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An under-the-radar hearing on the way shippers will contract volumes on Canada’s key crude oil export pipeline began last month in what could turn out to be the most important battle for control of Canadian oil resources. 

The more than a month-long hearing at the Canada Energy Regulator (CER)—planned to end on June 25—is expected to end up with the regulator determining how Canadian oil firms and U.S. refiners will pay to ship crude on Enbridge’s Mainline system over the next decade. Mainline, with the capacity to ship nearly 3 million barrels per day (bpd) of oil, is Canada’s biggest transporter of oil, carrying crude from oil-rich Alberta to markets in eastern Canada and the U.S. Midwest.  

The current pipeline contracting system expires on June 30, 2021. Mainline’s operator Enbridge has been operating the pipeline for decades under the so-called “common carrier” system, in which all of the huge capacity has been available for short-term shipments of volumes that shippers can change every month. This has given Canadian oil producers the flexibility to contract short-term volumes without having to commit to long-term obligations to ship crude on the pipeline. 

Mainline Operator Enbridge Looks To Secure Long-Term Shipments

Now Enbridge wants to change that. Mainline’s operator seeks to convert the contracting terms to ones where 90 percent of the available capacity would be reserved for long-term access to its network. Canada Energy Regulator’s Commission is set to decide, after the hearing ends at end-June, whether the proposal is fair for all parties. 

Enbridge’s rationale for the new tolling framework is to ensure certainty for shippers in the long term, it says. But it also has a purely business reason to seek long-term firm contracts for Mainline—to reduce its long-term volume risk, because competing pipelines already offer shippers the ability to contract for firm service on a long-term basis. The new proposed system will “provide Enbridge with the tools to compete on a level playing field,” the company said in its proposal. 

For example, the Trans Mountain expansion project already has contracts in place that commit the majority of its capacity to firm service on a long-term basis. In this case, if Enbridge continues as a “common carrier”, it could lose much more than the firm long-term contract pipelines where shippers pay for volumes anyway, regardless of how much they would actually ship one month or next.  

While Enbridge’s application to convert Mainline to firm long-term contracting may be just protecting its business in the long term, it could mean that Canada may give control to its most important pipeline to U.S. refiners, which favor the proposed new contracting system, Samir Kayande, an independent energy business strategy consultant, writes in Financial Post. 

CER Hearing “is about who effectively controls Canadian resources” 

Since refiners typically want low crude oil prices, if they are given their way in the new contracting system, their bargaining power would grow, at the expense of Canada’s exploration and production companies which usually would like to see higher oil prices, Kayande argues.  

“The toll hearing at the CER is about who effectively controls Canadian resources,” Kayande notes. 

According to Enbridge’s evidence, companies that ship over 75 percent of the volumes on the Mainline have said the proposed terms and tolls are “fair, balanced, and productive.”  

“Producers have generally not shipped on the Mainline, with the exception of those that hold capacity on connecting downstream pipelines. It could well be that, if Mainline Contracting is approved, it is primarily parties with refining interests and parties (including producers) that have downstream pipeline capacity that will contract for service on the Mainline,” Enbridge argues. 

“But this would not be a “redistribution of the pie”. This would be entirely consistent with the current and past usage of the Mainline under the 100% uncommitted service structure,” the pipeline operator says.  

Canadian Oil Producers Vs U.S. Refiners

However, most Canadian oil producers, especially those without downstream capacity in Canada and the United States, beg to differ. 

The Explorers and Producers Association of Canada (EPAC), which includes 170 producers, said, “Ensuring that the crude oil and liquids produced and exported from Western Canada realize the highest possible market value is of critical importance to the citizens of the provinces that own the resource, to the oil producers of the WCSB and their investors, to the communities who depend on that investment and to the municipal, provincial and federal governments who rely on the taxes and royalties paid by the upstream oil and gas industry.” 

“These public interests also far outweigh the objectives of the small group of mostly US based refining and allied interests that support the Application, that seek to acquire control for the next two decades over 90% of the transportation capacity on the Mainline thus giving them ability to lower the price that WCSB producers receive for their crude oil,” EPAC noted.

The association also slammed Enbridge’s “fear of competing pipelines” as “self-serving and opportunistic.”  

The Canadian Shippers Group, consisting of Canadian Natural Resources, MEG Energy Corp, Shell Canada, and Total E&P Canada, said that “The Application is the result of an egregious attempt by Enbridge to exert its market power to its own advantage, which would come to the detriment of Canadian based producers, aggregators and refiners.”  

Roland Priddle, the former chair and board member of the National Energy Board between 1986 and 1997, also slammed Enbridge’s proposal in his evidence on behalf of the Canadian Shippers Group. 

“The support that Enbridge has marshalled for the Application does not represent the Canadian public interest: it is biased in favour of U.S. refiners and against Canadian crude oil producing interests, which had previously been the only or the dominant counterparty in settlement negotiations,” Priddle said. 

The ongoing hearing about the changes to Mainline’s operation has turned into a battle about who will control the future of Canadian oil and its prices. 

Oilprice , by Tsvetana Paraskova, June

Oil prices hit the highest level since 2018 as the global economy reopens, global inventories fall. OPEC+ is having its virtual meeting today planning to increase output at a lower rate than the market is asking for because they just assume Iranian oil is coming back on the market. 

Yet reports suggest that Iran is already not complying with weapons inspectors and there is information coming out that could make an Iranian deal impossible.  In the meantime, global demand is rising, and the world is more than likely headed towards an oil supply squeeze. Demand is recovering faster than supply as U.S. Rig counts rose only by 3 last week and crude oil inventories are falling.

The AP reports that The United Nations’ atomic watchdog hasn’t been able to access data important to monitoring Iran’s nuclear program since late February when the Islamic Republic started restricting international inspections of its facilities, the agency said Monday.

The International Atomic Energy Agency reported in a confidential document distributed to member countries and seen by The Associated Press that it has “not had access to the data from its online enrichment monitors and electronic seals or had access to the measurement recordings registered by its installed measurement devices” since Feb. 23.

While the IAEA and Iran earlier acknowledged the restrictions limited access to surveillance cameras at Iranian facilities, Monday’s report indicated they went much further. The IAEA acknowledged it could only provide an estimate of Iran’s overall nuclear stockpile as it continues to enrich uranium at its highest level ever.

Reuters reported that Iran has failed to explain traces of uranium found at several undeclared sites, a report by the U.N. nuclear watchdog showed on Monday, possibly setting up a fresh diplomatic clash between Tehran and the West that could derail wider nuclear talks.

If OPEC+ stays on course, and Iran oil’s comeback is delayed, that should get WTI oil solidly above $70 a barrel. Brent already is above $70. $70 may then try to establish as a floor once we break out of that level.

In the U.S., the biggest winner from President Joseph Biden’s drilling moratorium is Russia. Bloomberg News reports that American imports of Russian crude and refined products continue to climb, reaching almost 750,000 b/d in March, (to put it in context, the US imported 110% more oil from Russia in March than from Saudi Arabia) according to Bloomberg using IEA data.

This is increasing pressure on the Biden Administration. Reuters reports that President Joe Biden’s administration expects to release results of its review of the federal oil and gas leasing program by early summer, Interior Secretary Deb Haaland said on Friday. Biden announced the review shortly after taking office in what was widely viewed as a first step to fulfilling his campaign promise of banning new federal drilling leases to fight climate change.

Lease auctions have been paused in the meantime, upsetting the oil and gas industry and the state governments that host it, who argue the move risks killing jobs and hurting the economy. “The oil and gas review are in the process right now,” Haaland said on a call with reporters to discuss the department’s budget request.

“Everyone’s been working hard on it. We expect to have it released in early summer.” Haaland did not say how long the pause on lease auctions could last. Some 25% of U.S. oil and gas production comes from federal lands and waters. The Biden review is intended to weigh the economic benefits of federal drilling against its environmental and climate costs.

Haaland’s remarks came as the department detailed large increases in spending proposed by the White House on measures to address climate change, including wildfire mitigation and preparedness, permitting renewable energy projects on public lands, and cleaning up abandoned fossil fuel infrastructure.

Gas prices stayed strong this weekend and it looks like they are going to stay that way. Today’s AAA National Average is starting the month of June at $3.045 as many vaccinated travelers sucked down a lot of gallons.

We predicted early that the National average for gasoline would exceed $300 a gallon and that has happened. What is more, it looks like it is going to sit that way.

Investing, by Phil Flynn, June 3, 2021

Hibiscus Petroleum Bhd. is set to take over Repsol’s operations in Malaysia and Vietnam as the Spanish company sells its exploration and production assets in a move away from Malaysia to focus on its core market.  Repsol announced it will be selling oil exploration and production assets in Malaysia as well as Block 46 CN in Vietnam to a Malaysian Hibiscus Petroleum-owned subsidiary. Kuala-Lumpur listed Hibiscus will acquire the whole equity interest in Fortuna International Petroleum Corp for $212.5 million.

Rumors have been circulating around Repsol’s departure from Malaysia since February this year. But Repsol still holds a significant stake in the Southeast Asian oil sector, with major assets in Vietnam and Indonesia. 

The shift appears to be in a bid for Repsol to focus its portfolio on a core set of countries and activities, following its recent withdrawal from Russia and the ceasing of its oil production in Spain. Repsol will continue to focus its efforts around upstream activities, reducing its presence from 25 to 14 core countries.

This will take Hibiscus from being a small Asian player to one of the majors in the region, beating Indonesia’s Medco Energi as a rival bidder for the assets.

Readul Islam, an Asia upstream specialist at Rystad Energy stated of the deal, “In the North Sea, there has been a pack of private equity-backed players willing to pick up stakes as the legacy players exit their positions. In this region, Hibiscus seems to be taking on that role pretty much single-handedly.”

While vice president of analysis at Rystad, Prateek Pandey, said the sale to Hibiscus was “an excellent example of a regional independent stepping up to expand their portfolio as international heavyweights trim their exploration and production presence across Asia.”

The deal will see Hibiscus acquire a 35 percent interest in PM3 CAA PSC, 60 percent in 2012 Kinabalu Oil PSC, 60 percent in PM305 PSC, and 60 percent in PM314 PSC offshore eastern Peninsular Malaysia, as well as 70 percent in Block 46 CN in Vietnam.

However, the deal is pending regulatory approval in both countries, with the Vietnamese regulators proving a potential obstacle. Hibiscus also requires a waiver of partners’ pre-emption rights to complete the purchase. 

Malaysia’s oil and gas industry is slowly rebounding, following a fall in profits across the board in response to low oil demand and prices last year. State-owned oil company Petronas managed to double its first-quarter profits year-over-year, as oil prices climb while other costs have fallen. 

This follows the release of a 10-year industry plan, announced in April by the Malaysian government, aimed at prospering in a lower oil price environment. The national oil and gas services and equipment (OGSE) industry blueprint 2021-30 intends to enhance export potential, diversify the sector through renewable energy projects, and consolidate the industry.

Meanwhile, Vietnam’s state oil company Petrolimex is aiming for an increase in earnings of 9 percent, around $5.86 billion, and a rise in revenue and pre-tax profit of 238 percent, approximately $156 million.

The Hibiscus-Repsol deal could be the first of many as we see regional players take on a larger role in the development of the Southeast Asian oil market.

Oilprice , by Felicity Bradstock, June 3, 2021

India’s fuel demand could fall by as much as 40pc from pre-pandemic levels in the next few months should the surge in the country’s Covid-19 infections lead to extended lockdowns, officials from state-controlled refiners said.

The predictions, which come as the country’s coronavirus outbreak shows no sign of any significant slowdown, are likely to translate into lower refinery operations and crude imports.

Fuel consumption could fall to as little as 60-65pc of levels seen before the Covid-19 pandemic, senior officials at two of India’s state-controlled refiners told Argus. The predictions are based on authorities imposing two-month lockdowns to curb the spread of the coronavirus, as some government health experts are recommending.

Other refinery officials were more optimistic but still expected a significant drop in fuel use in the coming months.

State-controlled refiners, which mostly supply the domestic market, will need to reduce runs to at least 80pc next month, the officials said. Average run rates across the sector are unclear but IOC, the country’s biggest refiner, has cut its throughputs to 85-88pc of capacity from almost 90pc last week, according to a company official. India’s state-run refiners operate around 3.2mn b/d of capacity, including joint-venture plants.

India’s gasoline and diesel demand fell by 5-10pc last month from April 2019. A fall of up to 40pc in consumption could imply reductions of as much as 700,000 b/d for diesel and 290,000 b/d for gasoline, based on demand of 1.75mn b/d and 715,000 b/d respectively in June-July 2019.

Stocks of products such as diesel, bitumen and sulphur are rising, making it difficult for refiners to keep units running at full capacity. Local Covid-19 restrictions are also hitting operations. State-run Chennai Petroleum has reduced runs to less than 90pc at its 210,000 b/d Tamil Nadu refinery after the southern state announced a strict 15-day lockdown from this week. And MRPL will keep a 60,000 b/d crude distillation unit at its 300,000 b/d Mangalore closed until demand revives in Karnataka state, which is currently under a 15-day lockdown.

Runs are also likely be affected at private-sector Reliance Industries (RIL) and Nayara Energy, which is owned by Russia’s Rosneft, market participants said. The cuts are likely to be in line with those at state-controlled refiners, they added. But an official at RIL said the company will operate at its usual capacity because it sells mainly in the export markets.

The latest surge in Covid-19 infections is also preventing refiners from managing the decline in demand by shutting units for turnarounds. There are indications that the so-called Indian variant of the coronavirus is more infectious than the virus that drove previous outbreaks, something that is preventing workers from gathering to postpone maintenance.

High fuel prices are also hurting demand. Gasoline is selling at record levels of over 100 rupees/litre ($1.35/l) in some areas because of heavy taxes. India’s Federation of Automobile Dealers Association says vehicle sales are unlikely to revisit their March 2019 peak until the April 2022 to March 2023 fiscal year. Registrations of new vehicles last month fell by 28pc from March.

Rural surge

But the explosive spread of the coronavirus in India’s towns and villages during the latest outbreak is state-controlled refiners’ major concern. IOC, Bharat Petroleum (BPCL) and Hindustan Petroleum (HPCL) reported strong growth in fuel sales from India’s interior during the first wave of Covid-19 last year, helping offset a slump in demand in urban markets.

India’s positivity rate is high in 640 of the country’s 734 districts, according to government estimates, illustrating how deeply the virus has penetrated. More than half of the recent cases in Maharashtra state were in rural areas, while two-thirds of infections in Uttar Pradesh, India’s most populous state, were in villages.

Districts where the infection rate is more than 10pc — accounting for around 75pc of the total — should remain locked down for another 6-8 weeks to control the spread of the virus, the government’s top medical experts say. That would keep most of India shut until early August. But the government has so far resisted imposing widespread lockdowns, instead leaving the decisions to local authorities.

India reported 343,000 new infections yesterday, down from a record 414,000 a few days ago, although the decline has been accompanied by a reduction in testing. The surge is threatening economic growth, with ratings agency S&P reducing its forecast for GDP growth in 2021-22 to 9.8pc from double digits previously. India’s economy shrank by an estimated 8pc in 2020-21.

India’s diesel use slipped to 1.47mn b/d last month from 1.54mn b/d in March and a pre-pandemic 1.63mn b/d in April 2019, according to the most recent figures from state-run refiners. Demand for gasoline averaged 603,000 b/d in April, down from 675,000 b/d in March and 629,000 b/d in April 2019

By Argus, May 30, 2021

American tire manufacturer Goodyear Tire & Rubber Co. is facing accusations of unpaid wages, unlawful overtime and threats to foreign workers at its Malaysian factory, according to court documents and complaints filed by workers.

In interviews with Reuters, six current and former foreign workers, and officials with Malaysia’s labor department, say Goodyear made wrongful salary deductions, required excessive hours and denied workers full access to their passports.

The department confirmed it had fined Goodyear in 2020 for overworking and underpaying foreign employees. One former worker said the company illegally kept his passport, showing Reuters an acknowledgement letter he signed in January 2020 upon getting it back eight years after he started working at Goodyear

The allegations, which Reuters is the first to report, initially surfaced when 185 foreign workers filed three complaints against Goodyear Malaysia in the country’s industrial court, two in 2019 and one in 2020, over non-compliance with a collective labor agreement.

The workers alleged the company was not giving them shift allowances, annual bonuses and pay increases even though these benefits were available to the local staff, who are represented by a labor union.
The court ruled in favor of the foreign workers in two of the cases last year, saying they were entitled to the same rights as Malaysian employees, according to copies of the judgment published on the court’s website.

Goodyear was ordered to pay back wages and comply with the collective agreement, according to the judgment and the workers’ lawyer.
About 150 worker payslips, which the lawyer said were submitted to the court as evidence of unpaid wages and reviewed by Reuters, showed some migrants working as many as 229 hours a month in overtime, exceeding the Malaysian limit of 104 hours.

The foreign workers are claiming about 5 million ringgit ($1.21 million) in unpaid wages, said their lawyer, Chandra Segaran Rajandran. The workers are from Nepal, Myanmar and India.

“They are put in a situation where they are being denied their full rights as what is provided for (by law),” he said, adding that it amounted to “discrimination.”

Goodyear, one of the world’s largest tire makers, has challenged both verdicts at the high court. The appeal decision is expected on July 26. The verdict for the third case, over the same issues, is due in the coming weeks.

Goodyear declined to comment on any of the allegations, citing the court process. According to the court ruling last year, Goodyear Malaysia argued that foreign workers are not entitled to the benefits of the collective agreement because they are not union members

According to the ruling, a union representative testified that foreign workers are eligible to join and are entitled to the benefits in the collective agreement even if they are not members. The court agreed that the foreign workers’ job scope entitled them to those benefits.
Goodyear told Reuters it has strong policies and practices relating to and protecting human rights.

“We take seriously any allegations of improper behavior relating to our associates, operations and supply chain,” a representative said in an email.
The union — the National Union of Employees in Companies Manufacturing Rubber Products — did not respond to Reuters’ requests for comment on the workers’ complaints

Goodyear’s Malaysia operation is jointly owned by the country’s largest fund manager, Permodalan Nasional Berhad, which directed queries to Goodyear.

Fines and violations

Workers said they faced intimidation from Goodyear after they filed the lawsuits. Goodyear declined to comment.
“The company had different rules for different sets of workers,” said Sharan Kumar Rai, who filed one of the lawsuits and worked at Goodyear in Malaysia from 2012 until last year.

The foreign workers filed the first two lawsuits in July 2019. Soon afterward, Goodyear asked some to sign letters, without their lawyer’s knowledge, that they would withdraw from the legal action, according to their lawyer, police complaints filed in October 2019 and a copy of the letter seen by Reuters. Reporting a complaint to police does not always result in criminal charges but can trigger an investigation.

Industrial court chairman Anna Ng Fui Choo said in her ruling that the letter “was an act of unfair labor practice.”

Malaysia’s labor department told Reuters it had investigated and charged Goodyear in 2020 over nine violations of labor laws, unrelated to the lawsuits, regarding excessive hours and wrongful salary deductions. It fined Goodyear 41,500 ringgit ($10,050), it said.

Malaysia has in recent years faced accusations from its own Human Resources Ministry and authorities in the United States of labor abuse at its factories, which rely on millions of migrant workers to manufacture everything from palm oil to medical gloves and iPhone components.

By Arab News, May 30, 2021

Europe’s oil refiners have big plans to boost the use of green hydrogen to help them make fuel, an important component of the petroleum industry’s plans to cut its operational carbon emissions.

But with the clock ticking in the battle against climate change, the reality of what the industry has committed to remains modest. Green hydrogen comes from water and renewable electricity, while the vast majority of hydrogen made today comes from fossil fuels.

While using green hydrogen will help to clean up a refinery’s operations, it won’t have a big impact on the world’s overall carbon emissions because most of those occur when fuels are consumed rather than when they’re made. The gas is an essential part of oil refining, being used to take impurities out of fuels.

The first European plant to bring a so-called green hydrogen project online looks set to be Royal Dutch Shell Plc’s Rheinland refinery in Germany, with a small electrolyzer scheduled to start production in July. It will make about 1,300 metric tons a year. The International Energy Agency estimates global hydrogen usage is about 70 million tons annually, with consumption dominated by oil refineries and chemical makers.

With capacity of 10 megawatts, Rheinland is on a similar scale to pilot projects being developed across Europe by peers including Austria’s OMV AG and Spain’s Repsol SA. Over the course of a year, an electrolyzer of that size would produce enough hydrogen for less than a week at a complex like Rheinland. There are far bigger developments in the wings — up to a few hundred megawatts — but none of those have so far been funded.

“The problem is that the technology is still being developed, expensive to build and will need to increase in scale to make a significant difference,” said Jonathan Leitch, a director at Turner, Mason & Company.

While green hydrogen delivers higher carbon savings, refiners are also looking at so-called blue hydrogen, where projects tend to be bigger, at around 1,000 megawatts. Those rely on more-established carbon capture technology.

Carbon Capture

Refiners are more at home with blue hydrogen, described by Leitch as being pretty much the same as making hydrogen in a conventional refinery, except the carbon is captured and stored. The U.K., the Netherlands and Norway have the advantage here of being able to use caverns left over from the production of oil and gas to store carbon.

Companies across Europe are looking at using green or blue hydrogen, and most plan to use it in the production of fuels, rather than as a source of power. A refinery would need to make considerable modifications to run on hydrogen, with furnaces only able to tolerate a limited amount of hydrogen in the gas mix, according to Zoran Milosevic, a specialist with Eurotek Refining Services, a U.K.-based consultancy.

“Burning higher volumes of hydrogen in furnaces as fuel will be technically challenging and hardly economical,” Milosevic said.

Below is a list of hydrogen projects at European refineries. It includes projects where a developer mentions refiners among possible customers. It will be updated as developments take place.

Germany, Austria

• Shell Rheinland
• Green hydrogen, 10 megawatt electrolyzer
• Due to start in July
• Hydrogen for use by refinery to make fuel, and in local transport
• Capacity could be expanded to 100MW, but depends on securing funding
• Klesch Heide
• Green hydrogen, 30MW electrolyzer in first phase
• FID due later this year; construction to start in 2H 2022
• Hydrogen initially for use in the refinery
• Will also be tested in natural gas network
• Working with Orsted
• Possible expansion to 700MW
• OMV Schwechat
• Green hydrogen, 10MW electrolyzer
• FID is in place
• Project to complete in second half of 2023
• BP Lingen
• Green hydrogen, 50MW electrolyzer
• FID is due in early 2022
• Working with Orsted
• BP Gelsenkirchen
• Part of group that applied for EU funding in late 2020
• Gelsenkirchen would consume green hydrogen made in a facility owned by RWE

The Netherlands, Belgium

• Shell Rheinland
• Green hydrogen, 10 megawatt electrolyzer
• Due to start in July
• Hydrogen for use by refinery to make fuel, and in local transport
• Capacity could be expanded to 100MW, but depends on securing funding
• Klesch Heide
• Green hydrogen, 30MW electrolyzer in first phase
• FID due later this year; construction to start in 2H 2022
• Hydrogen initially for use in the refinery
• Will also be tested in natural gas network
• Working with Orsted
• Possible expansion to 700MW
• OMV Schwechat
• Green hydrogen, 10MW electrolyzer
• FID is in place
• Project to complete in second half of 2023
• BP Lingen
• Green hydrogen, 50MW electrolyzer
• FID is due in early 2022
• Working with Orsted
• BP Gelsenkirchen
• Part of group that applied for EU funding in late 2020
• Gelsenkirchen would consume green hydrogen made in a facility owned by RWE

U.K.

• Essar Stanlow
• Blue hydrogen
• First of two facilities to start operating in 2025
• Essar is working on a new furnace for the existing crude unit that will allow it to run on hydrogen
• Phillips 66 Humber
• Part of Humber Zero, which is looking at blue and green hydrogen production
• Funding in place up to FID, which is due in 2023
• Phillips 66 Humber
• Part of Gigastack project
• Partners are Orsted and ITM Power
• Valero Pembroke
• Part of South Wales Industrial Cluster

France

• Total La Mede (biofuels plant), in cooperation with Engie
• Green hydrogen, 40MW electrolyzer
• Project depends on securing subsidies
• Engie/Air Liquide Fos
• Refineries and chemicals companies to use the green hydrogen, according to developers
• Funds to be secured
• H2V Normandy
• Green hydrogen
• Air Liquide among partners
• NOTE: Exxon said it would consider buying green hydrogen if a project is launched near Gravenchon, provided it doesn’t hurt its profitability

Scandinavia

• Sweden, Preem Lysekil, in cooperation with Vattenfall
• Green hydrogen
• Project to build 200-500 megawatt electrolyzer being considered Denmark, Everfuel, adjacent to Fredericia
• Green hydrogen, 20MW electrolyzer, which is funded
• Expansion to 300MW subject to financing
• NOTE: Fredericia recently sold by Shell to Postlane Partners
• Norway, Equinor, adjacent to Mongstad
• FID still pending
• Green hydrogen for use in shipping, not in the refinery

Spain, Italy, Greece

• Spain, Repsol Bilbao
• 10MW electrolyzer
• Green hydrogen project isn’t affected by furlough of workers
• Spain, BP Castellon
• Green hydrogen, 20MW electrolyzer in first stage
• Working on feasibility with Iberdrola and Enagas
• Italy, Saras Sarroch, in partnership with Enel
• Green hydrogen, 20MW electrolyzer
• Italy, Eni 2 pilot projects in partnership with Enel

Bloomberg, by Rachel Graham, May 30, 2021

The UK government is subsidising a shift towards hydrogen-powered operations at two of the country’s oil refineries, with £7.7mn ($10.9mn) in environmental grants.

The bulk of the funding is going to Essar Oil UK, which runs the 204,000 b/d Stanlow refinery in northwest England. It has received £7.2mn to covers nearly one third of cost of building the UK’s first refinery furnace able to be fuelled entirely by hydrogen. The furnace will be installed in Stanlow’s only crude distillation unit (CDU), with construction beginning this year and completed by September 2023.

The furnace will use hydrogen produced by the HyNet North West project at the Stanlow site, from where first output is scheduled for 2025. When the furnace is running on hydrogen alone, it will reduce the refinery’s overall CO2 emissions by 11pc a year.

US firm Phillips 66 will receive a government grant of £500,000 to support research examining how hydrogen could be used to fuel gas-fired heaters at the 230,000 b/d Killingholme refinery on England’s northeast coast.

Phillips 66 said last month that it plans to process used cooking oil (UCO) to produce renewable fuels at Killingholme, which it will source from London, China and Singapore.

“The sector is a committed and important partner in reaching Net Zero,” said UK Petroleum Industry Association (UKPIA) director general Stephen Marcos Jones. “UKPIA looks forward to continued close engagement with governments on hydrogen opportunities for the downstream sector.”

The HyNet project will involve two ‘blue’ hydrogen plants with a carbon capture and storage (CCS) chain, requiring a total of £750mn in investment. Essar has said it will build a plant to convert pre-processed household waste into 100mn l/yr of sustainable aviation fuel (SAF), or biojet, at a cost of £600mn. Essar chief operating officer Jon Barden today said that Stanlow aims to be a “net zero site by 2040.”

Essar has been working its way through financial difficulty over the past month or so, after a bank changed the terms of a credit facility, forcing the company to raise new liquidity. Its chief executive and two directors departed the company in March and April.

Last week it said that it had arranged a new $850mn credit facility and completed a review of its governance, leading to the appointment of two new non-executive directors.

The UK government yesterday said that its Industrial Energy Transformation Fund would be allocating £16.5mn to “help energy-intensive sectors cut their emissions.”

Argus, by Benedict George, May 30, 2021

U.S. traffic volumes have almost returned to pre-pandemic levels, helping normalise gasoline consumption as more businesses re-open, domestic leisure travel resumes and workers return to offices.

The volume of traffic on all roads was down by less than 4% in March compared with the same month two years ago, according to the Federal Highway Administration (“Traffic volume trends” FHWA, March 2021).

Traffic levels had been down 41% in April 2020 at the height of the first wave of the pandemic and were still down 11% as recently as December 2020 during the second wave.

Car use likely increased further in April and May as social-distancing restrictions were relaxed and more service businesses and offices re-opened.

More driving means more fuel consumption.

The volume of gasoline supplied to the domestic market, a proxy for consumption, was down by just 4% at 8.9 million barrels per day in the four weeks to May 14 compared with the pre-pandemic five-year average of 9.3 million b/d.

The remaining driving and fuel deficits are likely to be erased over the third quarter as more employees return to central offices and domestic tourism recovers.

The rapid normalisation of gasoline consumption has encouraged a strong resumption of motor fuel production, which is nearing pre-pandemic levels.

Refinery gasoline production is down by just 3% compared with the five years from 2015 to 2019, according to the Energy Information Administration (“Weekly petroleum status report”, EIA, May 19).

Like the driving and consumption deficits, refiners’ gasoline production is likely to reach pre-pandemic levels during the summer

The enormous surplus that accumulated during the pandemic’s first wave has been absorbed. Inventories held at refineries, tank farms and in pipelines are back in line with the pre-COVID five-year average.

Jet fuel consumption is still severely affected by quarantine restrictions. But in the gasoline market the impact of the pandemic appears largely over, provided there is no resurgence of infections.

Ship Insight, by John Kemp, May 24, 2021