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Oil & Gas 360 Publishers Note: This is an excellent example from Equinor and Norway on the oil & gas market working to accelerate efforts to capture CO2.

On 30 October Prime Minister Erna Solberg opened the world’s largest CO2 transport test facility at Equinor in Porsgrunn.

The test facility transports CO2 in pipelines, both in gas and liquid form. The objective is to learn more about how CO2 behaves during pipeline transport, which is important knowledge in order to scale up CO2 transport and storage in the future.

The work you do here is an important contribution to the government’s strategy for carbon capture and storage,’ Prime minister Erna Solberg said when she officially opened the test facility.

Equinor has transported CO2 from the Sleipner field in the North Sea since 1996 and from the Snøhvit facility in Hammerfest since 2009, both are projects which have provided Equinor with important information about CO2 transport. In these projects, the CO2 is transported in gas and liquid form, respectively.

Now Equinor and its partners Total, Gassnova and Gassco have modified the facility to make it possible to study transport of CO2 as gas and liquid, simultaneously. This could yield knowledge that is important for determining where a pipeline route could be laid, and which reservoirs could be utilised. Testing and research can improve operation of the CO2 transport and storage project Northern Lights and can also reduce the costs associated with this new industry in the future.

The test facility was built in 1997. It has been used to test the transport of various combinations of oil, gas and water in the same pipeline, so-called multiphase transport. That’s why the facility is called the Multiphase rig. A total of more than one billion Norwegian kroner has been invested in the test facility, including construction and adaptations during the operations period. The facility is the very heart of Equinor’s research centre in Porsgrunn.

The price tag for the modification work was seven million kroner. The test facility has pipes that run in a 200-metre line, and it is the world’s largest test facility for CO2 transport.

‘This shows how infrastructure and competence from the oil and gas industry can be used to accelerate efforts to capture CO2 and store it in reservoir. This is an opportunity to create a new industry in Norway’, says Sophie Hildebrand, Chief Technology Officer in Equinor.

The plan is initially to use the test facility for two different CO2 transport tests, both tests of multiphase transport and testing of measuring instruments. According to the plan, these tests will be under way until the spring of 2021. After that, the test facility will be used to test the transport of both oil, gas and CO2, depending on where the needs are greatest.

Oil & Gas 360º Publisher Note, Editor: Stu Turley, November 30

The world’s largest independent oil trader doubts that new coronavirus lockdowns in Europe will lead to another significant drop in crude prices following last week’s rout.

“This is a speed bump,” Mike Muller, the head of Asia for Vitol Group, said in an interview Sunday with Dubai-based consultant Gulf Intelligence. “We are not going to see a violent reaction in price on Monday.”

Benchmark Brent crude fell 10% in the five days through Friday to $37.46 a barrel, its lowest since May, as daily Covid-19 cases hit a record in the U.S. and nations including France and Germany announced new lockdowns. The U.K. followed suit on Saturday.

While energy demand in Europe is being hit, global oil inventories fell at a rate of around 2 million barrels a day in September and October and that trend will probably continue, according to Muller.

“We are seeing demand destruction unexpectedly from these lockdown measures — hundreds of thousands of barrels-per-day-equivalent for Europe alone,” he said. “But the bigger, overriding picture is still that the world is in a stock-drawing mode.”

Last year, daily oil consumption in Europe totaled 14.9 million barrels, according to data from BP Plc. Demand was 1.5 million barrels a day in France and 2.3 million in Germany.

OPEC+ — an alliance of the Organization of Petroleum Exporting Countries and other producers such as Russia — has helped bolster prices since it agreed to output cuts in April. The group was meant to ease those curbs by 2 million barrels a day in January, but it may be forced into a delay given oil’s renewed weakness.

Bloomberg, Editor: Nadine Daher, November 30

The Shell oil refinery in Convent is up for sale but could face closure if the company doesn’t find a buyer as it consolidates its refinery portfolio from 14 sites to only six by 2025.

Shell warned local officials several months ago that it was testing the market for the potential sale of the Convent site, located between Baton Rouge and New Orleans, and its associated facilities.

“We’ve had success (with asset sales) in the past in difficult markets. If it’s not possible, we’ll consider closing and shutting down,” Chief Financial Officer Jessica Uhl said during a conference call with analysts and investors.

The company does expect to keep “refinery capacity in the key markets tied to our chemical business,” she said.

Shell plans to consolidate its assets into six energy and chemical parks, which includes the Norco site near New Orleans. Other sites are in Deer Park, Texas; The Netherlands; Singapore; Germany; and Canada. The new petrochemical parks are expected to be located near existing complexes, such as Shell’s Geismar site in Ascension Parish.

The goal is for the refineries to be more integrated with the chemical complexes and produce more biofuels, hydrogen and synthetic fuels, executives told investors.

Other refineries under review for potential sale or closure include Puget Sound, Washington, and Mobile, Alabama, along with ones in Canada and Denmark.

The Convent refinery sits on 4,400 acres that straddles Ascension and St. James parishes and can process 240,000 barrels of crude oil per day. It employs 700 Shell workers and 400 contract workers. The processing equipment connected to the plant is located in St. James Parish and occupies about 900 acres.

Shell’s subsidiary, Equilon Enterprises LLC, has $1.18 billion in total taxable value in St. James Parish and paid $18.8 million for the refinery in 2019, tax assessor records show.

The refinery produces various grades of gasoline; jet fuel; diesel fuel and heating oil; propane and butane for residential and industrial use; and oil for tankers, power generation and vehicles.

The facility has access to multiple major crude oil and product pipelines, which ship gasoline, diesel, kerosene and jet fuel. The site’s location on the Mississippi River allows shipping and receiving petroleum products aboard ocean-going vessels. The refinery uses two docks along 6,000 feet of Mississippi River access.

The Convent refinery began operations in 1967 as a Texaco refinery. In 1998, a joint venture was formed between Texaco, Saudi Refining and Shell Oil Co. under the name Motiva. In 2001, Texaco was purchased by Chevron and its interest in Motiva was sold to Shell Oil and Saudi Refining Inc. in 2002. A separation of the joint venture between Royal Dutch Shell and Saudi Aramco in 2017 resulted in the Convent refinery being fully owned and operated by Royal Dutch Shell.

The Advocate, Editor: Kristen Mosbrucker, November 30

Every new crisis is a formidable opportunity to try new things, oftentimes merely to have another go with methods that have failed in the past but should work better now.

Cognizant of the pricing developments in the Asian market, the Iraqi state oil marketing company SOMO has announced that from 2021 onwards it would introduce a new medium sour grade to its set of available grades – Basrah Medium. The concept of Basrah Medium is by no means a complete novelty, it has been mooted for more than 2 years already as a necessary step to mitigate the quality deterioration of Iraq’s flagship export blend, Basrah Light. Next year, however, might be the long-awaited year of breakthrough for Basrah Medium.

Taking a helicopter view of the Iraqi oil export, SOMO’s current grade allocation is quite new when compared to other Middle Eastern NOCs. In the beginning was the word, and the word was Basrah – short and straightforward.

Iraq also had a second export stream in Kirkuk that was predominantly shipped to the Turkish port of Ceyhan and from thereon taken to buyers in the Mediterranean and elsewhere. However, as the US-led military invasion has upended Iraq’s internal standing order, SOMO has found itself between the rock and a hard place in trying to keep its quality commitments. Basrah Light initially started out as a much lighter crude that it currently is – hence its peg to 34 degrees API.

The thing is that the crude production ramp-up from 2010 onwards has altered the quality parameters of Basrah crude, primarily due to the face that all new major fields to be commissioned were really heavy (West Qurna-2 at 23 API or Halfaya at 22-23 API).

The worsening of what is now Basrah Light has compelled Iraqi authorities to create a new crude stream in 2015, Basrah Heavy, easing the quality pressure on Basrah Light. From the start Basrah Heavy had its own resource base – the blend is predominantly composed of crude from 3 supergiant fields (West Qurna-2, Gharraf and Halfaya) – however it lacked a predictable outlet base as many Asian downstream firms were still yet to finalize their expensive refinery reconfigurations that would have allowed to refine challenging crudes, such as Basrah Heavy.

For much of the past 5 years Basrah Heavy was heavily discounted to regional benchmarks in Europe and Middle East. When Basrah Heavy was introduced for the first time in May 2015, its official selling price for Asian deliveries was set at $-6.85 per barrel to Oman/Dubai, whilst the European OSP stood at $-8.45 per barrel to Dated Brent.

Over the years both the better-quality Basrah Light and Basrah Heavy witnessed their market differentials appreciate and the OPEC+ production cuts were of special importance along the way.

Such a positive development was partially counteracted by the unbeseeming quality of Basrah Light and Basrah Heavy – the latter has slid down into the 28-29° API interval (i.e. roughly losing 2 per barrel on the quality mismatch between the contractual quality and the real one), whilst the former was sporadically worsened by a recurrent practice of dumping remaining fuel oil volumes into the general export stream.

Coming back to the concept of Basrah Medium, availability of crude, to use the words of Iraqi energy authorities, was never an issue, as opposed to the availability of storage and blending capacities. Then-Iraqi oil minister Thamir al-Ghadhban claimed last year that the launch of Basrah Medium is directly dependent on having enough storage capacities at the Fao export depot.

The Fao crude storage park plays a key role in Basrah Medium marketing as Fao would be the place where almost all of the pre-export blending would take place. The Fao storage upgrade should have been ready by 2016 already, consisting of 24 storage tanks totaling a bit more than 8 MMbbls – from FAO the crude would go to the single point moorings (SPM) of the Basrah Terminal, effectively the place where domestically-produced crude last touches Iraqi soil.

Hindered by the military operations against the Islamic State and everything that profound challenge entailed, today SOMO can only boast of 16 storage tanks being available in Fao. Having ample storage in Fao underpins SOMO’s quest to have dedicated berths for the three separate streams of Basrah crude – Light, Medium and Heavy.

SOMO has been talking about the “intended segregation” of Basrah Light into two streams – one that carries on with the current quality parameters and the other one which corresponds to the initial Basrah Light quality.

The thing is that Basrah Medium would be the one taking over the 28-29° API quality of today’s Basrah Light and, as it happens, concurrently taking over most of its volumes and Basrah Light would become a lighter stream, much smaller in volumes to be exported. The difficulty of maintaining high Basrah Light exports in the post-2021 horizon will be further exacerbated by the fact that Iraq’s own refineries run predominantly on lighter crudes due to their low sophistication.

The biggest foreseeable problem with introducing Basrah Medium is going to be the decline of Basrah Light. Let’s take the supergiant Rumaila field (current output around 1.4mbpd) as a case in point – heretofore the production has come from the Zubair formation (34-36° API) but future volumes would be heavier and sourer, coming from the field’s Mishrif reservoirs (26-28° API).

In addition, of the other giant fields only West Qurna-2 could provide a short-to-mid-term output boost, however that would also mean more Basrah Heavy production. Hence, it remains to be seen wherefrom does SOMO expect to garner future Basrah Light volumes. The lighter Yamama reservoirs (37-40° API) that should make up the backbone of Basrah Light are only represented by the Luhais and Tuba fields, both nowhere near the reserves and output numbers of Rumaila, West Qurna or Halfaya.

OilPrice.com, Editor: Viktor KatonA, November 30

Midstream companies see EBITDA, cash flow decreases. Contracts key to LNG export expansions. While gas pipeline volumes have been recovering recently, thanks in large part to a surge in activity among LNG exporters, operators plan to keep spending and growth plans in check heading into 2021.

Kinder Morgan, Enterprise Products Partners and Energy Transfer were among the midstream companies that expressed a desire to maintain cost efficiency, at least until the market further stabilizes. Record daily coronavirus cases in the US could cause demand to pull back again, something the operators are watching for carefully.

Sanford C. Bernstein and Co. said in a Nov. 10 note to clients that commodity prices pose the “greatest risks” to companies with natural gas infrastructure, with lower prices potentially leading to lower production and higher-than-expected prices benefiting pipeline volume throughput and processing plant utilization.

“Reduced production or demand for these products hurts the midstream master limited partnership companies that transport them, leaving pipelines empty and companies unable to earn back their investments,” the firm said. “Higher-than-expected production benefits existing assets while providing companies with more growth opportunities.”

Over half of the top 10 midstream companies in an S&P Global Market Intelligence analysis experienced percentage decreases in both adjusted EBITDA and distributable cash flow during the third quarter of 2020 compared with the prior-year period. Cheniere Energy recorded the biggest declines as customers canceled liquefied natural gas cargoes.

LNG exporters like Cheniere plan to focus on existing operations and sanction new expansion projects only once they have a sufficient number of commercial contracts in place. Some have lowered liquefaction fees they are offering new customers to remain competitive, while others have delayed final investment decisions until next year.

Cost cuts
The midstream firms that posted stronger results benefited from “aggressive” cost cuts and plans to return cash to shareholders as volumes strengthened in the Permian Basin and Marcellus and Bakken shales, according to analysts at Morgan Stanley and UBS.

“We were impressed how quickly [management] teams ‘got’ it,” UBS told clients Nov. 9. “Within two quarters since the onset of [COVID-19], capex came down, there was a real hard focus on costs and a slew of buyback authorizations. … Clearly [management] is listening to investors and attempting to deliver.”

Midstream observers have also been waiting for M&A activity in the upstream sector to trickle downstream, but executives acknowledged that such opportunities may be limited because of market uncertainty and depressed valuations, as well as regulatory hurdles.

“Trust me, we’ve looked at a lot of companies, and there are companies out there that I personally would love to have, but there’s no way we can do it because we’d sell damn near everything we bought,” Enterprise co-CEO James Teague said Oct. 28.

Magellan Midstream Partners Chairman, President and CEO Michael Mears said he anticipates “very few” pipeline mergers in 2021 given that the biggest players are laser-focused on maintaining sturdy balance sheets and implementing stock repurchase programs.

The global energy transition away from fossil fuels also took center stage on third-quarter earnings calls. Investors who are focused on environmental, social and governance issues are pressuring pipeline management teams to address the sector’s future. Among other things, the investor movement has been prompted by a shift at gas utilities and European supermajors to a lower-carbon operating environment to fight climate change. While pipeline executives acknowledged that climate efforts require a significant reduction in emissions, they said such projects must make financial sense.

“The returns are lower and lower than what we would see in [oil and gas] midstream investment,” Kinder Morgan CEO Steven Kean noted. “I don’t see us gambling on an uplift in our overall equity value because we started to make some investments in solar panels or windmills.”

S&P Global Platts, Editor: Allison Good, November 30

Slumping fuel consumption during the pandemic is accelerating the long-term shift of refining capacity from North America and Europe to Asia, and from older, smaller refineries to modern, higher-capacity mega-refineries.

The result is a wave of closures, often centring on refineries that only narrowly survived the previous closure wave in the years after the recession in 2008/09.

Fuel consumption has been stagnant or falling across most of North America, Western Europe and Japan since 2007 as a result of efficiency improvements.

North American, European and Japanese refineries have been left battling to protect their share of a declining market, creating downward pressure on profitability.

The problem of overcapacity has been masked during periods of strong economic growth but exposed every time the business cycle turns down.

Asia Fuel Growth

In contrast to Western Europe, North America and Japan, fuel consumption has grown rapidly across the rest of Asia over the last decade.

The region’s three sub-markets in West Asia (centred on the Gulf), South Asia (centred on India) and East Asia (China) have been responsible for more than two-thirds of worldwide oil consumption growth since 2009.

Asia has seen sustained growth in its refining capacity to match the growth in consumption; refineries are typically built near to consumption centres since it is operationally simpler to transport crude than products.

Asia and the Middle East account for 43% of worldwide refining capacity, almost exactly matching their 44% share in global oil consumption, with both shares up from 33% in 1999.

Asia’s refineries are more competitive because they are nearer growing markets; process large volumes with better economies of scale; and are equipped with more modern and sophisticated equipment.

Increasing Scale

In the 1960s and 1970s, new refineries were built at a minimum efficient scale of 100,000-250,000 barrels per day of crude capacity, but refineries commissioned in the 2000s and 2010s are generally 300,000-400,000 bpd or more.

New mega-refineries are often built with integrated petrochemicals units, enabling them to produce a higher share of higher value-added chemicals as well as lower-value fuels.

As a result, the new mega-refineries can squeeze a higher share of valuable products from the same crude at lower cost, outcompeting rivals in North America and Europe.

Facing a shrinking fuel market at home, North American and European refiners have found it increasingly difficult to compensate by growing fuel exports profitably.

And as the average size and complexity of new oil refineries has increased, the oldest, smallest and least complex refineries have become uneconomic.

The result is a wave of refinery closures, with jetties, tank farms and pipelines repurposed to become import terminals .

Most closures have been in North America and Europe, but smaller, older and fuel-only refineries in other parts of the world, including in Australia and the Philippines, have also been hit.

Reuters, Editor: Barbara Lewis, November 30

Oil refiners are permanently closing processing plants in Asia and North America and facilities in Europe could be next because of the uncertain prospects for a recovery in fuel demand after the coronavirus pandemic cut consumption.

The pandemic initially cut global fuel demand by 30% and refiners temporarily idled plants. But consumption has not returned to pre-pandemic levels and less travel may be here to stay, leading to the possibility plants may shut permanently.

United States

Royal Dutch Shell RDSa.L said it was closing its refinery in Convent, Louisiana, the largest such U.S. facility. The shutdown will occur in November after Shell failed to find a buyer. Shell expects to sell all but six refineries and chemical plants globally and is considering closing facilities it cannot sell.

Marathon Petroleum MPC.N, the largest U.S. refiner by volume, plans to permanently halt processing at refineries in Martinez, California, and Gallup, New Mexico.

Singapore

Shell will halve crude processing capacity and cut jobs at its Pulau Bukom oil refinery in Singapore as part of an overhaul to reduce the company’s carbon dioxide (CO2) emissions to net zero by 2050.

Japan

Japan’s biggest refiner, Eneos Corp, permanently shut the 115,000 barrels-per-day (bpd) crude distillation unit at its Osaka refinery on Sept. 30 as planned.

Australia & New Zealand

Exxon Mobil Corp XOM.N is urging the Australian government to start releasing aid to the country’s oil refineries by January after a decision by BP early in November to shut the nation’s biggest refinery.

BP plc BP.L plans to stop producing fuel in Australia and will convert its loss-making Kwinana oil refinery, the biggest of the country’s four, into a fuel import terminal because of tough competition in Asia.

Australia has proposed offering incentives worth A$2.3 billion ($1.68 billion) over 10 years to keep the country’s four remaining oil refineries open and said it would invest in building fuel storage as part of a long-term fuel security plan.

Viva Energy has said a full shutdown of its refinery in Victoria was on the cards given the dire long-term outlook for the industry.

Refining NZ NZR.NZ said in late June it was considering shutting New Zealand’s only oil refinery and turning it into a fuel import terminal, but first would reduce its operations to cut costs and break even into 2021.

Philippines

Royal Dutch Shell RDSa.L will permanently shut its 110,000-barrel-per-day Tabangao facility in the Philippines’ Batangas province, one of only two oil refineries in the country.

Europe

Gunvor Group said in June it was considering mothballing its 110,000 bpd refinery in Antwerp as COVID-19 hurt the plant’s economic viability.

Petroineos said on Nov. 10 it plans to mothball nearly half of its 200,000 barrel-per-day refinery at Grangemouth in Scotland.

French oil major Total TOTF.PA said in September it was investing more than 500 million euros ($583 million) to convert its Grandpuits, France, refinery into a zero-crude platform for biofuels and bioplastics.

Energy consultancy Wood Mackenzie put plants in Netherlands, France, and Scotland on a list of potential closures.

Reuters, Editor: Florence Tan, Ahmad Ghaddar, Bozorgmehr Sharafedin, Enrico Dela Cruz, Seng Li Peng, Erwin Seba, Sonali Paul and Koustav Samanta, November 30

While oil demand in Europe and the United States continues to disappoint, refiners in Asia are racing to procure crude from around the world, giving the oil market some hope that at least in one region, demand is strengthening in the fourth quarter.

Lower term supplies from major OPEC producers due to the OPEC+ cuts, new import quotas for independent refiners in China, and strengthening fuel demand in India have all combined to create a bidding war for crude grades from all around the world going to Asia at the beginning of 2021, traders have told Bloomberg.

The increased demand for crude has pushed the price of Russia’s ESPO blend for January loading to the highest premium over the Dubai benchmark in five months. ESPO is very popular with refiners in China and Japan, but Chinese refiners are also snapping up cargoes from Angola and Brazil, according to the traders who spoke to Bloomberg. Japan and South Korea are also buying more cargoes from Qatar and the United States.

Some of the increased purchases are due to the fact that the top Middle Eastern producers and exporters, Saudi Arabia and Iraq, have recently reduced term supplies to their customers.

Demand in Asia is also supported by India, which sees a recovery in fuel demand that rose year-on-year in October for the first time since February.

Shipbrokers told Reuters that the oil trading units of major oil firms, including Shell and China’s Sinopec, have been on the lookout to book supertankers to send U.S. crude oil from the Gulf Coast to Asia next month. This has pushed the price of the West Texas Intermediate at Magellan East Houston WTI-MEH to the highest in two months, according to Reuters data.

Demand in China and the wider Asia region is currently the only bright spot on the oil market as demand remains depressed in major developed economies in Europe and in the United States, which are grappling with a surge in COVID-19 infections.

OilPrice.com, Editor: Josh Owens, November 30

Oil is trading at its highest level since March as the commodity is swept up in wider market enthusiasm about the US presidential transition process getting underway and positive progress on the vaccine front.

Brent (BZ=F) was up as much as 1% on Tuesday, sitting at $46.47 (£34.26) a barrel at around 10:40am in London.

European markets rallied on Tuesday in the wake of US General Services Administration chief Emily Murphy writing a letter on Monday that confirmed President-elect Joe Biden could formally begin the hand-over process.

Market enthusiasm was also buoyed by the latest news on the vaccine front. AstraZeneca (AZN) said on Monday that its COVID-19 vaccine could be as much as 90% effective, be cheaper to make, easier to distribute and faster to scale-up than its rivals.

“The oil market has for a long time been shrouded with fog, with predictability extremely difficult with respect to both the timing and magnitude of an oil demand rebound,” said Bjarne Schieldrop, chief commodities analyst at SEB.

“This fog has now been lifted and blown away.”

Still, Schieldrop contends that a “Biden administration is bad news for oil” as he is expected to accelerate the green energy transition as well as the electrification of transportation, which will lower oil demand over the long-term.

While the Organization of the Petroleum Exporting Countries and its allies (OPEC+) are expected to extend current output cuts into next year, some members of the group are facing major obstacles. For instance, Iraq is seeking upfront payments of about $2bn for a long-term crude-supply contract, as the country continues to suffer an economic crisis due to low oil prices and wider OPEC+ cuts.

“Once financial markets know the oil market will tighten up, that inventories will decline and the oil market will move from a surplus situation to a tightening situation, then the forward crude oil price curve flattens almost overnight, well before the physical tightening actually begins,” said Schieldrop.

Yahoo! Finance, Editor: Kumutha Ramanathan, November 30