Big Oil Saw Record $199Bn Profits In 2022 But 2023 Will Be Different

ExxonMobil, Chevron, Shell, TotalEnergies, and BP reaped almost $200 billion collectively last year but fears of an economic slowdown, plunging natural gas prices, cost inflation and uncertainty over China’s re-opening are dimming the outlook for 2023.

The five companies are expected to report $198.7 billion in combined 2022 profit in the coming days, 50% higher than the previous annual record set more than a decade ago, according to data compiled by Bloomberg.

The tsunami of cash generated by the group over the past 12 months means the industry can sustain dividend increases and share buybacks, analysts said. Crucially for shareholders, management teams held off on spending increases as commodities boomed, in stark contrast with previous cycles.

Instead, they opted to repay debt and swell investor returns: Chevron stunned shareholders with a $75 billion stock-repurchase announcement on Wednesday — five times the company’s current annual outlay for buybacks.

“Commodity prices are down across the board relative to record 2022 levels, but it still looks like it’s going to be a very strong year,” said Kim Fustier, head of European oil and gas research at HSBC Holdings Plc. “It could very well be the second-best year in history for overall distributions and share buybacks.”

Fourth-quarter earnings, while one of the three highest on record, will likely be reduced by lower oil and gas prices. Guidance from Exxon and Shell suggests refining margins held up more than expected. Chevron is scheduled to kick off Big Oil earnings season at 6:15 a.m. New York time on Jan. 27.

While the pullback in energy prices has been sharp — crude and gas are lower now than when Russia invaded Ukraine in late February — it may help put the global economy and energy companies on a firmer long-term trajectory. Lower energy costs are helping take some of the sting out of inflation, easing pressure on central banks to carry on raising interest rates.

Across the board, the biggest oil explorers are focused on funneling record profits back to shareholders while keeping a check on spending. That strategy has provoked political attacks from Brussels to Washington DC by politicians wanting more supply to bring down prices.

Shares of the five supermajors are up at least 18% since Russia’s invasion despite an 11% drop in the price of crude. The top ten performers in the S&P 500 last year were all energy companies, with Exxon advancing 80% for its best annual performance on record. Oil companies now generate about 10% of the index’s earnings, despite making up just 5% of its market value, according to data compiled by Bloomberg.

“Investors are attracted to a lot of the characteristics this sector has to offer now,” said Jeff Wyll, a senior analyst at Neuberger Berman Group LLC, which manages about $400 billion. “It was trying to be a growth sector and that failed. It reinvented itself as a cash distribution and yield play, which is attractive in this environment.”

Key to the oil majors’ fortunes is whether they can stick to shareholder-return pledges made last year during the months-long run up in commodity prices.

“I expect them to maintain those shareholder returns,” said Noah Barrett, lead energy analyst at Janus Henderson, which manages about $275 billion. “The base dividends are incredibly safe at almost any oil price, balance sheets are in good shape and I expect them to continue buying back shares.”

Investors are also keen to hear executives sticking to the mantra of capital discipline. It was the huge growth in spending over much of the last decade that eroded shareholder returns and left the sector vulnerable to oil crashes in 2016 and 2020.

“There is still an aversion to big capital expenditure increases, period,” Wyll said. “The problem the sector got into in the past is doing too many megaprojects at one time. Now it’s much more focused.”

So far that discipline appears to be holding. Exxon and Chevron both raised spending targets for this year but the increases were driven largely by inflation rather than ramping up long-term growth projects. Despite a 500% increase in oil prices from early 2020 to mid-2022, global oil and gas capital spending fell in real terms, Goldman Sachs Group Inc. said in a Jan. 9 note.

One crucial question for executives this earnings season is how much they’re reserving for European windfall-profit taxes. Exxon estimated a $2 billion charge but is pursuing legal action. Shell says its 2022 bill may total $2.4 billion.

Earlier this month, Exxon indicated that fourth-quarter earnings took a hit of about $3.7 billion from weaker oil and gas prices compared with the previous quarter, but analysts noted that refining margins were much stronger than expected. The US oil giant reports on Jan. 31.

Shell, whose newly appointed Chief Executive Officer Wael Sawan will host his first earnings call, also noted stronger refining and pointed to a rebound in gas trading. TotalEnergies pointed to similar trends in a Jan. 17 statement.

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Texas O&G Sector Closes 2022 With Continued Employment Growth

Texas Independent Producers and Royalty Owners Association (TIPRO) has noted that oil and gas jobs in Texas continued growth in December to close out 2022.

According to TIPRO’s analysis, direct Texas upstream employment for December 2022 totaled 211,200, an increase of 1,300 jobs from November employment numbers, subject to revisions. Texas upstream employment in December 2022 represented the addition of 36,100 positions compared to December 2021, including an increase of 7,000 jobs in oil and natural gas extraction, and 29,100 jobs in the services sector. The average monthly gain in Texas upstream employment last year was 3,127.

TIPRO’s new employment data also indicated a significant rise in job postings for the upstream, midstream, and downstream industries for the month of December. According to the association, there were 14,482 active unique jobs postings for the Texas oil and natural gas industry in December, including 6,953 new job postings added in the month by companies.

Among the 14 specific industry sectors TIPRO uses to define the Texas oil and natural gas industry, Support Activities for Oil and Gas Operations continued to lead in the rankings for unique job listings in December with 4,526 postings, followed by Crude Petroleum Extraction (1,982), and Petroleum Refineries (1,418). The leading three cities by total unique oil and natural gas job postings were Houston (5,688), Midland (1,217), and Odessa (677), TIPRO said.

The top three companies ranked by unique job postings in December were John Wood Group with 820 positions, Baker Hughes (816), and KBR (576), according to TIPRO. Of the top ten companies listed by unique job postings last month, six companies were in the services sector, followed by two companies in oil and natural gas extraction and two midstream companies.

Top posted industry occupations for December included heavy tractor-trailer truck drivers (604), managers (414), and maintenance and repair workers (334). Top qualifications for unique job postings included Commercial Driver’s License (492), CDL Class A License (427), and Master of Business Administration (230). TIPRO reports that 44 percent of unique job postings required a bachelor’s degree, 34 percent a high school diploma or GED, and 23 percent had no education requirement listed as part of the criteria.

There were 1,758 advertised salary observations, or 12 percent of total oil and natural gas job postings, with a median salary of $52,200. Based on TIPRO’s new full year analysis for 2022, the average annual wage for the Texas oil and natural gas industry was $139,000, with average wages for the Texas upstream sector exceeding $145,000 last year.

When further examining the economic impact of the sector, TIPRO says direct Gross Regional Product (GRP), which is essentially Gross Domestic Product (GDP) for a region of study, for the Texas oil and natural gas industry was $315 billion in 2022, representing 14 percent of the state economy. Texas upstream industry direct GRP exceeded $157 billion last year. TIPRO says indirect employment tied to the Texas oil and natural gas industry also increased in 2022. When calculating direct, indirect, and induced employment for the upstream sector, for every position in Crude Petroleum Extraction, eight jobs are created in other industries, followed by Natural Gas Extraction (seven jobs), Drilling Oil and Gas Wells (two jobs), and Support Activities for Oil and Gas Operations (two jobs).

TIPRO also highlights recent data released from the Texas comptroller’s office showing production taxes paid by the oil and natural gas industry to the state of Texas generated $887 million in tax revenue in December. According to the comptroller’s data, in December, Texas oil producers paid $516 million in production taxes, up 15 percent from December 2021. Natural gas producers, meanwhile, last month also paid $371 million in state taxes.

Additionally, TIPRO reports that oil and gas production is on track to continue to rise in the months to come. Oil output in the Permian Basin is forecasted to grow by 30,000 barrels per day (bpd) to hit a record 5.635 million bpd in February, according to the U.S. Energy Information Administration (EIA). In the Eagle Ford Shale in South Texas, oil output will also go up next month to total 1.213 million bpd. Overall, U.S. crude oil production is expected to go up by 76,000 bpd and will top 9.375 million bpd in February, projects the EIA. Natural gas production in the Permian Basin will also rise by 109 million cubic feet per day (Mmcf/D) and will hit record highs in January at 21.72 billion cubic feet per day (bcf/d). Natural gas output in the Eagle Ford Shale is also forecasted to reach 7.4 bcf/d in February, up 46 Mmcf/d from projected January levels. Altogether, EIA forecasts natural gas production in the United States to grow to 96.656 bcf/d in February.

“The oil and natural gas industry continues to have a tremendous impact on our state economy, providing high paying jobs and billions of dollars annually in taxes to support infrastructure investments, education and other essential services. We look forward to working with policymakers during the 88th Texas Legislative Session to fund programs that will help drive further growth in our sector for the benefit of our state, including road repair and maintenance in energy producing areas, seismicity research and produced water pilot projects,” said Ed Longanecker, president of TIPRO.

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Will Venezuela Make an Oil Market Comeback in 2023?

Venezuela will not be making a big comeback in the oil market this year.

That’s what FGE thinks, according to Francisco Gonçalves, a senior analyst and energy economist at the company, who noted that “without further sanctions relief, we expect Venezuela’s production gains in 2023 will be limited”.

“Chevron joint venture production aside, Venezuela’s output for most of 2022 was stuck at around 650,000 barrels per day – albeit some 150,000 barrels per day higher year on year due mainly to more frequent imports of Iranian condensate – showing that the country has limited capacity for production growth,” Gonçalves told Rigzone.

“With regards to the output from Chevron’s four Venezuelan joint ventures over the next months, growth is likely to be minimal, given Chevron has said it is not planning on making any significant investment there in the short term,” he added.

Although the three main JVs could “in theory” produce around 200,000 barrels per day, compared to around 50,000 barrels per day in November 2022, the partners would need to make “big investments” over the next two to three years to ramp-up their production by another 80-100,000 barrels per day overall, according to the senior analyst.

“Even if there are some small synergies – e.g., the new licence allows Chevron to use imported diluent at its Venezuelan JVs, therefore freeing PDVSA to use up Iranian condensate for its other non-Chevron heavy oil ventures – we would highlight the various problems with the country’s ageing storage and offloading infrastructure which have and will most likely to continue hampering any further sustained recovery in Venezuelan oil production and/or exports,” Gonçalves said.

“Therefore, we could see a potential boost to Venezuela’s output, but by just 50,000 barrels per day by 1H 2023 and not much thereafter,” Gonçalves added.

Offering his opinion, Vikas Dwivedi, a Global Oil & Gas Strategist at Macquarie Group, told Rigzone that Venezuela is unlikely to make a “significant” comeback in 2023.

“The political gap is still too large for a full normalization of Venezuela’s ability to export their full volumes,” Dwivedi said.

“Even more importantly, the mechanical gap is probably even larger as the Venezuelan oil industry would need significant upgrades and repairs to ramp up production. Finally, if the oil market remains oversupplied for most of 2023 as we expect, the U.S. and other countries will be less motivated to work with Venezuela to increase their oil production,” Dwivedi added.

Macquarie Group told Rigzone that it is expecting a modest production increase from Venezuela this year – “on the order of a ~75,000 barrel per day increase for the full-year, rising through the year”.

Paul Horsnell, the head of commodities research at Standard Chartered Bank, told Rigzone that he thinks any output comeback for the country will likely be limited.

“Were sanctions to be significantly eased immediately, [it] would put the potential upside this year at 250-300,000 barrels per day, i.e. taking crude output to 900-950,000 barrels per day. That comes from fixing some of the immediate and most obvious problems and easing a few bottlenecks,” Horsnell said.

“Beyond that, the timescale for a return to, say, two million barrels per day is likely to be long, perhaps three to five years, and returning to the three million barrel per day of crude oil hit in the late-90s is completely off the table with the current structure of the industry and petroleum laws,” he added.

Horsnell noted that, in the mid-1990s, PdVSA talked of getting to five million barrels per day.

“The trouble was that they tried to get there by de facto operating independently of the Venezuelan government, and they provoked the rest of OPEC into a price war that was not called off until well after the Acción Democrática government had been voted out and President Chavez voted in,” he said.

“The scope for such aggressive production planning to happen again is considerably less now, but Venezuela’s experience is perhaps an object lesson in the dangers of a national oil company acting as a state within a state, and it explains why the regulatory re-opening of the Venezuelan oil sector will likely be fairly cautious regardless of who is in power,” Horsnell added.

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Ten Factors That Will Shape Offshore Wind In 2023

Intelatus Global Partners has looked at ten factors that will shape the offshore wind sector in 2023.

The sector is forecast to grow to 240 GW by 2030 and over 410 GW by 2035. Philip Lewis, a Director of Research at Intelatus, said that the sunny outlook for offshore wind must be balanced with some building dark clouds. He also compiled a list of factors influencing the sector in the new year.

1. Solid foundations: Optimism for the supply chain is founded on declared and inferred offshore wind deployment targets by a growing number of countries of over 400 GW, driven by energy transition and energy security policies.

2. New kids on the block: Offshore wind activity is expected to remain strong in all established markets – China, the UK, the European Union, and Taiwan. Commercial-scale wind farms will advance in the US, new European Union markets (Greece, Ireland, Italy, Poland and the Baltics, Portugal, Spain, etc.), Japan, and South Korea. Governments in Australia, India, the Philippines, Canada, Brazil, and Columbia will all take steps to advance offshore wind project permitting.

3. P2X is a game changer: Power-to-X in offshore wind terms means converting electrons to moveable and storable molecules. Initially producing green hydrogen, the electrons will be converted to a range of hydrogen-based energy carriers such as methanol and hydrogen for use in the industrial, residential, and transportation segments. Offshore wind-to-hydrogen production is moving from demonstration to commercial-scale projects within this decade. P2X is the driver for zero-subsidy wind farms, initially in northwest Europe and expanding further in the future.

4. Shifting foundations: The overall foundations for growth are positive, but what type of foundations will be deployed? Bottom fixed (mainly monopiles but also jackets and gravity bases) will dominate on projects installed within this decade, but 2023 will see an increased focus on the development of commercial-scale floating wind farms, which will come on stream at the very earliest at the end of this decade but mainly after 2030.

Floating wind drives different manufacturing supply chain opportunities and challenges to bottom-fixed projects. We are focusing on a potential shortage of large AHTSs, offshore construction vessels with suitable cranes and deck space and crew. The shortage will become a global phenomenon accentuated by local content requirements.

5. The impacts of inflation: Inflation and supply chain disruptions will result in delays and possibly cancellations. Several developers have issued project warnings and are seeking to balance rising costs with power offtake commitments.

6. Supply chain restructuring: The three traditional international turbine OEMs (Siemens, Vestas, and GE) struggle to make money as they continue developing ever-larger turbines. These larger turbines drive bigger foundations, power cables, and installation vessels, all requiring supply chain investments…and for the supply chain to make suitable returns on investments.

7. The expansion of the Chinese OEMs: As the Chinese market settles down after an exceptional 2021, Chinese turbine OEMs and other suppliers are looking to export to overseas markets. With large new turbines being offered, one can expect the big three international players to face stiff price competition in their core markets.

8. Vessel (and other supply chain) shortages: With the evolving technical, client, and local content drivers, how many companies will invest in new vessels without long-term commitments? Outside of some established players, the answer is “relatively few.” The key driver for construction or support vessel investment is project commitments coupled with developer financial investment decisions. Delays in vessel investment in several key markets will pose a problem from the middle of the decade in delivering forecast capacity.

9. Vessels are evolving, but many questions remain unanswered: Vessel operators understand that they need to decarbonize, but what is the solution to future-proof a vessel? Will it be biofuels, hydrogen-based fuels such as methanol, ammonia, or other hydrogen carriers? How to convert the energy carriers – multi-fuel internal combustion engines or fuel cells? What about battery-based hybrid vessels or even fully electric for SOVs and CTVs? How to secure “green” fuel or electricity supply? So many questions with no firm consensus. The answer will be an individual choice based on the availability of energy carriers.

How to secure a “green” fuel or electricity supply? So many questions with no firm consensus. The answer will be an individual choice based on the availability of energy carriers.

10. More local content: Governments want a return on their investment in offshore wind in terms of local employment. We anticipate increasing local content barriers in the U.S., Taiwanese, Japanese, and South Korean markets. In some markets, like the United States, local content is established at a local and state level in addition to federal policies. Local restrictions will create barriers for developers and may result in project delays and cancellations. The established European market’s open trade framework will support ongoing cross-border activity and supply chain confidence.

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Oil Rollercoasters In Holiday Shortened Trading Week

(The views and opinions expressed in this article are those of the attributed sources and do not necessarily reflect the position of Rigzone or the author.)

In this week’s edition of oil and gas industry hits and misses, one of Rigzone’s regular market watchers looks at this week’s oil price moves, the Covid-19 situation in China, cold fronts in the U.S. and more. Read on for more detail.

Rigzone: What were some market expectations that actually occurred during the past week – and which expectations did not?

Tom Seng, Director – School of Energy Economics, Policy, and Commerce, University of Tulsa’s Collins College of Business: In the holiday-shortened trading week, oil prices peaked early but fell later as concerns over the Covid outbreaks in China coupled with an unexpected increase in inventories sent them lower week-on-week. After trading near $81.20 per barrel, WTI fell to below the $77 mark at one point only to rebound to just under $79 per barrel. Meanwhile, Brent’s high was $85.60 per barrel, falling to near $81.25 then rising to over $82 per barrel. Covid-19 continues to spread throughout China with reports of overcrowded hospitals and crematoriums. Supply chain issues are emerging again as the impact of the virus on China’s economy is having ripple effects throughout the globe. Despite what appears to be a dire situation, China has said it will open its country up to international travelers next month. Russia’s ban on selling oil to countries which have imposed the $60 per barrel price cap appears to have little impact on prices thus far. India, China and Turkey will still provide outlets for the Urals as those countries are not participating in the price cap.

This week’s EIA Weekly Petroleum Status Report indicated that inventories of commercial crude rose slightly by 718,000 barrels to 419 million, shrinking the deficit back to six percent below normal for this time of year. The gain was largely attributed to more oil leaving the Strategic Petroleum Reserve since refinery utilization actually increased. The API reported that inventories decreased 1.3 million barrels while the WSJ survey predicted a decrease of 700,000 barrels. Refinery utilization rose to 92 percent vs 90.9 percent the prior week. Total motor gasoline inventories fell 3.1 million barrels to 223 million barrels, now at four percent below average. Distillates increased 283,000 barrels to 120.2 million barrels, still seven percent below normal. Heating oil stocks held at about 8.2 million barrels. Crude oil stocks at the key Cushing, OK, hub dropped 195,000 barrels to 25.0 million barrels, or 33 percent of capacity. Imports of crude oil were 6.2 million barrels per day, while crude exports were 3.5 million barrels per day. Exports of refined products were 5.7 million barrels per day, down from 6.3 million barrels per day. Volumes withdrawn from the Strategic Petroleum Reserve were 3.5 million barrels, which dropped the total inventory to 375 million barrels, the lowest level since 1984 and 214 million barrels less than a year ago. U.S. oil production was 100,000 barrels per day lower at 12.0 million barrels per day vs 11.8 million barrels per day last year at this time.

All three major stock indexes are poised to settle positive on the week but look to be much lower than the start of 2022. Crude prices couldn’t muster any gains despite a lower U.S. Dollar.

Rigzone: What were some market surprises?

Seng: Natural gas prices have fallen below the $5.00 mark on the prospect of warmer weather ahead despite the EIA’s Weekly Natural Gas Storage Report, which showed inventory levels are back to a deficit of three percent vs the five-year average for this time of year. The cold fronts coming in so far have been extreme and have dipped deeply into the country’s mid-section. And the coldest months are yet to come.

Rigzone: What developments/trends will you be on the lookout for next week?

Seng: The key EIA inventory reports this week only reflect activity through last Friday. Next week’s numbers should reflect the impact of Winter Storm Elliott on the East Coast. Conversely, the thousands of flights canceled by Southwest Airlines could lead to a gain in distillate inventories.

To contact the author, email [email protected]

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Exxon To Maintain Capex Levels At $20-25B Until 2027

Supermajor ExxonMobil today announced its corporate plan for the next five years which maintains annual capital expenditures at $20-$25 billion.

Exxon said that it plans a sizeable increase in investments aimed at emission reductions and accretive lower-emission initiatives, including its Low Carbon Solutions business. According to the company, lower-emissions investments will grow to approximately $17 billion.

The plan is expected to double earnings and cash flow potential by 2027 versus 2019 and supports the company’s strategic priorities, which include leading the industry in safety, shareholder returns, earnings and cash flow growth, cost and capital efficiency, and reductions in greenhouse gas emissions intensity.

“Our five-year plan is expected to drive leading business outcomes and is a continuation of the path that has delivered industry-leading results in 2022,” said Darren Woods, chairman and CEO. “We view our success as an ‘and’ equation, one in which we can produce the energy and products society needs – and – be a leader in reducing greenhouse gas emissions from our own operations and those from other companies. The corporate plan we’re laying out today reflects that view, and the results we’ve seen to date demonstrate that we’re on the right course.”

Investments in 2023 are expected to be in the range of $23 billion to $25 billion to help increase supply to meet global demand. The company also remains on track to deliver a total of approximately $9 billion in structural cost reductions by year-end 2023 versus 2019.

Upstream earnings potential is expected to double by 2027 versus 2019, resulting from investments in high-return, low-cost-of-supply projects. More than 70% of capital investments will be deployed in strategic developments in the U.S. Permian Basin, Guyana, Brazil, and LNG projects around the world.

By 2027, upstream production is expected to grow by 500,000 oil-equivalent barrels per day to 4.2 million oil-equivalent barrels per day with more than 50% of the total to come from these key growth areas. Approximately 90% of Upstream investments that bring on new oil and flowing gas production are expected to have returns greater than 10% at prices less than or equal to $35 per barrel, while also reducing Upstream operated greenhouse gas emissions intensity by 40-50% through 2030, compared to 2016 levels.

Near-term upstream investments are projected to keep production at approximately 3.7 million barrels of oil equivalent per day in 2023 assuming a $60 per barrel Brent price, offsetting the impact of strategic portfolio divestments and the expropriation of Sakhalin-1 in Russia.

ExxonMobil Product Solutions expects to nearly triple earnings by 2027 versus 2019. These growth plans are focused on high-return projects that are anticipated to double volumes of performance chemicals, lower-emission fuels, and high-value lubricants. The company continues to leverage its industry-leading manufacturing scale, integration, and technology position to upgrade its portfolio and reduce costs.

The company announced an expansion of its $30 billion share-repurchase program, which is now up to $50 billion through 2024. It also recently increased its annual dividend payment for the 40th consecutive year. By year-end 2022, ExxonMobil expects to distribute approximately $30 billion to shareholders, including $15 billion in dividends and $15 billion in share repurchases.

Growing the Low Carbon Solutions business

ExxonMobil has allocated approximately $17 billion on its own emission reductions and accretive third-party lower-emission initiatives through 2027, an increase of nearly 15%. Nearly 40% of these investments is directed toward building our lower-emissions business with customers to reduce their greenhouse gas emissions with a primary emphasis on large-scale carbon capture and storage, biofuels, and hydrogen.

These lower-emissions technologies are recognized as necessary solutions to help address climate change and closely align with ExxonMobil’s existing competitive advantages and core capabilities. The balance of the capital will be deployed in support of the company’s 2030 emission-reduction plans and its 2050 Scope 1 and 2 net-zero ambition. In the Permian, the company is on track with its goal to reach net-zero Scope 1 and 2 emissions from its operated unconventional assets by 2030.

“We’re aggressively working to reduce greenhouse gas emissions from our operations, and our 2030 emission-reduction plans are on track to achieve a 40-50% reduction in upstream greenhouse gas intensity, compared to 2016 levels.”

“We will continue to advocate for clear and consistent government policies that accelerate progress to a lower-emissions future. At the same time, we’ll continue to work to provide solutions that can help customers in other industries reduce their greenhouse gas emissions, especially in higher-emitting sectors of the economy like manufacturing, transportation, and power generation,” added Woods.

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BSEE Extends Public Review Period For Oil And Gas Draft PEIS

The United States Bureau of Safety and Environmental Enforcement has extended the period for public comments on the draft programmatic environmental impact statement (PEIS) for Oil and Gas Decommissioning Activities on the Pacific Outer Continental Shelf (OCS).

The public is invited to review and provide feedback on the draft PEIS until January 10, 2023.

The PEIS will inform future decisions on decommissioning applications for offshore oil and gas platforms in federal waters off southern California. Twenty-three California OCS oil and gas platforms installed between the late 1960s and 1990s are subject to eventual decommissioning.

“Given the number of requests for additional time to review and evaluate options for the anticipated offshore oil and gas decommissioning in the Pacific Region, BSEE is extending the comment period by an additional 29 days to Jan. 10, 2023,” said Bruce Hesson, BSEE Pacific Region Director. “The comments we receive will inform our decisions on future decommissioning in the region, we must therefore give the public ample time to provide feedback, helping to ensure a robust analysis.”

The Bureau of Ocean Energy Management (BOEM) is assisting BSEE in the preparation of the environmental impact statement and is maintaining information about the draft PEIS on its website. The public and all interested parties, including federal, state, Tribal, and local governments or agencies, are invited to submit written comments on the draft PEIS until January 10, 2023.

BSEE noted that comments can be submitted either through the Federal eRulemaking Portal, by traditional mail (either in an envelope or hand carry), or by email.

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Potential Biden Plan to Stock Up On Diesel May Bring Price Surge

US President Joe Biden is considering forcing the nation’s fuel suppliers to keep a minimum level of inventory in tanks this winter as a means of preventing heating oil shortages and keeping prices affordable. It may actually do the opposite.

Such a requirement would essentially sideline fuel supplies in the market today and divert them into tanks for safekeeping — a shift that could create a demand surge in the short term and an ensuing spike in prices. “It would result in product that would typically be exported going into storage,” said Jason Gabelman, an analyst at Cowen & Co., driving up prices in the Northeast without bolstering supplies in the market.

There is this precedent: In July, pipeline operator Magellan Midstream Partners LP raised minimum inventory levels for fuel stored throughout its pipeline and terminal system in the US Midwest, sending wholesale diesel prices there soaring.

A federal mandate could touch off an even larger-scale rally. The East Coast has grown increasingly reliant over the years on fuel imports from Europe, especially Russia. And Russia’s war in Ukraine has limited those shipments. Meanwhile, the largest refinery in the East Coast is preparing to go into maintenance in the middle of the region’s heating demand season, which typically peaks in January and February.

While the measure may backfire in the short term, it could get the ball rolling to prepare for next winter, said Paul Horsnell, head of commodities research at Standard Chartered.

“Now might be a good time to start things moving through Congress.”

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