Tag: Brent Crude

Fast forward five years, and all seems to have gone the wrong way. The mojo is certainly gone. Exxon is not only again the largest US oil company, but its market value nearly doubles its competitor. Worse, Exxon has entangled Chevron in a long arbitration battle that could derail a make-or-break $60-billion-plus deal. Wirth, long admired, is now questioned. Rivals whisper his job may be on the line.

Mike Wirth became the king of Big Oil on Oct. 7, 2020. That was the day the chief executive officer of Chevron Corp. elbowed out archival Exxon Mobil Corp. to become America’s largest oil corporation by market value.

Fast forward five years, and all seems to have gone the wrong way. The mojo is certainly gone. Exxon is not only again the largest US oil company, but its market value nearly doubles its competitor. Worse, Exxon has entangled Chevron in a long arbitration battle that could derail a make-or-break $60-billion-plus deal. Wirth, long admired, is now questioned. Rivals whisper his job may be on the line.

The 64-year-old American chemical engineer is on a charm offensive to prove naysayers wrong. “The portfolio is stronger than it’s been,” he tells me in an hour-long interview. “This is the comeback.”

The path to redemption isn’t easy, but having listened to Wirth’s arguments, as well as spoken to multiple shareholders, bankers and analysts over the last few weeks.

To be fair to Wirth, his company is far from suffering the existential crisis its critics claim. In the third quarter, it returned to shareholders a record high $7.7 billion via dividends and share buybacks. Its stock has recovered too: At close to $160 per share, Chevron is up more than 10 per cent over the last year. Speaking from his office on the outskirts of San Francisco, days before Chevron relocates its headquarters to Houston, Wirth painted a rosy outlook because, as he puts it, Chevron has promised investors to increase its free cash flow by 10 per cent each year. The target seems achievable; if it delivers, the mojo will return.

Speaking from his office on the outskirts of San Francisco, days before Chevron relocates its headquarters to Houston, Wirth painted a rosy outlook because, as he puts it, Chevron’s cash generation compared to its spending is at an “inflection” point… If oil prices stay above $70 a barrel, it should enjoy a cash bonanza from 2025 as several projects start pumping, allowing the company to move into harvest mode. Chevron has promised investors to increase its free cash flow by 10 per cent each year….The target seems achievable; if it delivers, the mojo will return.

Yet, the challenges abound. Wirth inherited a troubled legacy when he became CEO in 2018. Under his predecessor, John S. Watson, Chevron had become a byword for late and over-budget mega-projects. Capital spending jumped from less than $20 billion annually before 2010 to about $40 billion in 2013, 2014 and 2015. Watson famously justified the splurge with a new vision: $100-a-barrel was the new $20-a-barrel.

Wirth inherited a troubled legacy when he became CEO in 2018. Under his predecessor, John S. Watson, Chevron had become a byword for late and over-budget mega-projects. Capital spending jumped from less than $20 billion annually before 2010 to about $40 billion in 2013, 2014 and 2015. Watson famously justified the splurge with a new vision: $100-a-barrel was the new $20-a-barrel.

Saudi Arabia had other plans, however. In late 2014, the kingdom launched a price war to halt the expansion of the US shale industry. Oil prices cratered to less than $30 a barrel. Chevron was left hanging out to dry. Wirth slashed spending and told investors the old days wouldn’t come back. Some were skeptical, but he delivered. Little by little, shareholders regained confidence. Then, in 2019, Wirth attempted to buy rival Anadarko in a deal valued at $50 billion, including debt. But Occidental Petroleum Corp. counterbid at $57 billion with the help of Warren Buffett. Rather than start a bidding war, Wirth walked away, pocketing a $1 billion breakup fee. It was the move that consolidated his appeal on Wall Street: He put financial common sense above ego.

All that Wirth needed to do to remain Wall Street’s favorite was rinse and repeat: keep costs under control, deliver projects on time and meet oil production targets. “Repetition is reputation,” as veteran oil analyst Paul Sankey likes to put it.

But Chevron didn’t, and Wall Street was merciless. The first setback was the expansion of the Tengiz project in Kazakhstan, the company’s crown jewel. When announced in 2016, it was meant to cost $37 billion and see its first oil in 2022; now, now, the crude won’t flow until next year, and the cost has ballooned to over $45 billion. Wirth admits he dropped the ball, allowing a culture of “optimism” that overlook the challenges.

“We were not — and I was not — asking the right questions,” he says. “I was not in contact with the field team as frequently as I should have been.” For Wall Street, it was déjà vu of the years when spending went unchecked.

The second setback was in Chevron’s backyard — the Permian region that’s the epicenter of the US shale revolution. Wirth had set a lofty target of pumping one million barrels a day by 2027, but in 2022 and 2023, the company struggled. With hindsight, it was a minor wobble as production is now again on track. But, Chevron didn’t explain itself at the time, putting off some investors.

Yet these setbacks pale in comparison with the third: the ongoing acquisition of Hess Corp. for $60 billion, including debt. The deal, announced in 2023, is the boldest that Wirth has attempted and would give Chevron a stake in a prized series of oil fields off the coast of Guyana, the Latin American nation bordering Venezuela and Brazil. The problem? Exxon owns a large chunk of the very same oilfields and claims it has the right to bid for them first.

Exxon, Chevron and Hess tried to resolve their differences in private, but the case is now going into arbitration in June, with a ruling likely in July or August. For many in the industry, Exxon, by delaying the Chevron-Hess deal at least one year, has already won — even if it ultimately losses the arbitration.

Still, everyone faces risks, even Exxon, and as the arbitration approaches, I believe the incentive to reach an out-of-the-court deal increases. Wirth disagrees: “Why would you do something now that you shouldn’t get done earlier?” He may be ultimately right, but that’s of little help for shareholders now. Today, investors don’t know what they are buying in Chevron. Are they purchasing shares in a future Chevron-Hess? Are they buying into a Chevron that fails to buy Hess and rushes into a standalone Chevron that carries on without further deals?

All those options have pros and cons — but above all, they have uncertainty. If one believes that Wirth will prevail in arbitration, buying Chevron today is a no-brainer. But if he doesn’t, one must put a lot of faith that the CEO wouldn’t rush into an expensive M&A deal to offset the loss of Hess.

“The standalone Chevron story is very, very strong,” Wirth says. “So even in the case where the transaction doesn’t close, which we don’t believe is going to happen, I think our track record says we wouldn’t go out and just throw money at something.”
But it’s hard to see how Chevron wouldn’t search for an acquisition if it doesn’t get Hess, although Wirth can probably do it on his own terms and time, without overpaying. Without that extra something, investors would question the growth of Chevron beyond the next few years. The Permian is a great story, but production there is expected to plateau in 2027; Tengiz is now a superb narrative for 2025, 2026 and 2027, but as time goes, shareholders will start asking questions about the renewal of thof the oilfield’s contract, set for 2033. Buying Hess solves these questions, hence why it’s so important.

Wirth has a point when he insists that Chevron is a better company than naysayers portray. Above all, it’s a cash machine. Between 2011 and 2014, Chevron generated, on average, $3.9 billion in free cash flow per year with Brent crude averaging nearly $110 a barrel. Last year, Chevron produced five times more free cash flow — nearly $20 billion — despite Brent crude trading at $80 a barrel. With a leverage ratio around 12 per cent, which is likely to drop into the single digits in the fourth quarter thanks to asset sales, Chevron can take on debt to sustain dividends and buybacks if oil prices sag. In the past, the company has boosted iits leverage to 20 per cent to 25 per cent during down cycles. Funding payouts with debt is risky, however, so Chevron should consider lowering its buybacks if oil prices fall below $70 a barrel. The company is currently buying back its shares atat a pace of $17 billion annually, near the upper end of its $10 billion to $20 billion annual guidance.

That financial firepower, alongside Wirth’s reputation as an executive who would walk from a deal rather than overpay, is the best antidote to skeptical investors. Chevron is owning its mistakes, and that’s a first good step. Now, it needs to show it’s learned the lessons.

By: Javier Blas ,Bloomberg / 12 November, 2024.

Oil prices lost further ground in early trade on a stronger dollar and pessimism over Chinese demand growth.

Brent crude traded 1.4% lower to $72.86 a barrel, while WTI fell 1.6% to $69.26 a barrel.

The dollar was up 0.4% against a basket of major currencies ahead of key inflation data later this week, making oil cheaper. Prices are also pressured by growing concerns over demand trends in China after the top crude importer didn’t announce new stimulus measures, as well as easing supply risks in the U.S.

Meanwhile, “a Trump presidency is seen as relatively more bearish for energy markets,” ING analysts said in a note. “However, the key risk to this view is if President Trump chooses to strictly enforce sanctions against Iran.”

By Giulia Petroni, Dow Jones Newswires / Nov 11, 2024

Weak demand in China will lead to lower supply from the world’s top crude exporter, Saudi Arabia, to the world’s largest crude importer in December, trading sources told Reuters on Monday.

The drop in Saudi supply would come despite the fact that the Kingdom has reduced its official selling prices (OSPs) for crude loading in December for Asia.

December will see a second consecutive month of lower Saudi deliveries to China, estimated at a total of 36.5 million barrels. This would be down from 37.5 million barrels expected this month, and 46 million barrels in October, according to trade data compiled by Reuters.

The Saudi crude oil supply to China next month would also be the lowest monthly volume since July, as Chinese state-owned giants PetroChina, Sinopec, and Sinochem are expected to lift fewer cargoes from the Kingdom.

Aramco, the Saudi state giant, last week reduced the price of its crude that will be loading for Asia in December.

Saudi Arabia’s flagship crude grade, Arab Light, saw its OSP cut by $0.50 per barrel, to $1.70 a barrel above the Dubai/Oman benchmarks, from which Middle Eastern exporters price their crude for the Asian markets.

The Kingdom also slashed the OSPs of all its grades loading for Asia—Arab Extra Light, Super Light, Arab Medium, and Arab Heavy, although the reductions in the heavier grades were lower than those for the lighter crudes.

Chinese crude oil imports have been underwhelming this year, with October marking the sixth consecutive month in which cargo arrivals have lagged behind the imports in the same months of 2023, official Chinese data showed last week.

Reduced capacity at a PetroChina refinery and continued weak demand from China’s independent refiners, the so-called teapots, weighed on the imports into the world’s top crude importer in October.

Weaker-than-expected Chinese demand may have been the reason why the OPEC+ group delayed the beginning of the easing of its production cuts to January 2025, from December 2024, although the cartel and its allies did not give a specific reason for the decision.

By Tsvetana Paraskova for Oilprice.com / Nov 11, 2024

U.S. energy company Glenfarne Group LLC said on Monday it had selected construction contractor Kiewit to build its proposed Texas LNG export terminal in Brownsville, Texas.

The proposed terminal has the capacity to turn about 0.5 billion cubic feet per day (Bcf/d) of natural gas into 4 million tonnes per annum of liquefied natural gas.

Glenfarne said it would work with Kiewit to meet the requirements needed to achieve a final investment decision (FID).

The company was expected to begin construction by November 2024 and commercial operations by 2028. However, in May it asked federal energy regulators to give it until 2029 to put its plant into service.

Earlier this month, Glenfarne said it had already secured enough supply agreements in a volume sufficient for achieving an FID, including agreements with EQT Corp., Gunvor Group, and Macquarie Group.

By: Reuters , 11/4/2024

Global Partners LP is strengthening its operational capabilities and supply options in the Northeast with the acquisition of a liquid energy terminal in East Providence, R.I., from the ExxonMobil Oil Corp.

The terminal — which features 10 product tanks with 959,730-barrel shell capacity — serves as a strategic storage facility for various products, including gasoline, additives, distillates and ethanol. It includes a six-bay truck rack servicing the Rhode Island, northern Connecticut and southern Massachusetts markets, as well as a large dock with capabilities to accommodate long-range vessels.

The addition of gasoline infrastructure through the transaction will enable the partnership to optimize its large, active marketing and retail presence in the area. In addition to the terminal, Global Partners will acquire surplus vacant real estate parcels providing long-term opportunities for alternative uses as market dynamics evolve, the company stated.

“The additional operational capabilities and supply optionality, along with the potential for real estate development, further deliver our commitment to strategic growth by diversifying our portfolio and capitalizing on assets that leverage our integrated network,” Slifka added.

The latest acquisition builds upon the partnership’s strategy to enhance its assets of liquid energy terminals. Over the last year, Global Partners has invested more than $500 million to significantly expand its wholesale segment through the strategic acquisition of a combined 29 terminals from Motiva Enterprises and Gulf Oil, more than doubling the partnership’s storage capacity to 21.4 million barrels.

The terminals expanded the partnership’s geographic reach within New England, along the Eastern Seaboard and into Florida, the Gulf Coast and Texas, as Convenience Store News previously reported.

Waltham-based Global Partners operates or maintains dedicated storage at 54 liquid energy terminals — with connectivity to strategic rail, pipeline and marine assets — spanning from Maine to Florida and into the U.S. Gulf States. Through this extensive network, the company distributes gasoline, distillates, residual oil and renewable fuels to wholesalers, retailers and commercial customers. In addition, Global Partners owns, operates and/or supplies more than 1,700 retail locations across the Northeast states, the Mid-Atlantic and Texas.

By: Danielle Romano , csnews / 11/4/2024 .

Global tank storage operator Vopak has committed just a fraction of the $1 billion it allocated for energy transition projects by 2030 but expects investments to accelerate towards the end of the decade, CEO Dick Richelle said. 

The company has spent a little less than $100 million on the projects in the two years since it made the spending pledge, Richelle told Reuters in an interview.

“Although developments have slowed down, we still see that it kind of moved away from a big hype and dream to much more realism in building these new supply chains going forward,” he said.

Some of the factors that have slowed projects include a lack of government mandates and incentives, higher production costs for alternative fuels and rising construction capital expenditure, he added.

For example, Norway’s Equinor scrapped plans to export hydrogen to Germany because it is too expensive and there is insufficient demand and Repsol put on hold hydrogen projects in Spain due to an unfavourable regulatory environment.

“You need all of those parties at the same time to hold hands and basically jump to make sure that you can establish a whole supply chain,” Richelle said.

“I think that has been slow simply because of the fact that it’s either not clear what incentive you’re going to get at production, or it’s not clear what the mandate is and where you want to sell your product, or the incentive over there in order to import the product.”

Looking ahead, Vopak is focusing on infrastructure projects in four areas of energy transition: biofuels and feedstocks such as sustainable aviation fuel and renewable diesel; hydrogen and hydrogen carriers such as ammonia; carbon dioxide (CO2) value and supply chains; and battery storage.

Vopak plans to capture a bigger share of the biofuels market by converting existing storage tanks for bio-bunker fuel blending in Rotterdam and Singapore, and in the use of biofuels as raw material for fuel and petrochemical production in India, Brazil and Los Angeles, Richelle said.

For ammonia, Vopak is targeting big production centres such as the Middle East and the U.S., and end-markets like Antwerp, Rotterdam, Singapore and South Korea where it operates terminals, he added. The company said in July it had opened an office in Japan to explore opportunities there.

Vopak also has a strong presence in China, a competitive producer of green methanol, where it can facilitate the production and distribution of the alternative fuel, Richelle said.

In carbon storage, the company is working on a project in Rotterdam and has an initial agreement with Australia’s Northern Territory to develop a CO2 import terminal.

Vopak is also making early steps in battery storage investments, having announced a project in Texas earlier this year, Richelle said.

“We see that there’s potentially an important role for Vopak to play as the world moves from the storage of molecules to electrons,” he said.

Story by Florence Tan and Jeslyn Lerh, November 4, 2024

Exxon Mobil (XOM.N), opens new tab on Friday edged past Wall Street’s third quarter profit estimate, boosted by strong oil output in its first full quarter that includes volumes from U.S. shale producer Pioneer Natural Resources.

Oil industry earnings have been squeezed this year by slowing demand and weak margins on gasoline and diesel. But Exxon’s year-over-year profit fell 5%, a much smaller drop than at rivals BP (BP.L), opens new tab and TotalEnergies (TTEF.PA), opens new tab, which posted sharply lower quarterly results.

The top U.S. oil producer reported income of $8.61 billion, down from $9.07 billion a year ago. Its $1.92 per share profit topped Wall Street’s outlook of $1.88 per share, on higher oil and gas production and spending constraints.

“We had a number of production records” in the quarter, said finance chief Kathryn Mikells, citing an increase of about 25% year-on-year in oil and gas output to 4.6 million barrels of oil equivalent per day (boepd).

Exxon earlier this month flagged operating profit had likely decreased, leading Wall Street analysts to shave their quarterly per share earnings forecast by nearly a dime.

RECORD PRODUCTION

Exxon’s results reflected the first full quarter of production following its acquisition in May of Pioneer Natural Resources. The acquisition has already boosted the company’s cash flow, Mikells told analysts on a post-earnings call.

The $60 billion deal drove production in Permian basin, the top U.S. shale field, to nearly 1.4 million boepd, helping overcome a 17% decline in average oil prices in the quarter ended Sept. 30.

Volume growth from the Pioneer acquisition and its lucrative Guyana consortium added almost $3 billion to earnings in the first nine months of this year, Mikells said on a post-earnings conference call. Compared with the second-quarter, Pioneer output averaged slightly lower, she noted.

Despite the record, output from the Permian was still below Barclays’ estimate of 1.5 million boepd, and Exxon’s earnings from U.S. oil and gas production were also softer than forecast, the bank’s analyst Betty Jiang said.

No. 2 U.S. oil producer Chevron (CVX.N), opens new tab, whose plans to acquire Hess Corp have locked the two rivals in a bitter arbitration battle over Guyana, beat Wall Street estimates by a nine-cent margin compared with Exxon’s four-cent beat.

That helped Chevron shares gain more than 3% on Friday, while Exxon gave up more than 2% of premarket gains to trade about flat by noon ET (1600 GMT).

Exxon expects full year output to average about 4.3 million boepd, including eight months of Pioneer’s contributions.

The company plans to issue a revised production forecast next month. It noted that scheduled well maintenance will lower output by about 30,000 boepd in the fourth quarter.

The market is worried about oil supply outrunning demand next year, with exporter group OPEC reviewing plans to add 180,000 barrels per day (bpd) of additional oil supply from December. Oil prices slumped over the summer and remain about 12% below June’s average.

REFINING SLUMPS, CHEMICALS GROW

Exxon disclosed it raised its quarterly dividend by 4% after generating free cash flow of $11.3 billion, well above analysts’ estimates. Rivals Saudi Aramco (2223.SE), opens new tab and Chevron have had to borrow this year to cover shareholder returns after boosting dividends and buybacks to attract investors.

Exxon’s earnings from producing gasoline and diesel in the quarter were $1.31 billion, down from $2.44 billion year-on-year as weak margins and a nearly month-long outage at its 251,800-bpd Illinois refinery hit segment results.

Lower planned maintenance at other plants, along with gains on derivatives, helped offset weak industry-wide refining margins and the impact of the Illinois outage, Exxon said.

“Refining margins definitely came down in the quarter. If you look at overall results for the refining business, we feel pretty good,” said CFO Mikells. Per unit refining margins since 2019 have about doubled on a constant margin basis, she said.

Profits from Exxon’s chemical business, which has been pressured by industry overcapacity for two years, rose in the quarter to $893 million, compared with $249 million a year ago, on a slight increase in margins.

By Shariq Khan and Gary Mcwilliams / November 4, 2024

Crude oil inventories in the United rose by 1.643 million barrels for the week ending October 18, according to The American Petroleum Institute (API). Analysts had expected a build of 700,000 barrels.

For the week prior, the API reported a 1.58-million-barrel draw in crude inventories.

So far this year, crude oil inventories have slumped by nearly 6 million barrels since the beginning of the year, according to API data.

On Tuesday, the Department of Energy (DoE) reported that crude oil inventories in the Strategic Petroleum Reserve (SPR) rose by 0.7 million barrels as of October 18. SPR inventories are now at 384.6 million barrels, a figure that reflects an increase of about 37 million from its multi-decade low last summer, yet 250 million down from when President Biden took office.

At 4:30 pm ET, Brent crude was trading up $1.44 (+1.94%) on the day at $75.73—up roughly $1.30 per barrel loss from last Wednesday. The U.S. benchmark WTI was also trading up on the day by $1.68 (+2.38%) at $72.24—a $1.60 per barrel gain over last Wednesday’s level.

Gasoline inventories fell this week by 2.019 million barrels, on top of last week’s 5.926-million-barrel decrease. As of last week, gasoline inventories are 4% below the five-year average for this time of year, according to the latest EIA data.

Distillate inventories fell by 1.478 million barrels, on top of last week’s 2.672-million-barrel decrease. Distillates were already about 10% below the five-year average as of the week ending October 11, the latest EIA data shows.

Cushing inventories—the benchmark crude stored and traded at the key delivery point for U.S. futures contracts in Cushing, Oklahoma—fell by 216,000 barrels, according to API data, compared to the 410,000-barrel build of the previous week.

By Julianne Geiger, Oilprice.com / Oct 22, 2024

The EU’s natural gas storage is already at 95% full, data from Gas Infrastructure Europe show, after the bloc reached in August its target to have 90% full storage well ahead of its self-imposed binding deadline, November 1.

In the middle of August, the EU reached its target of filling gas storage facilities to 90% of capacity 10 weeks ahead of the 1 November deadline. This achievement is on par with last year, when EU countries reached the 90% target on August 18, the European Commission said two months ago.

Now the EU storage is 95% full as the heating season begins. The storage level this year is slightly below last year’s level, but above the 2017-2021 average and the 2022 storage levels, according to the data.

Major economies and gas markets such as Germany and Italy have their storage at more than 97% full, while Austria, still dependent on Russian pipeline gas flows, had its gas storage at 93.73% full as of this weekend.

Yet, gas in storage wouldn’t cover Europe’s needs for winter, and the volumes of gas in storage are slightly lower compared to this time last year, mostly due to lower numbers of incoming LNG cargoes.

As Europe prepares for the winter amid uncertainty about the remaining Russian pipeline gas flows, LNG imports have been rising in recent weeks.

Now that more cargoes have headed to Europe, supply concerns could ease, but prices are set to increase with rising seasonal demand and competition between Europe and Asia for LNG supply.

In addition, the conflict in the Middle East and fears of it spreading through the region are pushing up Europe’s natural gas prices early on Monday.

Dutch TTF Natural Gas Futures, the benchmark for Europe’s gas trading, were up by 2% to $43.42 (40.00 euros) per megawatt-hour (MWh) at 12:42 p.m. in Amsterdam on Monday.

By Charles Kennedy, Oilprice.com / October 21, 2024

China guzzled roughly 16.5 million b/d of the world’s oil supply in 2023, all liquids included. As the world’s second-largest oil consumer, accounting for about 16% of global demand, a peak or plateau in its refined oil product demand is crucial to the oil market. The timing of the peak and the pace of oil demand decline from there on will affect global oil balances and, consequently, oil prices.

“With a total oil demand tripling that of India’s, the world’s third-largest oil consuming nation, China is the only major developing country that is likely to see demand of gasoline and gasoil/diesel to reach a plateau at present or in the near future,” said Kang Wu, global head of oil demand research at S&P Global Commodity Insights. “While oil demand in nearly all developed countries has peaked, the vast majority of developing countries other than China will see their oil demand continue to grow in the foreseeable future.”

“As such, China is a decisive force in determining if and when the global oil demand will peak,” Wu added.

Analysts have varying views on the year when China’s oil demand will peak, but most of them agree the decline will not be so dramatic as to trigger a sharp downturn in global oil demand.

Commodity Insights projects China’s total refined product demand, excluding direct crude burn and all NGLs, will peak in 2027 at 16.4 million b/d. It consumed 15.5 million b/d in 2023. Global refined product demand is forecast to peak in 2028 at 91.5 million b/d, compared with 88.4 million b/d demand in 2023.

However, China’s oil demand growth in the second quarter of 2024 – merely 16 months after reopening from pandemic-related restrictions – has been slower than expected, with a year-on-year reduction in crude throughput. The combination of rapid growth in the displacement of road transportation fuels, muted demand from construction and manufacturing sectors, and extreme weather disruptions hit consumption.

The average utilization of independent refineries in China’s Shandong province fell to 52% in June 2024, the lowest level since March 2020, when the country’s oil demand was slowly recovering from the pandemic outbreak, data from local information provider JLC showed. China’s independent refineries are swing suppliers and their activity directly reflects the country’s oil demand.

Gasoil, the largest component of China’s oil barrel, accounting for about 22% or 3.8 million b/d of the country’s refined product demand, either already has or is close to reaching peak as growing sales of LNG-fueled heavy-duty trucks displace conventional diesel-powered trucks, analysts said.

Commodity Insights expects China’s gasoil demand to peak in 2027 at slightly over 4.0 million b/d. The International Energy Agency (IEA) estimates the demand to grow by 1.5% and 3.1% in 2024 and 2025, respectively, according to its monthly Oil Market Report dated July 11, while a few China-based analysts told Commodity Insights that gasoil demand has already peaked.

State-owned PetroChina’s Planning & Engineering Institute estimated China’s gasoil demand peaked in 2023 and will see a 5% year-on-year decline in 2024 amid sales of LNG-fueled heavy-duty trucks jumping more than 120% and displacing about 612,000 b/d gasoil this year.

CPPEI estimated gasoline demand had also peaked in 2023 at 155 million metric tons per year, or 3.6 million b/d, and has started to decline this year due to the rising proportion of new energy vehicles (NEV) and higher-efficiency internal combustion engine vehicles on the road.

Commodity Insights expects China’s gasoline demand will peak in 2025 at 3.8 million b/d. The IEA projects demand of the fuel to peak at 3.66 million b/d in 2024 and start to fall by 2.3% in 2025. NEV sales accounted for 43.8% of total vehicle sales in July — an all-time high.

January to July sales of battery electric vehicles and plug-in hybrid electric vehicles jumped 31.1% year-on-year, while ICE vehicle sales declined 6.5%, according to data from the China Association of Automobile Manufacturers. Meanwhile, new ICE vehicles are estimated to displace about 2%-3% of gasoline consumption due to improved energy efficiency, a senior refining economist with Sinopec said.

The peaking of China’s gasoline and gasoil demand is decisive in indicating the overall trend in China’s oil demand. Demand for other transportation fuels, led by jet fuel and fuel oil, is expected to continue rising but they account for a smaller proportion of China’s overall oil demand.

It should be noted, however, that when it comes to oil liquids as a whole, including petrochemical feedstocks such as LPG and ethane, it will take a few more years before China’s demand stops growing.

A later peak for gasoil demand, based on some analyst projections, would be mainly due to a more optimistic expectation in the development of China’s construction and manufacturing sectors, information collected by Commodity Insights showed.

Shift to petrochemicals

An earlier-than-expected peak for refined products — estimated mainly by research arms connected with China’s state-run oil companies — would lead to a decline in the country’s crude imports until demand surges for petrochemical products.

Market sources said the demand wave of petrochemical products is unlikely to happen until 2027. Bracing for a demand peak in refined oil products, most refineries in China, whether state-owned or independent, have been heavily investing in facilities to shift to petrochemical production.

However, trade sources in the petrochemicals sector said that China’s ongoing property market crisis, coupled with the economic slowdown, will continue discouraging demand for petrochemical products in the foreseeable future. “It will take a few years for the petrochemical industry to recover from the recession cycle,” the senior refining economist with Sinopec said.

China’s January-July crude imports have fallen nearly 3% year on year, official customs data showed, due to slow demand for refined and petrochemical products. On the other hand, domestic crude output rose 1.6% to 4.3 million b/d in the same period.

Despite the year-on-year decline, crude imports so far in 2024 remain the second highest in history – slightly above the third highest of 10.70 million b/d seen in the same period of 2021, according to customs data.

Medium sour crudes remain in favor

China’s appetite for medium sour crudes is unlikely to change for at least the next five years due to the configuration of Chinese refineries and refining economics, the senior refining economist with Sinopec said. API and sulfur content of the crudes that China imports averaged at 30.5 and 1.57%, respectively, as of June, almost flat to the 30.4 and 1.48% levels seen in 2017.

“There were some up and down between 2017 and 2024, but the changes are more related to price movements of different grades of crude rather than refinery configuration,” Mengbi Yao, a senior research analyst with Commodity Insights said.

Most of China’s refineries are designed to process medium sour crudes, including the new private mega plants and the ones built by Sinopec and PetroChina. Refineries that can process cheaper heavy, sour barrels follow, led by PetroChina’s new Guangdong Petrochemical, as well as the independent refineries in Shandong province.

The Middle East remains China’s top crude supplier by region, with its market share steady at 54.2% in H1 from 54.4% in the same period of 2023, Commodity Insights estimates. The configuration of China’s refining sector has encouraged Saudi Aramco, the world’s top crude producer, to invest in China’s integrated refineries. Aramco has a 30% interest in a planned integrated refinery and petrochemicals complex in Panjin in northeast China.

In March 2023, Aramco acquired a 10% interest in China’s Rongsheng Petrochemical. As of July, it has been in talks with Shenghong Petrochemical and Hengli Petrochemical for potential investments. Saudi Aramco is China’s biggest crude supplier. Its Arab Heavy (API 27.7, 2.87% sulfur) coupled with Arab Medium (API 30.2, 2.59% sulfur) crudes account for more than 63% of the Middle East crudes supplied to China, S&P Global Commodities at Sea data showed.

Meanwhile, most of the brownfield refineries are shifting production from oil products to petrochemical products by adopting the route of naphtha/LPG to ethylene to extend the value-chain, a Beijing-based analyst said.

“Generally speaking, the existing refineries will stick to the most competitive crudes, which are the medium and light grades from the oil-rich Middle East, North Africa, Norway and Guyana,” the Sinopec economist said, adding that the profitability from processing these grades was better due to their lighter yields, although the heavy barrels are cheaper.

“But in the future, when oil product demand slumps and aging refineries are phased out, light feedstocks will be in favor, led with NGL, LPG and followed by light crudes for directly cracking into ethylene, than the conventional route of refining light, medium crudes into ethylene as well as oil products,” the Sinopec economist added.

By: Oceana Zhou / 14 Oct 2024.