the weekly average was about 12
million barrels, Reuters calculations showed.
    - Overall, onshore middle-distillate inventories were about 27 percent higher year on year.
    - Light distillates stocks dropped 169,000 barrels to a two-week low of 15.7 million barrels
in week ended Wednesday, while fuel oil stocks rose 478,000 barrels to a six-week high of 20.3
million barrels.
    
        EIA INVENTORIES
    - U.S. crude oil stockpiles rose less than expected last week due to a drop in imports,
while gasoline and distillate inventories fell as refiners slowed down production, the Energy
Information Administration said on Wednesday.
    - Crude inventories rose 919,000 barrels in the week to Jan. 25, compared with
analysts' expectations for an increase of 3.2 million barrels.
    - Distillate stockpiles, which include diesel and heating oil, fell 1.1 million
barrels, versus expectations for a 1.4 million-barrel drop, the EIA data showed.
        
    SINGAPORE CASH DEALS
    - No gasoil deals, no jet fuel trades.

SINGAPORE (Reuters) – PetroChina Co plans to drop Petroleos de Venezuela SA (PDVSA) as a partner in a planned $10 billion oil refinery and petrochemical project in southern China, said three sources familiar with the matter this week.

The company’s decision adds to state-owned PDVSA’s woes after the United States imposed sanctions on the company on Jan. 28 to undermine the rule of Venezuelan President Nicolas Maduro.

However, dropping the company was not a reaction to the U.S. sanctions but follows the deteriorating financial status of PDVSA over the past few years, said two of the sources, both executives with China National Petroleum Corp, the parent of PetroChina.

“There will be no role of PDVSA as an equity partner. At least we don’t see that possibility in the near future given the situation the country has been through in recent years,” said one of the executives, asking to remain unidentified because he is not authorized to speak to the media.

The move illustrates the fading relationship between Venezuela and China, which has given $50 billion to the South American country in the form of loans-for-oil agreements. China, the world’s largest oil importer, is now the second-biggest buyer of Venezuelan crude in Asia, taking in 16.63 million tonnes, or about 332,000 barrels per day (bpd), in 2018.

That relationship began to fray in 2015 when Venezuela requested a change in the payment terms on the debt to ease the impact of its falling crude output and declining oil prices. Instead of handing out large fresh loans, Beijing has shifted to small investments or granting extensions in the grace periods for the outstanding loans.

The sanctions were imposed at the same time the United States and other nations have backed opposition leader Juan Guaido as legitimate ruler instead of President Nicolas Maduro. During Maduro’s rule, oil production has plunged while millions have left amid hyperinflation and as consumer goods have vanished from market shelves.

PDVSA was originally a 40 percent equity partner in the refinery project, located the city of Jieyang in the southern province of Guangdong. PetroChina and PDVSA received environmental approval for the project in 2011.

Initial plans were for the refinery to process 400,000 bpd of strictly Venezuelan crude oil. The plans have now been expanded to focus on petrochemical production including a 1.2-million-tonnes-per-year ethylene plant and a 2.6-million tpy aromatics plant. The plant is expected to be operational by late 2021, Caixin reported on Dec. 5.

Under the revised plan, the refinery will not be restricted to Venezuelan oil but could process other so-called heavy crude grades that could come from Middle Eastern producers such as Saudi Arabia and Iran, said the third official, a PetroChina trading executive.

Hyundai Heavy Industries, the world’s biggest shipbuilding group, has announced a share swap deal worth 2.1tn won ($1.98bn) to take over second-ranked Daewoo and create a global heavyweight controlling over 20% of the market.
The move comes as the worldwide shipbuilding sector recovers from a global economic downturn that led to massive losses, widespread job cuts and, in 2017, the $2.6bn bailout of South Korea’s Daewoo Shipbuilding & Marine Engineering Co Ltd.
State-funded Korea Development Bank (KDB) owns 55.7% of Daewoo, and has said it intends to sell the stake and consolidate the country’s three biggest shipbuilders – which includes Samsung Heavy Industries Co Ltd – into two.
The combination of two of the giant shipbuilders would ease competition and excess capacity, which have depressed ship prices, KDB chairman Lee Dong-gull said at a news conference.
The deal will “raise the fundamental competitiveness of Daewoo, at a time when the threat from latecomers in China and Singapore is growing,” Lee said yesterday.
Hyundai and Daewoo hold a combined market share of 21.2%, followed by Japan’s Imabari Shipbuilding with a 6.6%, showed data from Clarksons Research.
Lee said it will take several months to gain approval from antitrust regulators from related countries. He said the size of the resulting entity’s market share would not be detrimental to the interests of customers.
Daewoo will also receive liquidity support of 2.5tn won ($2.25bn) from KDB and Hyundai, Hyundai said in a stock exchange filing.
KDB also said it would approach Samsung Heavy to gauge any interest in taking over Daewoo. A Samsung Heavy spokesman said it has received a proposal from KDB and that it needs to review the matter.
Daewoo shares rose as much as 22% yesterday, before ending up 2.5%.
Those of Hyundai Heavy Industries Holdings Co Ltd and unit Hyundai Heavy Industries Co Ltd fell about 4% on concern about a high purchase price, analysts said. Meanwhile, Samsung Heavy shares ended up 2.5%, as investor concerns of it bidding for Daewoo eased. “Consolidation is good for the industry, but not for the company which buys the stake,” said analyst Um Kyung-a at Shinyoung Securities, citing overlapping businesses between Hyundai and Daewoo.
The shipbuilding industry accounts for 7% of both exports and employment in Asia’s fourth-biggest economy. Hyundai Heavy’s workers’ union said it will delay a vote on last year’s wage deal in protest of a purchase it says could threaten job security.
It said it would be “angered” if the shipbuilder ploughed money into buying another big firm having released workers after reporting losses and shrinking orders. KDB’s Lee ruled out any job cuts after the combination.
Hyundai’s holding company is set to raise funds for acquisitions through the sale of part of its stake in refiner Hyundai Oilbank Co Ltd to Saudi Aramco for up to 1.8tn won.