Shell to cut up to 10pc of workforce by 2022: Update
Adds details from internal document
Shell expects to cut up to 9,000 jobs by the end of 2022, more than 10pc of its workforce, as part of a structural reorganisation to shift towards a low-carbon future.
"We have to be a simpler, more streamlined, more competitive organisation that is more nimble and able to respond to customers," chief executive Ben van Beurden said. "We have too many layers in the company: too many levels between me, as the CEO, and the operators and technicians at our locations."
The firm will look to cut between 7,000-9,000 jobs over the next two years. Shell will reduce the number of jobs in the top three layers of the company by nearly a fifth, van Beurden told employees in an internal document seen by Argus.
The total job cuts include around 1,500 people who have already agreed to take voluntary redundancy this year, but they exclude those who leave Shell because of divestments. Shell had a workforce of 83,000 at the end of last year. It said the redundancy programme, combined with other measures, should save $2bn-2.5bn/yr by 2022.
Earlier this year Shell cut its dividend for the first time since the 1940s, partly in preparation for the energy transition shift, saving it $10bn this year and reducing the need for urgent redundancies. But the firm said today that it plans to make its traditional business more focused as part of a low-carbon future. It has already announced plans to become a net-zero emissions energy business by 2050 or sooner.
"We will continue to invest, but it will not be about how many barrels of oil, or cubic feet of gas, [the] Upstream [business] produces, but how much it adds to the bottom line," van Beurden said. "Upstream will be critical to Shell as we change — we need it to be very successful, so we have the financial strength to invest further in our lower-carbon products."
Shell is seeking to sell five refineries to reduce its fleet to fewer than 10, and plans to grow its integrated gas business. The new "reshaped Shell" will be set up with a strong focus on helping customers decarbonise in sectors such as aviation, shipping and road transport, van Beurden said. "We have to change the type of products that we sell."
Shell plans to establish a "sectors and decarbonisation" business in its downstream segment, according to the internal document. And it plans to integrate a number of departments under one structure. For example, IT, digital and data capabilities will move into the projects and technology organisation.
Shell's decision to reduce its workforce follows in the footsteps of competitor BP, which announced in June it would cut 14pc of its global workforce — around 10,000 jobs — as a result of the oil downturn brought on by Covid-19 and citing the energy transition. Shell plans to complete a detailed design of the company by early January 2021, and for the reshaped firm to become fully operational by 1 July next year.
By Rowena Edwards
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Yara first-quarter gas consumption higher on year
Yara first-quarter gas consumption higher on year
London, 29 April (Argus) — Europe's largest fertiliser producer Yara's European gas consumption in the first quarter was up by 26pc on the year, but remained far lower than in the second half of last year. Norway-based Yara's gas consumption across Europe in January-March totalled 29.2 trillion Btu, well above the 23.1 trillion Btu a year earlier, but drastically down from 37.5 trillion Btu in the fourth quarter last year, the company's latest quarterly report shows. Yara did not report its European ammonia production for the first quarter, but the company's global output totalled 1.74mn t, up from 1.38mn t a year earlier. Yara's first-quarter European gas consumption fell from the preceding three months, despite its average European gas costs falling to $11.70/mn Btu from $13/mn Btu. The firm's European gas costs have declined sharply since peaking at $34.50/mn Btu in the third-quarter 2022, when European wholesale prices hit all-time highs ( see price graph ). Yara's quarterly spending on European gas supplies fell to $343mn in January-March, the lowest since at least summer 2021 when the company began reporting this data, and around one third the $1.08bn peak in April-June 2022. Yara's European gas consumption also fell despite a 37pc annual increase in total fertiliser deliveries in Europe . Lower curtailments, improved production economics and "volume catch-up" had supported output, Yara said. But while European deliveries improved on the year, they remained "below normal" — particularly for nitrates — and Yara sourced a larger share of its European deliveries from its global plants, the company's chief financial officer Thor Giaever said. Yara had hinted earlier this year its ammonia assets might run at 90pc or more of capacity as the company expected to boost production this year . But one explanation for the lower gas demand compared to the previous quarter is Yara may be maximising production at more efficient plants like Sluiskil in the Netherlands and Brunsbuttel in Germany, while ramping down less efficient plants, allowing the company to maintain or increase production while consuming less gas. Yara last year curtailed 19pc of its European ammonia capacity , turning towards greater imports of ammonia to replace the lower production. And that remains key to Yara's business plans , which the company said last week focused on "further strengthening operational resilience and flexibility". Argus assessed European ammonia production prices based on the TTF front-month price at roughly a $100/t discount to northwest European import prices in its last weekly assessment on 25 April, suggesting a still-significant financial incentive to produce ammonia domestically. The European fertiliser market remains under pressure by large volumes from Russia, meaning Europe has swapped an energy dependency on Russia for a food dependency, chief executive Svein Tore Holsether said, echoing previous statements . Comparing global assets Yara consumed 54.4 trillion Btu of gas globally in January-March, down from a multi-year high of 61.9 trillion Btu in October-December ( see consumption graph ). European consumption accounted for roughly 54pc of Yara's global gas demand in January-March, well down from 61pc in the previous quarter. And Yara spent $485mn on gas worldwide in January-March, 71pc for European supply, a lower proportion than at any other point since 2021. Yara's global average gas cost was $8.90/mn Btu in January-March, 24pc below its reported European cost. That discount has been a significant driver for Yara and others to increase production abroad rather than in Europe over the past two years. Yara forecasts its European gas costs at $9.70/mn Btu and $10.50/mn Btu in the second and third quarters of this year, respectively, holding well above its global average gas costs of $7.70/mn Btu and $8.40/mn Btu during those same periods. Globally, the firm aims to produce 8.6mn t of ammonia in 2025, significantly up from 7.8mn t in 2023, it said. By Brendan A'Hearn Yara European vs global gas costs $/MMBtu Yara European vs global gas consumption million MMBtu Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Service firms talk up long-term gas prospects
Service firms talk up long-term gas prospects
New York, 29 April (Argus) — Leading oil field service firms are bullish on the outlook for natural gas demand in coming years even though the fuel remains stuck in the doldrums for now, with US prices near pandemic lows amid oversupply after a mild winter. "This is the age of gas," Baker Hughes chief executive Lorenzo Simonelli says, adding that global demand for the power plant and heating fuel is due to climb by almost 20pc through 2040. "Gas is abundant, lower emission, low cost, and the speed to scale is unrivalled," he says. Halliburton also sees natural gas as the "next big leg of growth" in North America, driven by demand for LNG expansion projects, although its current plans do not envisage any comeback this year. Given a shrinking fracking fleet and lack of new equipment being built, the stage is set for an "incredibly tight market" in future, chief executive Jeff Miller says. A recovery in natural gas activity in the US may not happen until the end of this year or even 2025, Liberty Energy chief executive Chris Wright says. "Customers need to see that prices have firmed, that export volume demand actually is pulling upward at a meaningful rate," he says. On recent first-quarter earnings calls, service firms were upbeat about international growth prospects in the face of escalating geopolitical tensions in the Middle East. The backdrop remains one of growing demand for oil and gas and an "even deeper focus" on energy security, according to Olivier Le Peuch, chief executive of SLB, the world's biggest oil field service company. SLB, formerly known as Schlumberger, expects overseas growth momentum to make up for a slowdown in North America this year. "The relevance of oil and gas in the energy mix continues to support further investments in capacity expansion, particularly in the Middle East and in long-cycle projects across global offshore markets," Le Peuch says. But results in North America will be depressed by the combination of low gas prices, capital discipline and producer consolidation. International rescue Halliburton expects international revenue growth in the "low double-digits" for the full year, with some margin expansion given the tight market for equipment and labour. Steady activity levels are seen in North America after land completion activity bottomed out in the fourth quarter of 2023 and rebounded in the first quarter. "The world requires more energy, not less, and I'm more convinced than ever that oil and gas will fill a critical role in the global energy mix for decades to come," Miller says. The positive outlook is reinforced by customers' multi-year activity plans across markets and assets. Baker Hughes forecasts "high single-digit growth" when it comes to the outlook for international drilling and completion spending this year. But customer spending in North America is expected to fall in a "low to mid-single-digit range" when compared with 2023. "We continue to anticipate declining activity in the US gas basins, partially offsetting modest improvement in oil activity during the second half of the year," Simonelli says. Beyond 2024, upstream spending is seen growing further across international markets, albeit at a "more moderate" pace than seen in recent years, according to Baker Hughes. SLB paced a decline among oil service stocks at the end of January when state-controlled Saudi Aramco scrapped plans to increase crude output capacity to 13mn b/d from 12mn b/d. But Saudi Arabia has stepped up its plans to boost gas output, by 60pc by 2030. This new energy mix was not anticipated six months ago, but it will "not have a natural impact on our ambition for growth" in Saudi Arabia, Le Peuch says. And Saudi gas plans will require substantial investment in gas infrastructure, which is a "long-term net positive" for Baker Hughes, Simonelli says. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Production, patience driving Canada’s oil sands profits
Production, patience driving Canada’s oil sands profits
Calgary, 29 April (Argus) — Canadian oil sands operators enjoying firm profits on strong production are getting ready for a major boost when a new export pipeline to the Pacific coast goes into commercial service this week. The federally owned 590,000 b/d Trans Mountain Expansion (TMX) remains on track to start operations on 1 May, and the line has already started to bear fruit. More than 4mn bl of Canadian crude is being pushed into the C$34bn ($25bn) expansion for linefill, helping to work down inventory levels in Alberta while lifting local prices relative to international benchmarks, as intended. The largest four oil sands companies — Canadian Natural Resources (CNRL), Cenovus, Suncor, and Imperial Oil — are all shippers on the expansion. They closed 2023 with a new production record of 3.6mn b/d of oil equivalent (boe/d) combined in the fourth quarter, and are targeting further increases as they plan to fill the new pipeline. About 80pc of their output comes from their core oil sands businesses, with the balance from natural gas and offshore projects. The higher output compensated for a slight dip in prices, helping to push profits higher. First-quarter 2024 results are likely to be a similar story, but it is the second quarter when producers look ready to shine as prices climb to multi-month highs. A combined profit of C$26bn in 2023 was a stellar result for the big four oil sands operators, despite a 25pc decline from the record C$34bn set the previous year. Their massive projects are agnostic to daily price swings, instead focused on uptime, long-term fundamentals and capitalising on key step-changes such as the one TMX presents. Patience in the oil sands is key. TMX will cater largely to heavy crude producers, which saw diluted bitumen prices in Alberta rise only slightly quarter on quarter to $58/bl in the first quarter. But climbing global benchmarks in April and a shrinking heavy sour discount with the help of TMX linefill now has the outright price for the crude approaching $70/bl. This is above guidance given in 2024 corporate budgets, and far above oil sands operating costs that for some are as low as $12/bl. The TMX factor TMX will nearly triple the existing 300,000 b/d Trans Mountain system that connects oil-rich Alberta to the docks in Burnaby, British Columbia. The expansion was first conceived more than a decade ago with the intention of being operational by late-2017, but cost overruns and repeated delays put the project in jeopardy. Canadian producers that sought growth during that period of frustration are poised to take advantage of this new era of excess export capacity. CNRL, Cenovus and Suncor have been significant buyers in the oil sands in recent years, doubling down on the world's third-largest deposit of oil while many international companies fled amid regulatory uncertainty. The government itself enabled a foreign operator to leave Canada, buying the Trans Mountain system from Kinder Morgan in 2018. But as Prime Minister Justin Trudeau's Liberal party sees TMX to completion, and then the line's planned sale, it is also readying legislation towards something more on-brand for climate-concerned Ottawa: carbon capture. A carbon capture and storage (CCS) project spearheaded by Pathways Alliance — a consortium of the six largest oil sands producers — is awaiting federal and provincial help to push their proposal forward. Federal incentives are soon to become law, the Trudeau government said this month, with the expectation that tax credits will advance the massive C$16.5bn project and start to offset oil sands greenhouse gas emissions to meet net zero pledges for all parties involved. TMX represents a new era for Canadian crude producers, but so too does CCS, as it could attract even more investment into Alberta's oil sands region. By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
BP inks another LNG deal with Korea's Kogas: Correction
BP inks another LNG deal with Korea's Kogas: Correction
Corrects total volume of LNG supplied in paragraph 2 Singapore, 29 April (Argus) — BP has signed another long-term LNG sales and purchase agreement with South Korean state-owned importer Kogas, the former said today. BP will provide Kogas with up to 9.8mn t of LNG over 11 years from mid-2026 on a des basis. But other details regarding pricing and the origin of the contracted supplies were not available. This most recent deal is in addition to the existing long-term sales and purchase agreement between the two companies that was signed in 2022. Kogas on 22 April 2022 signed an 18-year LNG purchase agreement to buy 1.58mn t/yr of LNG from BP that will begin in 2025. Australian independent Woodside Energy and Kogas in February signed a sales and purchase deal for term supplies of LNG to South Korea. The deal for 500,000 t/yr on a des basis will start in 2026 and run for 10½ years. Kogas may be seeking more imported term supply as the firm has increased its downstream contractual supply deals. Kogas signed a series of deals to supply gas to subsidiaries of the country's state-controlled utility Kepco in December 2023. By Simone Tam Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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