Silicon Investor - Chevron

[Jon Koplik] Permian produced water, data centers can form symbiotic relationship ..............

Jon Koplik — 7/10/2026 12:59:37 AM

Permian produced water, data centers can form symbiotic relationship .............................

Oil & Gas Journal

July 7, 2026

Permian produced water, data centers can form symbiotic relationship

Technology around cleaning up produced water is evolving. Companies are looking to the Permian to deploy or prove their systems. That could, in turn, drive produced water as a source for data center use.

By Alex Procyk

The rapid expansion of AI data centers in West Texas is creating a major water demand challenge, prompting industry interest in treating and reusing the Permian basin’s vast volumes of produced water as a potential cooling-water source.

In this Insights episode of the Oil & Gas Journal ReEnterprised podcast, Alex Procyk, upstream editor, reviews the potential.

Produced water is extremely saline -- often far saltier than seawater -- making conventional desalination expensive, but emerging technologies, including systems that use data-center waste heat to drive treatment processes, could improve economics while generating valuable byproducts such as lithium and other minerals.

Large-scale adoption will depend on proving treatment costs at commercial scale, establishing clear permitting pathways, developing new business agreements between energy and data center operators, and effectively managing disposal and seismicity risks associated with concentrated waste streams.

---------------------------------------

END (of introduction) ( I did not try to listen to the roughly 27 minute long podcast.)

.
.
.

[robert b furman] Hi Jon, Great post. I liked it then and I've been buying VTS anedNOG lately. T...

robert b furman — 7/6/2026 8:52:11 AM

Hi Jon,

Great post.

I liked it then and I've been buying VTS anedNOG lately. They are substrantially below the 2025 April 9th lows.

For their business model to stay conservative and assure cash flow, the Iran War was a multi-year wind fall of future oil production hedged out well into 2027. above $70.00.

Bob

[Jon Koplik] WSJ -- Sudden Glut of Oil Threatens to Weaken Iran’s Hand in Talks ...............

Jon Koplik — 7/5/2026 5:06:45 PM

WSJ -- Sudden Glut of Oil Threatens to Weaken Iran’s Hand in Talks .................................

WSJ

Commodities & Futures

July 5, 2026

A Sudden Glut of Oil Threatens to Weaken Iran’s Hand in Talks

Cheaper, more plentiful crude offers countries a chance to restock more quickly and counter Tehran’s Hormuz leverage

By Rebecca Feng and Georgi Kantchev

Oil prices have fallen to prewar levels. Tanker traffic through the Strait of Hormuz is recovering fast. Gulf producers are already restarting idled wells.

But one thing will take much, much longer -- re-filling the world’s oil coffers.

Speed matters. The amount of oil in storage around the world is playing a central role in the U.S.-Iran power dynamics. The faster countries restock their buffers of crude, the weaker Iran’s ability to threaten the world economy by holding the Strait of Hormuz hostage.

Vice President JD Vance explicitly connected oil storage and negotiating leverage last week. He said in an interview with media personality Michael Knowles that the U.S. signed a memorandum of understanding with Iran to allow the world to “refill some stocks and then to see where the hand is,” referring to Tehran’s position at the table.

Oil storage is a mix of commercially owned tanks that sit near refineries, ships kept laden at sea and government-run strategic reserves. Inventories in the Organization for Economic Cooperation and Development, a group of mostly wealthy countries, fell by 163 million barrels from March to May to their lowest level since December 1990.

Re-filling global stocks is likely to take months if not years, longer than the 60 days stipulated in the MOU to settle thorny issues such as Iran’s nuclear program.

Two factors that will help rebuild stocks faster: falling prices and a surprising glut of oil.

“The surge in oil supply is about to collide with a market that, at least for now, simply does not need it,” said Natasha Kaneva, head of the global commodities strategy team at JPMorgan.

Some are predicting oil prices -- currently around $70 a barrel -- will fall even more in the months ahead, providing further relief to drivers and airlines. Analysts at Macquarie and Citigroup both forecast this past week that prices could sink to $60 in coming months.

Part of the reason for the projected price decline is that it will take time before strategic-reserve managers start buying again.

OECD nations are projected to begin refilling strategic reserves in the fourth quarter of this year, with the U.S. starting its own replenishment in 2027, first at only 100,000 barrels a day and then ramping up to about 170,000 barrels a day in the second half of the year, said JPMorgan’s Kaneva.

The turn of events -- from a market that nearly went into a dangerous supply shock into one that is amply supplied -- is “an almost comical development four months into Hormuz’s closure,” said Rory Johnston, founder of oil research firm Commodity Context.

Tanker traffic out of the Strait of Hormuz has entered a new normal of around 30 to 60 a day. That is less than before the war, but enough to relieve pressure in global markets.

Ship tracker Vortexa estimated around 140 million barrels of crude oil left in June -- an average of about 4.7 million barrels a day, up from just two million a day in May. The crude exodus accelerated in early July to about 40% of prewar levels, according to Vortexa.

On Sunday, the Organization of the Petroleum Exporting Countries and its allies agreed to raise oil output by 188,000 barrels a day in August, the fifth straight monthly increase. With shipping traffic through the strait recovering and Gulf producers restoring production, the cartel’s announcements of output increases are less symbolic than a few months ago.

The United Arab Emirates, which left OPEC in May after years of chafing under production quotas, has been one of the quickest Gulf producers to dial exports back up.

It is using a bypass pipeline from Abu Dhabi to Fujairah outside the strait, plus it is taking advantage of ships streaming out of the Gulf.

Kuwait has recovered production volumes faster than expected. Its export loadings rose to around 1.6 million barrels a day last week, compared with prewar levels of around 2.4 million barrels a day, Johnston said. Saudi Arabia, meanwhile, has kept sending oil via a bypass route to the Red Sea in addition to its tankers now exiting the Gulf.

Ample supply and low prices should spur companies and governments to rebuild stocks—eventually.

Crude levels in the U.S. Strategic Petroleum Reserve -- which was created in 1975 after the Arab oil embargo and sits in salt caverns on the Gulf Coast -- are still falling, and in the week ended June 26 hit their lowest level since 1983, according to the U.S. Energy Information Administration.

Replenishing the SPR back to prewar levels will take 15 to 18 months at a rate of 200,000 barrels a day, said Hamad Hussain, commodities economist at London-based research firm Capital Economics. And that is an optimistic rate of buying.

After the Ukraine war sparked an oil price shock in 2022, the U.S. did not start replenishing its SPR until mid-2023. It then added to the SPR at roughly 75,000 barrels a day for 30 months until the war with Iran started. By then, inventories were still significantly lower than they had been before 2022.

“Washington did not rebuild the SPR after the previous drawdown cycle, and with focus on keeping prices low, it has little incentive to bid aggressively for barrels to refill it now,” said Rahul Choudhary, an oil and gas research analyst at Rystad Energy.

In China, the government drew down barrels from its massive oil reserves -- which analysts estimate to be between one billion and 1.4 billion barrels -- to cushion the Gulf supply shock.

But China doesn’t appear to be in a rush to refill. Vortexa data shows that China imported just six million barrels of crude a day via sea in June, roughly four million barrels a day fewer than it averaged in 2025.

Not everyone thinks the current calm will last. The oil price is reacting to the idea that the “hostilities have largely finished for good,” said Neil Crosby of market-intelligence company Sparta Commodities. “I and many doubt that this outcome is real and lasting,” he said. But for now, it is hard to bet the other way until conflict flares up again.

------------------------------

END.

.
.
.

[Jon Koplik] 6/23/26 WSJ / Spencer Jakab / Energy Stocks Could Be a Slick Trade ...............

Jon Koplik — 6/25/2026 11:35:36 PM

6/23/26 WSJ / Spencer Jakab / Energy Stocks Could Be a Slick Trade .........................

WSJ

June 23, 2026

Energy Stocks Could Be a Slick Trade

By Spencer Jakab

Let’s face it: No one knows what will happen next with the Strait of Hormuz.

A single social-media post or Iranian drone could send oil prices plunging or surging before the digital ink is dry on this newsletter. The only thing we can say for sure is that there was a war and a whole lot of oil and natural gas wasn’t shipped to customers.

Energy stocks aren’t acting that way, though. An index of U.S. companies in the sector is now lower than it was before the conflict, trailing the market and lagging tech stocks by a mile.

It’s natural for a commodity producer’s value to fall when the price of what it sells does, but the market seems to be missing how long those prices were elevated and are likely to remain so. The benefit is easier to quantify than the potential gain from AI.

Analyst forecasts for free cash flow of the three largest companies in the energy index alone -- Exxon Mobil, Chevron and ConocoPhillips -- have risen by a combined $60 billion for this year and next, according to FactSet. For the two largest refiners in the index, Valero and Marathon, free cash-flow expectations are up $18 billion. Across just those five companies, that’s a 53% increase in cash that can be distributed.

Private and government stockpiles of oil and refined products around the world have been depleted and countries will have to refill them, basically guaranteeing extra demand. Those caught short, like India and Australia, might overcompensate.

That’s not all. Customers will take barrels wherever they can get them, but they won’t look at every supplier the same way now. Hydrocarbon reserves or vital infrastructure in politically stable regions far from war zones, mostly in the Western Hemisphere, should command a stock-market premium.

This 160-year-old industry doesn’t hold the growth promise of space or AI, but it’s getting oddly overlooked given the events of the past months. The entire U.S. energy sector is worth half as much as Nvidia alone. The three largest producers combined add up to less than Micron, which also operates in a notoriously cyclical business.

Energy booms tend to contain the seeds of their own destruction. The Hormuz crisis hasn’t been long enough (so far) to spur a ruinous wave of exploration spending or conservation, though.

In the weeks before the war, a rotation dubbed the HALO ( heavy assets, low obsolescence) trade ripped through U.S. stocks. That was when it looked like AI would disrupt once-highflying knowledge businesses like software.

Energy infrastructure is the ultimate heavy asset and a cash windfall doesn’t hurt either.

If you liked it then, you should love it now.

-------------------------

END.

.
.
.

[Jon Koplik] WSJ -- Inside Exxon’s Dilemma Over Returning to Venezuela ......................

Jon Koplik — 5/29/2026 10:45:59 PM

WSJ -- Inside Exxon’s Dilemma Over Returning to Venezuela ...........................................

WSJ

May 28, 2026

Inside Exxon’s Dilemma Over Returning to Venezuela

The U.S. oil giant is in talks to resume pumping oil in the Latin American country after a 19-year exile, but plenty of hurdles remain

By Collin Eaton and Kejal Vyas

Exxon Mobil is in talks with Venezuelan officials about returning to the oil-rich country after a 19-year exile. Yet many of the challenges that have long prevented American companies from making big investments there still plague the country.

The oil giant recently sent a technical team to survey the Cerro Negro heavy-oil project that it operated until 2007 when Hugo Chávez nationalized much of the country’s energy infrastructure. A group of U.S. executives also journeyed to Caracas to discuss potential investments.

The team left disappointed with what they found in northeastern Venezuela’s Orinoco Belt, according to people familiar with the matter. The project was in a ruinous state -- its upgrader, a facility that turns heavy crude into a lighter synthetic oil, needed major repairs. Oil wells across the region have sustained damage after years of mismanagement. Relaunching operations there would require billions of dollars in upfront investments, the company concluded.

Furthermore, talks with the emissaries of Venezuela’s new government haven’t been as fruitful as Exxon had hoped, the people said. In meetings in Caracas and Houston, the parties have yet to agree on contract terms that would tempt the company to risk entering the country. Even if they do reach a deal, a substantial rise in oil production is expected to take years to materialize given how long it would take to fix widespread environmental problems, solve electricity shortages and repair equipment.

Exxon, which was also kicked out of Venezuela in a nationalization push in the 1970s, remains focused on recouping all of the more than $1 billion it says it was owed in restitution -- and it isn’t convinced Venezuela will soon pay off that debt, some of the people said. The company, though, still wants to find a path forward.

“Until there’s a clear definition of the government’s take, it’s going to be quite hard to sign [a contract] with a new operator such as Exxon,” said José Ignacio Hernández, a law professor and consultant at Aurora Macro Strategies. “What is the amount of royalty? What is the amount of extraction integrated taxes?”

Exxon declined to comment.

The dilemma facing Exxon is consequential because Venezuela is home to some of the world’s largest oil reserves. As the biggest energy company in the U.S., Exxon prides itself on its ability to find and extract fossil fuels hidden deep in the earth’s crevices. Passing up the chance to tap those reserves would be difficult, especially when rival Chevron CVX is potentially primed for a windfall as the only big American company active there.

Meanwhile, having assets in Venezuela could give Exxon a geopolitical advantage and protect its interests in neighboring Guyana, where the company is pumping oil from a generational discovery. Before the U.S. ousted Nicolás Maduro, the strongman deployed military assets within reach of the Exxon-led project in Guyana’s Stabroek oil block.

Closer to home, securing a deal in Venezuela would endear Exxon to President Trump, who is pushing for U.S. energy companies to invest $100 billion to repair the country’s dilapidated oil-and-gas infrastructure.

Exxon CEO Darren Woods’s position toward Venezuela appears to have softened lately. On the company’s earnings call earlier this month, he called Venezuela “a huge resource that’s now opened up more freely to the world.”

That’s a big shift from January when Woods said at a White House meeting that Venezuela was “uninvestable” without significant changes to its commercial frameworks, legal system and hydrocarbon laws. Those comments drew the ire of Trump, who threatened to block Exxon from the country.

Relaunching the Cerro Negro project or starting up a new one would be costly for Exxon. The alternative to using the upgrader -- a facility designed to process 120,000 barrels of heavy crude a day -- would be to blend the crude with diluents, which would squeeze the company’s margins.

Repairs would cost several hundred million dollars, one of the people familiar with the matter said. Fully rebuilding the project’s infrastructure could cost as much as $5 billion, and new projects -- with more advanced upgrading facilities and higher production capacity -- could cost as much as $10 billion.

ConocoPhillips and other U.S. energy companies are also waiting for Venezuela to complete new contract rules that would clarify the government’s cut of any foreign fossil-fuel investments. Representatives from the U.S. oil industry have flocked to Caracas in recent weeks to seek an audience with Venezuela’s interim president, Delcy Rodríguez, to discuss potential investments.

Some have walked away stunned by the scope of the destruction in Venezuela’s oil fields. Power shortages, damaged roads and persistent security risks are ongoing challenges.

At a forum in Caracas last week, Chevron spokeswoman Susana Brugada said the country’s power outages have a devastating impact on oil operations.

“Every time one of those major power failures occurs -- the kind where everyone’s refrigerator starts to suffer and our computers crash -- just imagine what that does to the oil wells,” she said in comments broadcast by local TV network Televen.

“A single power flicker can knock out 40 wells in the blink of an eye; and it’s not as if the power comes back on and those 40 wells immediately spring back to life. When we do the math on their potential output, we are talking about a genuine reduction in national production.”

Yet momentum is still building in Venezuela. Chevron recently agreed to an asset-swap deal that would expand its footprint. In early May, some smaller companies -- including Hunt Oil, Crossover Energy, HKN Energy and Mercuria Energy Group -- signed memorandums of understanding to explore new drilling and trading opportunities.

MOUs are nonbinding and are seen by many in the oil industry as an expression of interest in striking a deal. Any agreements reached in the near term with Exxon and Conoco are expected to be MOUs.

Conoco CEO Ryan Lance recently told Bloomberg that Venezuela still has a lot of work ahead of it to attract oil-company investments.

Conoco, which maintains that Venezuela owes it more than $12 billion in restitution for the nationalization of its assets, is evaluating opportunities.

“As with any potential investment, decisions will be guided by a range of factors, including economic and policy stability, safety, adherence to the rule of law, and market competitiveness,” a Conoco spokesman said. “Any decision to proceed would need to take into account mechanisms to recover the debt that is owed.”

Copyright © 2026 Dow Jones & Company, Inc.

.
.
.

[robert b furman] Hi John, Thank You for the informative post! Bob

robert b furman — 4/27/2026 9:03:57 AM

[Jon Koplik] WSJ -- Persian Gulf Oil Damage Will Ripple Long Past the End of the War ........

Jon Koplik — 4/24/2026 3:17:06 PM

WSJ -- Persian Gulf Oil Damage Will Ripple Long Past the End of the War ...................

WSJ

April 24, 2026

Persian Gulf Oil Damage Will Ripple Long Past the End of the War

Even if the strait opens tomorrow, the hit to the global economy will be long lasting

By Ed Ballard and Joe Wallace and Summer Said

An oil refinery in Erbil, in Iraq’s Kurdish region.

It took a few days to close thousands of Middle East oil wells early in the Iran war. The prolonged closure of the Persian Gulf means it will take months or even years for energy flows to recover.

Traffic in and out of the Persian Gulf remains close to a standstill, with the U.S. and Iran locked in a tanker war and diplomatic efforts on ice. Brent crude prices shot back above $100 a barrel this week as oil-hungry sectors across the world came to grips with a closure that is lasting much longer than originally feared.

Analysts and oil industry executives say prospects for a speedy resumption of Gulf crude supplies are worsening. Even if the strait opens tomorrow, the damage to the global economy will be long lasting.

Reanimating the world’s most productive oil patch will require overcoming substantial engineering and logistical challenges.

Middle East producers need tankers that have fanned out across the world to deliver their cargoes and sail back, which could take months. Fuel amassed in storage tanks has to get to market to clear space for more oil. Workers who left the region when war broke out must return.

“There’s an awful lot of infrastructure that’s been shut down,” Russell Hardy, chief executive of oil trader Vitol, told an industry event this week. “It takes some time to put all that back.”

Goldman Sachs energy analysts said this week that the longer the Strait of Hormuz is closed, the slower the recovery in production will be.

One of the biggest hurdles will be restarting oil wells.

The problems are likely to be most acute in Iraq, the region’s second-biggest producer behind Saudi Arabia. In normal times, Iraq pumps 5% of the world’s oil. Daily output plunged to about 1.6 million barrels from 4.9 million before the war started at the end of February, said Mohammed Hussein of Iraq Oil Report, an industry publication.

Iraqi oil producers last week made initial test runs of a production restart, government officials said, but hit pause when it became clear Hormuz wasn’t opening.

The officials said poor security, an exodus of overseas workers and limited resources have made it hard to assess the state of some fields. Iran-backed militia in Iraq are believed to have been behind recent attacks on oil fields in the country, as well as strikes on energy infrastructure elsewhere in the region.

Some fields will have to be brought back slowly. Paraffin and asphalt-like substances may have clogged wells that pump thick crude. At older fields, pressure is likely to have fallen during the outage. Less oil and more natural gas might emerge when they are revived.

Getting back to 85% of prewar production in Iraq’s southern oil fields may take nine months, according to research firm Wood Mackenzie, though the area could achieve around two-thirds of prewar output more quickly.

Closing fields hurriedly, as many were in the early days of the war, can damage wells in addition to equipment such as submersible pumps that lift oil from fields where natural pressure isn’t strong enough.

Restarting the fields is costly, so the looming plunge in oil revenue could complicate the restart, the Iraqi officials said. Another obstacle, they said: Iraq doesn’t have a state tanker fleet unlike Saudi Arabia, meaning it relies on international traders and shipping companies.

“The longer things are shut in, typically the more complex they are to bring back on,” Jeff Miller, chief executive of oil-field-services company Halliburton, told analysts this week.

Exactly how much output will suffer will be a mystery until engineers try to restart production, said Fraser McKay, head of upstream analysis at Wood Mackenzie. He calls it “a really key uncertainty.”

Analysts say the United Arab Emirates and Saudi Arabia, the biggest producer by far, will have a better time, having carefully managed the pressure of their fields down the decades. Even there, output won’t recover at a stroke.

Across the Gulf, around half of oil fields have high enough pressure to return to prewar production rates within two weeks. Around 80% could do so within six weeks, according to the International Energy Agency.

The problematic 20% are mostly in Iraq and Kuwait, the latter of which normally produces about 3% of the world’s oil. “Ultimately, some pre-conflict production may not return,” the IEA said.

Iraqi oil trucks line up on a highway in Syria as shipments are rerouted.

For the oil market, the result is likely to be a long period of uncertain supplies.

Iraq was under more pressure to close production than its neighbors because it has less oil storage and export pipeline capacity. To keep as much oil flowing as possible, Iraq increased exports through a pipeline between the Kurdish region and Turkey, and started trucking fuel oil to Syria’s Mediterranean coast.

That amounts to a relative trickle, but “Iraq has no choice but to continue” with those stopgaps, said Yesar Al-Maleki, a Gulf analyst at the Middle East Economic Survey and nonresident fellow at the Atlantic Council.

Officials in Iraq are planning for the third major restart of its fields in a generation. Production tanked during the first and second Gulf Wars. It recovered and surpassed Saddam Hussein-era rates in part because of investment from international producers such as the U.K.’s BP and Italy’s Eni.

The country’s biggest field, Rumaila, is effectively run by a joint venture between BP and PetroChina under a deal with state-owned Iraqi companies. It produces a third of Iraq’s crude in normal times from hundreds of wells.

At Rumaila and other Iraqi fields with low pressure, operators inject water to force crude to the surface. In some cases, it takes three barrels of water to pump a single barrel of crude, said Ahmed Mehdi of consulting firm Renaissance Energy Advisors.

He said water mixes with the oil in unpredictable ways while wells aren’t pumping, so water output has to be carefully managed when the fields start producing again.

----------------------------

END.

.
.
.

[Jon Koplik] Bloomberg Opinion -- U.S. Oil Production Is Booming. So Is Demand ...............

Jon Koplik — 10/23/2025 11:14:37 AM

Bloomberg Opinion -- U.S. Oil Production Is Booming. So Is Demand ...............................

bloomberg.com

or :

archive.is

excerpts :

------------------------------

The US will consume an annual average of 20.59 million barrels of oil a day in 2025, the highest in 18 years, according to current trends.

-----------------------------

High US per capita oil consumption is driven by several factors, including a rich population living in sprawling suburbia and poor public transport.

-----------------------------

Until Trump won his second term, the American energy industry had largely accepted that the country’s oil consumption all-time high, set in 2005 at 20.8 million barrels a day before the onset of the global financial crisis, was unassailable. Rising efficiency meant that, after a brief recovery following the pandemic, America was a post-peak oil demand nation, like other rich countries such as Germany, France and Japan. Thus, only a few months ago, the International Energy Agency said that US consumption would fall every year from 2025 onwards, reaching 20.01 million barrels a day by 2030.

Today, the downward path looks uncertain. Can US oil demand grow further, setting a new high? Many -- me included -- think there’s a good chance. The most updated forecast from the IEA, looking only up to 2026, already shows a small increase next year.

---------------------------

The internal composition of that demand is changing. Back in 2005, when American overall oil demand set its record, gasoline and diesel were at the forefront of the country’s usage growth. Today, consumption of both fuels is down from the most recent peaks. Instead, the fastest-growing fraction of the barrel is ethane, used overwhelmingly as a feedstock in the petrochemical industry, where it becomes the building block of plastics. US jet-fuel demand is also growing rapidly.

---------------------------

END.

.
.
.

[robert b furman] Hi Carranza, What a pump and dump. They win the arb, and in the premarket, CVX...

robert b furman — 7/18/2025 4:09:36 PM

Hi Carranza,

What a pump and dump.

They win the arb, and in the premarket, CVX pops up 5 points ,and at the close it is down $1.34.

OH the larceny.

Bob

[carranza2] Chevron won the arbitration zerohedge.com

carranza2 — 7/18/2025 8:21:33 AM

[robert b furman] I would expect they'd get to buy their prorated amount of the asset, just like X...

robert b furman — 6/10/2025 4:39:44 PM

I would expect they'd get to buy their prorated amount of the asset, just like XOM did.

Not sure, but that is how my dealership buy/sell agreements are written and intended to work.

We'll see soon enough now.

Bob

[carranza2] Grok 3 thinks that CNOOC likely gets to participate (short version): **Conclus...

carranza2 — 6/10/2025 4:20:10 PM

Grok 3 thinks that CNOOC likely gets to participate (short version):

**Conclusion**:

If Exxon wins the arbitration, CNOOC, as Exxon’s partner, likely has the contractual right to participate in the "win" by exercising a right of first refusal to bid on Hess’s 30% stake in the Stabroek block, per the JOA. However, whether CNOOC actually participates depends on the specific terms of the agreement, the arbitration ruling’s scope, and CNOOC’s strategic and financial priorities. No definitive evidence confirms CNOOC’s exact role or intent, but its involvement in the arbitration filing suggests it could benefit alongside Exxon if the panel rules in their favor. The outcome remains uncertain until the ICC panel decides.[]

(https://www.reuters.com/business/energy/hess-guyanas-secret-value-becomes-part-exxon-arbitration-sources-say-2024-08-20/)[](https://www.reuters.com/business/energy/exxon-says-it-is-confident-it-will-win-dispute-over-chevron-hess-deal-2025-05-29/)[](https://www.bairdmaritime.com/offshore/exploration-development/oil-megamergers-exxon-cnooc-challenge-hess-corporations-sale-of-its-guyana-assets-to-chevron)

[carranza2] Every now and then someone writes something incisive. Here’s an example, IMO. ...

carranza2 — 6/10/2025 11:56:08 AM

Every now and then someone writes something incisive. Here’s an example, IMO.

maritime-executive.com

Question: if XOM wins its suit against CVX, does CNOC get to participate in the Hess asset? Hope not.

[Selectric II] Since XOM wrote the agreement, I lean to their interpretation of the JV to win....

Selectric II — 6/4/2025 3:12:13 PM

Since XOM wrote the agreement, I lean to their interpretation of the JV to win.

As a general rule, ambiguous terms or terms capable of multiple interpretations in a contract are construed against the drafter.

OTOH, they may have included language to negate that rule of construction.

This should be interesting, to say the least.

[robert b furman] Hi carranza2, I have a larger position in XOM. Since XOM wrote the agreement, ...

robert b furman — 6/4/2025 11:42:30 AM

Hi carranza2,

I have a larger position in XOM.

Since XOM wrote the agreement, I lean to their interpretation of the JV to win.

If they win, XOM and CNNOC could extract a bump in a side settling and gain a solid partner (more solid than Hess).

For a well capitalized E&P to take on another well capitalized partner would not be out of the ordinary.

Taking on CVX would parhaps allow a faster build out of a long life reserve - not a bad idea.

If either loses, I'll be ready to sell some puts, with the hope of getting them assigned. CVX pays a higher dividend, I would like to add to there stock (via selling a put not far out in time).

Just thoughts on the decision perhaps giving some short term discount on a great stock to buiy and hold for the dividend.

Thanks for your thoughts, it will be interesting.

Bob

[carranza2] An XOM trade seems like a likely winner. First, if XOM loses the arbitration, i...

carranza2 — 6/4/2025 10:26:50 AM

An XOM trade seems like a likely winner.

First, if XOM loses the arbitration, it doesn't lose its interest in the Guyana oil. It simply does not obtain the Hess portion. Its only loss are the legal fees which have been incurred, something XOM can pay with an hour's worth of production.

Second, if XOM wins, it obtains a very nice boost to its reserves, a boost which will of course be reflected in the share price. If CVX loses, it might seek some sort of appellate remedy, but reversal is very unlikely. IMO the arbitration panel's decision will control. It should mark the end of the litigation

The arbitration has been heard. A decision is expected in August.

I already own XOM, but will buy more in anticipation of the result. It is a great investment (dividend, management, etc.) even if it loses the arbitration. So, no loss should CVX win the arbitration, just a loss of an instant 15-20% boost in the share price. Otherwise, all other fundamentals remain unaffected.

How profitable is Guyana? Very nice field:

Exxon-led consortium's profit in Guyana rose to $10.4 bln in 2024
10:49:20 AM ET, 06/03/2025 - Reuters

GEORGETOWN, June 3 (Reuters) - The profit of a consortium by oil producers Exxon Mobil, Hess and CNOOC in Guyana increased 64% last year to $10.4 billion, Exxon said on Tuesday.

The group's expenses in the South American country rose to $4.9 billion in 2024 from $3.5 billion the previous year, the U.S. company added. (Reporting by Kemol King, writing by Marianna Parraga)

Thoughts?

[robert b furman] Hi Jon, I have positions in both CVX and XOM. I think that XOM should prevail....

robert b furman — 5/27/2025 10:45:17 AM

Hi Jon,

I have positions in both CVX and XOM.

I think that XOM should prevail.

The original JV agreement would most likely have a right of first refusal if they were written like my partnership agreements all stated.

No doubt Guyana has been and will be a huge success.

I would expect both CNOOC and XOM to buy up the Hess share of the JV.

As a side offer, I'd expect CVX to grease both CNOOC and XOM, if they were allowed to BUY IN to a much bigger and more successful venture that XOM put HESS on.

That's just my spin based on my Buy/Sell agreements I've had and signed with my partners in dealerships

WE SEE SOON!

[Jon Koplik] WSJ -- Why Exxon and Chevron Are Fighting So Hard Over an Oil Project in Guyana...

Jon Koplik — 5/25/2025 11:59:04 PM

WSJ -- Why Exxon and Chevron Are Fighting So Hard Over an Oil Project in Guyana ...................

WSJ

May 25, 2025

Why Exxon and Chevron Are Fighting So Hard Over an Oil Project in Guyana

The feud has chilled the relationship between their CEOs. It comes to a head when arbitration starts Monday.

By Collin Eaton

Exxon Mobil and Chevron are battling this week over rights to one of the world’s most coveted oil projects, a contest that has chilled the relationship between their senior executives and threatens to upend the industry’s hierarchy.

Exxon’s move last year to derail Chevron’s $53 billion purchase of Hess rankled Chevron’s senior executives and damaged a once-amicable relationship between the two rivals, people familiar with the matter said.

Exxon CEO Darren Woods and Chevron CEO Mike Wirth occasionally dined together and spoke by phone about their joint interests in projects around the world. That relationship has chilled, the people said.

The dispute hinges on Exxon’s claim that it has a contractual right to pre-empt Chevron’s bid for Hess’s stake in a major oil project in Guyana. And it has delayed what would be Chevron’s biggest-ever deal for more than 18 months. Chevron and Hess say Exxon doesn’t have the right to interfere in the corporate acquisition. Talks failed, and Exxon filed for arbitration last year.

The fight -- which has astonished the oil industry in Houston -- will come to a head Monday in London, with the start of a private arbitration hearing. By August or September, the panel will decide whether Exxon and another partner in Guyana, China’s Cnooc, have the right to counter Chevron’s bid for Hess’s 30% stake in a generational oil discovery of 11 billion barrels of oil and gas.

“What it highlights is how valuable big, low-cost oil fields really are in a world where it’s getting harder and harder to find them,” said Dan Pickering, chief investment officer of Pickering Energy Partners.

All three companies have projected confidence that they will prevail. The ruling will hinge on the interpretation of several lines in a confidential contract.

Exxon Mobil CEO Darren Woods; Chevron CEO Mike Wirth

For Chevron, the arbitration is a must-win. Hess is a big player in the Bakken Shale of North Dakota, but its crown jewel is Guyana. Hess’s share of the Guyana project could be worth some $40 billion, analysts estimated last year.

Guyana’s oil boom is fueled by six oil-production vessels now pumping around 650,000 barrels a day. Exxon hopes the consortium’s production will reach 1.3 million barrels a day by 2027. That is more than the entire Bakken produces.

The economics of the Guyana project are among the industry’s most lucrative. Oil giants cut exploration spending following the advent of onshore U.S. shale drilling. Although some frackers are beginning to look overseas for new prospects, few frontier oil fields show as much promise as Guyana.

Buying Hess -- a deal that Chevron announced in October 2023 -- would help quell concerns investors have had about Chevron’s portfolio of oil-production assets and where its growth will come from after 2030.

Much has changed in the past year. Chevron recently started up a major expansion project in Kazakhstan and fired up a big new oil platform in the Gulf of Mexico, which the U.S. now calls the Gulf of America. It is trimming costs with job cuts of up to 20% of its global workforce by the end of 2026.

Still, if Chevron falls short of a win, analysts say there are few other acquisition targets with the same potential as Hess. And Secretary of State Marco Rubio said Thursday that the U.S. plans to allow Chevron’s license to operate in Venezuela, which has vast oil reserves, to expire Tuesday.

Another reason Exxon’s challenge is more than just a headache for Chevron is that it comes in an age of investor activism. In the 1980s, when a big court fight between Pennzoil and Texaco pushed the latter toward bankruptcy, a takeover bid by activist Carl Icahn -- then dubbed a corporate raider -- made Texaco’s problems worse.

These days, the margin for strategic errors has shrunk, said Amy Myers Jaffe, director of the Energy, Climate Justice and Sustainability Lab at New York University. She points to Exxon’s proxy fight with activist investor Engine No. 1 that played out in 2021, and Elliott Investment Management’s more-recent push for changes at Phillips 66 and BP.

“If you don’t have a good strategy, you could be susceptible to a corporate raider or activist,” she said. “We’re in a time when the leadership of an oil company and the strategy they choose to take is material to whether people attack them from within the stakeholder groups.”

The oil companies are brawling over a generational find in Guyana, where a port to support offshore production was being built last year.

For Exxon, a loss in the dispute would have little negative impact in the short term. By the time the arbitration panel’s decision comes down, nearly two years will have passed since Chevron announced the Hess tie-up, a prolonged limbo that has kept it from pursuing other megadeals.

When Chevron proposed buying Hess, Exxon’s leaders were surprised that its partner in Guyana and its biggest competitor would -- behind closed doors -- strike a deal affecting a project that it had spent years developing. Exxon had done the spadework of government relations and assumed risk for the long-shot project after Shell exited its stake for a pittance in 2014.

Exxon says it has a responsibility to shareholders to consider the value of Hess’s Guyana stake in the Chevron deal, “and a right to then take an option on it,” Woods said on a call with analysts in December.

“Why would we give that away because one of the partners constructed a deal with another third party?” Woods said. “We don’t see why that would change the way we think about the option or the value of that option.”

Exxon has long held the role of big brother to Chevron, with larger oil production and superior profits. But during the pandemic, Chevron’s stock market value briefly vaulted above its rival. Exxon’s executives have since brought costs down and worked to gird the company from lower oil and gas prices.

Exxon’s shares have outperformed Chevron’s in the past few years, but a tie-up with Hess would help Chevron narrow the gap, analysts say.

If Exxon and Chevron ultimately work together in Guyana, the relationship among senior executives would bounce back, the people close to them predict. Some believe it may take time, though.

“Regardless of the outcome, there’s a cooling off between Exxon and Chevron that will be measured in years, not quarters,” Pickering said.

Write to Collin Eaton at collin.eaton@wsj.com

Copyright © 2025 Dow Jones & Company, Inc.

.
.
.

[Jon Koplik] OilPrice.com -- Chevron Needs Hess’s Guyana Oil Assets to Boost Reserves .......

Jon Koplik — 2/12/2025 3:19:04 AM

OilPrice.com -- Chevron Needs Hess’s Guyana Oil Assets to Boost Reserves .......................

OilPrice.com

Feb 11, 2025

Chevron Needs Hess’s Guyana Oil Assets to Boost Reserves

By Charles Kennedy

Chevron is betting on the multi-billion acquisition of Hess Corp to boost its assets with high-quality Guyana acreage where billions of barrels of oil equivalent have been discovered.

Chevron’s reserves replacement ratio has dropped in recent years and its oil and gas reserves have now declined to the lowest level in at least a decade, according to a Reuters analysis.

The falling reserves and the reserves replacement ratio (RRR) at below 100% make the proposed acquisition of Hess key to boosting Chevron’s asset base and RRR in the short term.

On the Q4 earnings call at the end of last month, Chevron said that its reserves replacement ratio (RRR) was -4% for 2024, with the largest reductions in proved reserves coming from production and the sale of oil sands and shale and tight assets in Canada. Additions to reserves were mainly from extensions and discoveries in the Permian and DJ Basins.

Excluding impacts from asset sales and acquisitions, organic reserves replacement ratio was 45%, Chevron said, reminding investors that reserves associated with shale development are limited to a five-year planning and execution period per SEC regulations.

During the past 10-year period, Chevron’s reserves replacement ratio was 88%, it said.

The ratio below 100% means that Chevron is depleting reserves faster than it can replace them.

The $53-billion acquisition of Hess would help increase the reserves and the RRR thanks to Hess’s 30% stake in the Stabroek block offshore Guyana where the operator Exxon has found more than 11 billion barrels of oil equivalent resources.

However, the deal has yet to clear several milestones before closing. The most important -- and potentially most problematic -- is the arbitration that Exxon and CNOOC, the third partner in Guyana’s prolific block, are seeking with Chevron over the proposed acquisition of Hess.

Exxon and China’s CNOOC claim that their current partnership terms with Hess Corp in the Stabroek Block give them the right of first refusal to the acquisition of Hess’s stake.

© 2025 OilPrice.com.

.
.
.

[Jon Koplik] Reuters -- Chevron struggles to replace oil, gas reserves amid Hess deal limbo ...

Jon Koplik — 2/12/2025 3:18:39 AM

Reuters -- Chevron struggles to replace oil, gas reserves amid Hess deal limbo ......................

Reuters

February 11, 2025

Chevron struggles to replace oil, gas reserves amid Hess deal limbo

By Sheila Dang

Chevron's reserve replacement ratio declines to 45%, raising investor concerns

Hess acquisition would boost Chevron's prospects with Guyana oilfield stake

Exxon and CNOOC challenged Chevron's bid for Hess in court

----------------------------------------

HOUSTON, Feb 11 (Reuters) -- Chevron's oil and gas reserves have fallen to the lowest point in at least a decade, highlighting the importance of the U.S. major's planned acquisition of oil producer Hess that has stalled due to a court battle with Exxon Mobil.

Reserve replacement is one of the key metrics for investors in energy companies, as it gives a sense of how much oil and gas the companies could produce and for how long.

If Chevron closes the Hess acquisition, it would gain a stake in the lucrative Guyana oilfields that are operated by Chevron's rival, Exxon

Exxon and CNOOC the other minority partner in the Guyana field, have challenged Chevron's bid for Hess in court, saying that they have first right of refusal on Hess's equity in the project.

Chevron's reserves, or the amount of oil and gas that it can potentially extract, declined from 11.1 billion barrels of oil equivalent in 2023 to 9.8 billion by the end of 2024. The reserves also declined in part due to sales of acreage.

The low rate of reserve replacement raises "red flags," said Paul Cheng, an analyst with Scotiabank, highlighting concerns about the company's longer-term prospects.

Chevron said its reserve replacement ratio over the past 10-year period was 88%.

The company's organic reserve replacement ratio, a metric that measures how much new oil and gas was added to the reserves compared to the amount it produced and excludes acquisitions and sales, was 45%. A ratio of 100% or more means the company is replacing its reserves at the same rate that it depletes them.

Cheng said the company's replacement ratio has been below the breakeven requirement over the past three years. Scotiabank maintains a sector outperform rating for Chevron.

Chevron declined to comment. During the fourth quarter earnings call, CEO Mike Wirth said the company was focused on developing high-quality oil and gas assets, including in the Gulf of Mexico.

The acquisition of Hess, a $53 billion deal struck in October 2023, could improve Chevron's prospects. It would grant the company a 30% stake in more than 11 billion barrels of oil equivalent of discovered recoverable resource in Guyana, the company said when it announced the deal.

"The combined company is expected to have resource inventory depth into the next decade – much further than we can usually see with confidence in our business," Wirth said in October.

Exxon has not yet reported its replacement ratio for 2024, but the No. 1 U.S. oil producer also struggled to replace its reserves in 2023 and 2022, which may have contributed to its decision to buy oil and gas producer Pioneer Natural Resources , Cheng said. Exxon declined to comment.

The Pioneer acquisition last year made Exxon the largest oil producer in the Permian Basin, the biggest U.S. oil field.

UK-based oil company Shell and French oil major TotalEnergies both have an average reserve replacement ratio over the past three years of more than 100%.

© 2025 Reuters.

.
.
.

[Jon Koplik] going to post two pieces / CVX / reserves replacement ratio -- one is from Reut...

Jon Koplik — 2/12/2025 3:18:10 AM

going to post two pieces / CVX / reserves replacement ratio -- one is from Reuters, and the other is from OilPrice.com.

Interestingly (at least to me . . . ) :

even though the OilPrice.com piece is pretty much just "referencing" the Reuters piece,

it ( the OilPrice.com piece) (and NOT the Reuters piece) brings up the following :

<<<<< Chevron . . . reminding investors that reserves associated with shale development are limited to a five-year planning and execution period per SEC regulations. >>>>>

which ... MIGHT negate the whole inflammatory / JUMP OUT THE WINDOW ! - nature of the "news" (?)

---------------------------

Also (another important detail) :

the Reuters piece said :

<<<<< Exxon has not yet reported its replacement ratio for 2024, but the No. 1 U.S. oil producer also struggled to replace its reserves in 2023 and 2022, which may have contributed to its decision to buy oil and gas producer Pioneer Natural Resources >>>>

Maybe Exxon also has the same problem with the SEC rules for :

reserves associated with shale development (?)

Jon.

.
.
.

[Jon Koplik] Barrons -- Exxon Enters the Electricity Business, Takes a Swipe at Nuclear .....

Jon Koplik — 2/3/2025 11:57:44 PM

Barrons -- Exxon Enters the Electricity Business, Takes a Swipe at Nuclear .....................

Barrons

Feb. 3, 2025

Exxon Enters the Electricity Business, Takes a Swipe at Nuclear

Exxon says it can compete with nuclear, because the gas power plants it intends to build would capture carbon emissions.

By Avi Salzman

Exxon Mobil CEO Darren Woods took a swipe last week at an industry that normally doesn’t come up on oil and gas earnings calls: nuclear power.

In normal times, oil and gas rarely crosses paths with nuclear. But these aren’t normal times. Fossil fuel energy companies are getting much more involved in electricity markets, and starting to butt heads with companies that provide electricity -- like the owners of nuclear power plants.

Woods mentioned nuclear while he was outlining a new business line on Exxon’s fourth-quarter earnings call: building natural-gas power plants to provide electricity to customers like tech companies that own AI data centers. Chevron is also looking to sell power from natural-gas power plants.

They would be competing with nuclear power in that arena. Nuclear companies have been some of the biggest winners of the AI boom, because tech companies have agreed to pay them above-market rates for the power from their reactors. One advantage of nuclear power is that it’s carbon-free, and it can help tech companies that have been trying to reduce their emissions. Shares of Constellation Energy, the country’s largest owner of nuclear reactors, have more than doubled over the past year, and small reactor company NuScale is up 700%. Exxon has risen just 5%.

Woods said that Exxon can compete with nuclear, because the natural-gas power plants it intends to build would be outfitted with technology that would capture the carbon emissions the plant produces, liquefy them and store them underground in perpetuity. The oil giant already owns the largest network of carbon pipelines in the country after buying pipeline owner Denbury in 2023. Exxon is “well-positioned to meet surging demand from data centers for low-carbon power and on a timetable that alternatives such as nuclear simply can’t match,” he said.

He has a point there. Nuclear power plants generally take more than a decade to build, whereas natural gas plants can be built in three to five years depending on how quickly companies can secure equipment like turbines.

And if Exxon can actually capture the vast majority of the carbon that the plants produce, they could rival nuclear plants in terms of emissions. Woods said the carbon capture aspect of the plants is the company’s big advantage -- he thinks Exxon can make more money by selling the “cleaner” power to tech customers than it could by simply selling natural gas power into competitive electricity markets.

But there are also downsides to Exxon’s proposed natural-gas power plants. The Institute for Energy Economics and Financial Analysis notes that carbon capture and storage has a “troubled history of cost overruns and delays,” and projects have tended to capture less carbon than initially expected.

And oil companies don’t have a great history in the electricity industry. Exxon doesn’t break out results for electricity-related business, because it has limited operations today. But French oil giant TotalEnergies details its earnings from its Integrated Power segment that generates and markets electricity. That includes areas like wind and solar power, which have struggled lately. In the latest quarter available, TotalEnergies said that the Integrated Power segment generated 9.5% returns on average capital employed, the lowest of all of its segments. Producing oil returned 15.6%, and refining and chemicals returned 27.4%.

[ note from Jon -- amazing that the Barrons reporter felt it was useful to include (weak) "Power segment" returns from an energy giant that has wind and solar power RUINING their investment return. ]

Write to Avi Salzman at avi.salzman@barrons.com

Copyright © 2025 Dow Jones & Company, Inc.

.
.
.

[Jon Koplik] OGJ -- Chevron affiliate Tengizchevroil starts production at Tengiz Future Growt...

Jon Koplik — 1/27/2025 11:24:41 AM

OGJ -- Chevron affiliate Tengizchevroil starts production at Tengiz Future Growth Project ...............

Oil & Gas Journal

Jan. 24, 2025

Chevron Corp. affiliate Tengizchevroil started oil production at its Future Growth Project at Tengiz oil field in western Kazakhstan.

By Alex Procyk

Chevron Corp. affiliate Tengizchevroil LLP (TCO) started oil production at its Future Growth Project (FGP) at Tengiz oil field in western Kazakhstan.

FGP is the third processing plant in operation at Tengiz field, which expands sour gas injection capability and is expected to ramp up output to 1 MMboe/d. Oil production at FGP follows completion of the wellhead pressure management project (WPMP) in 2024, which is designed to optimize the field and processing plants, the operator said.

The FGP and WPMP projects together installed power systems at Tengiz with five Frame 9 gas turbine generators, added four large compression trains with additional pumping capacity, installed a new centralized control center and enhanced sour gas handling and reinjection to the field for long-term pressure maintenance.

Tengiz ranks as the world’s deepest producing supergiant oil field and the largest single-trap producing reservoir in existence. The FGP expansion aims to increase crude oil production by 260,000 b/d at full capacity.

TCO is a Kazakhstani partnership owned by Chevron Corp. (50%), KazMunayGas (20%), ExxonMobil Corp. (25%), and Lukoil (5%)

© 2025 Endeavor Business Media, LLC.

.
.
.

[Jon Koplik] WSJ -- Oil Majors Flirt With Electricity ........................................

Jon Koplik — 1/25/2025 5:36:09 PM

WSJ -- Oil Majors Flirt With Electricity ...................................................................

wsj.com

or :

archive.is

WSJ

Heard on the Street

Jan. 21, 2025

Oil Majors Flirt With Electricity

As power generators such as Vistra soar, oil-and-gas giants are dipping their toes into a business where they have some natural advantages

By Jinjoo Lee

Exxon sees power plants as a means to expand the carbon-capture and sequestration business.

Artificial intelligence has suddenly made electricity a hot commodity. No wonder major oil companies want a piece of it.

Both Exxon Mobil and Chevron said last month that they are talking to potential data-center customers on deals to supply natural-gas-fired power paired with carbon-capture technology. Exxon is working on a power-plant design with at least 1.5 gigawatts of capacity -- enough to power more than a million homes. TotalEnergies, which has a power business, last year bought 1.5 GW of natural-gas-fired power plants near Dallas and Houston in Texas.

Exxon and Chevron have shied away from the wind and solar business for good reason: They have no experience in it and the expected returns are too low. But gas-fired power seems like a natural fit.

Major oil companies have plenty of experience in building and operating natural-gas-fired power plants to support their own energy-intensive operations, such as refining, natural-gas liquefaction and petrochemicals. Exxon said in its latest corporate update that it has developed 5.5 GW worth of power projects since 2001. Major oil companies might, in some cases, have more recent experience building power plants than large independent power producers: Many of them haven’t built power plants from scratch since the early 2000s, notes Hugh Wynne, co-head of utilities and renewable energy research at SSR.

Major oil companies also are able to move fast -- something tech giants value. They can site power plants near the source of fuel -- near their own oil and gas fields -- and sell electricity directly to data centers without needing to connect to the grid. And oil companies have lots of experience building off-grid power to support operations in far-flung places. That means they can bypass the lengthy process of connecting to the grid or building out a pipeline. In fact, it would be a natural fit for places with a lack of pipeline capacity -- such as the Waha hub in Texas -- where natural-gas prices often turn negative.

Another advantage: giant balance sheets and prodigious cash flow from their oil-and-gas business and disciplined spending. Investors would rather get cash returns than see major oil companies invest vast sums in oil and gas projects but could be open to investment in growth markets. Ultimately, this means major oil companies can fund power projects cheaply and quickly compared to raising project-level financing. Their scale should also come in handy when negotiating with equipment providers or engineering contractors.

Of course, the big question for major oil companies is whether returns from the power business are enough to meet their high hurdles. TotalEnergies’ integrated power segment, which also includes wind and solar, generated a return on average capital employed of 9.8% in 2023 compared with 18.9% for the overall business. Its goal is for the power business to reach returns of around 12% by 2028, which would be equivalent to TotalEnergies’ oil-and-gas returns when Brent crude prices are around $60 a barrel -- about 25% cheaper than they are today.

The return profile will ultimately depend on what major oil companies’ power exposure looks like. TotalEnergies’ integrated-power segment includes wind, solar and gas-fired power, as well as gas and electricity trading, for example. It still is unclear how much Exxon expects to get out of the power-generation business itself: It sees power plants as a means to expand the carbon-capture and sequestration business. “We don’t bring a lot of value creation to the power generation step in and of itself,” said Chief Executive Darren Woods in the company’s latest corporate update.

There are a few ways major oil companies might be able to squeeze out higher returns. One is if they can negotiate hefty premiums with tech companies for speedy access to off-grid power. Amazon.com and Talen Energy’s regulatory snag last year showed that siphoning electricity from grid-connected power will come with roadblocks. Fast access to a new, off-grid power plant removes those potential headaches.

Adding the ability to capture the carbon and bury it could command an extra premium, though the technology hasn’t yet been proven at scale. There are generous subsidies for the technology under the Inflation Reduction Act. Carbon-capture technology has been used with some success at coal-fired power plants, but it hasn’t been deployed at a commercial scale for natural-gas-fired power plants, according to Wynne of SSR.

Another option would be to indirectly benefit from data centers’ higher power demand by owning power plants that connect to the grid in deregulated markets such as Texas, California or PJM Interconnection. Those are markets where power-plant owners can profit from electricity price volatility. Plenty of power-plant owners have been burned by that volatility, but major oil companies are used to cyclical risks and have the balance sheets to weather them. TotalEnergies follows this model, selling about 30% of its electricity production to the wholesale power market without customer contracts.

The world’s energy demand is inevitably moving from hydrocarbons to electrons. Power-hungry data centers could very well help major oil companies stay relevant.

Write to Jinjoo Lee at jinjoo.lee@wsj.com

Copyright © 2025 Dow Jones & Company, Inc.

.
.
.

[Jon Koplik] Bloomberg / Oil and gas extraction / fastest labor productivity gains of any ......

Jon Koplik — 11/1/2024 1:21:27 PM

Bloomberg / Oil and gas extraction / fastest labor productivity gains of any ...........................

archive.is

Jon.

.
.
.

[Jon Koplik] Exxon Joins OPEC in Warning of Looming Oil Supply Crisis ..........................

Jon Koplik — 8/30/2024 12:56:57 AM

Exxon Joins OPEC in Warning of Looming Oil Supply Crisis ..............................

OilPrice.com

Aug 28, 2024

Exxon Joins OPEC in Warning of Looming Oil Supply Crisis

By Irina Slav

Exxon predicts a future oil shortage if investment in new production doesn't increase, despite forecasts of declining demand due to electric vehicles.

The company argues a rapid decline in production, especially from unconventional sources like shale, could lead to severe energy shortages and price hikes.

Exxon's warnings contrast with forecasts from the IEA and others who see lower oil demand in the future but raise questions about the long-term security of energy supplies.

-----------------------------

Traders and analysts have been overwhelmingly bearish on oil in the past few months. With a few exceptions, everyone seems to expect dwindling demand and falling prices. Yet it might turn out that the opposite will happen.

OPEC has been warning about this for years. Various officials from the cartel have been sounding the alarm that insufficient investment in new oil supply would eventually turn into a future supply squeeze that will push prices significantly higher. Exxon is now joining OPEC in those warnings.

In the new edition of its Global Outlook, the U.S. supermajor predicted that both oil and gas will continue to be vital elements of the world’s energy mix in 2050, with demand for oil remaining at above 100 million bpd after growth peaks and gas demand also remaining strong -- because electricity use in Exxon’s forecast will be 80% higher in 2050 than it is now.

Perhaps the most disheartening prediction made by Exxon concerns EVs and their effect on oil demand. Here’s what Exxon said about electric vehicles:

“If every new car sold in the world in 2035 were electric, oil demand in 2050 would still be 85 million barrels per day. That’s the same as it was in 2010.”

This stands in stark contrast with virtually every other forecast about electric vehicles and their impact on oil demand, which those other forecasters see as devastating -- even though the major growth in EV sales so far, even in China, has not really arrested oil demand growth.

One could argue that Exxon’s vision is of a world that the company wants to see in the future, so it can continue making money from selling hydrocarbons and hydrocarbon derivatives. It is the same argument one would use for OPEC’s warnings of under-investment in oil and gas.

However, it is not a particularly strong argument. A shortage of oil and gas would be very welcome to Exxon and OPEC alike. Shortages tend to drive prices higher, and higher prices invariably mean greater profits, as we saw in 2022. The other thing shortages lead to, however, is political and social instability, and that would not be welcome to large businesses such as Exxon -- hence the warning, and it is a grim one.

According to the supermajor, global oil production is facing a natural decline at a rate of some 15% annually over the next 25 years. For context, the IEA sees the rate of natural decline at 8% annually. Exxon points out, however, that the faster decline rate is a result of the shift towards shale and other unconventional oil production, where depletion happens faster than it does in conventional formations.

“To put it in concrete terms: With no new investment, global oil supplies would fall by more than 15 million barrels per day in the first year alone.” This is a scary prospect because “At that rate, by 2030, oil supplies would fall from 100 million barrels per day to less than 30 million -- that’s 70 million barrels short of what’s needed to meet demand every day.”

In other words, if investment in new oil and gas production dries up, the world will soon face not just a supply squeeze but the mother of all supply squeezes. Per Exxon’s report, the effects of that squeeze will feature severe energy shortages and disruption to daily lives, with oil prices potentially rising by as much as 400% -- twice as much as they jumped during the Arab oil embargo in the 1970s. This would, in turn, lead to higher unemployment, where rates could reach 30%, Exxon also said.

Of course, this is not going to happen. Long before such a massive squeeze materializes, there will be calls for more production, often from the same people who are currently calling for an end to all new oil and gas investment, as the IEA’s Fatih Birol did shortly after the IEA published its roadmap to net zero back in 2021.

In that roadmap, the IEA said the world needed no new oil and gas investments after the end of that year because oil and gas demand was going down. Several months later, amid falling supply and rising prices, Birol came out with a call on oil and gas companies to invest in more production and bring down prices. In IEA’s Oil Market Report for October 2021, the agency noted surging demand for energy and insufficient supply, noting that “Shrinking global spare capacity underscores the need for increased investments to meet demand further down the road.”

It seems, then, that Exxon might be on a more accurate track than the IEA, and the rest of the bearish forecasters fixated on China’s monthly crude imports and fuel exports. The supermajor might not be exaggerating the future that awaits the world if investment in oil and gas ceases. Fortunately for all of us, investment in oil and gas will not cease, despite the activist calls and threats by governments to force them to cease. The threats will remain just threats. Energy security always trumps ideology.

Copyright © 2024 OilPrice.com

.
.
.

[Jon Koplik] WSJ -- Canada’s Oil Sands Are Having Their Moment .................................

Jon Koplik — 6/25/2024 4:43:09 PM

WSJ -- Canada’s Oil Sands Are Having Their Moment ..............................

WSJ

HEARD ON THE STREET

June 25, 2024

Forget Shale: Canada’s Oil Sands Are Having Their Moment

The American oil patch’s poor northern neighbor offers investors stellar returns

By Jinjoo Lee

Canada’s oil sands were once the high-cost, dirty and unloved sibling to America’s fast-growing shale. Not any more.

Oil-sands producers have been among the top performing companies in the energy sector over the past year. Shares of the four largest Canadian oil-sands producers by market capitalization have gained an average of 37% over the past 12 months, outpacing an index of the largest U.S. energy companies by 19 percentage points. Two of those companies -- Canadian Natural Resources and Imperial Oil -- now fetch higher valuation multiples on some measures than U.S. supermajor Chevron.

Things weren’t always so rosy. Oil-sands facilities required enormous upfront spending, were expensive to operate and had a controversial environmental footprint. Not only that, but Canadian oil typically commanded steep discounts because of a chronic lack of pipeline capacity. Global energy giants such as ConocoPhillips and Shell sold off oil-sands stakes years ago.

It turns out their justifications were built on sand. On May 1, the pipeline bottleneck eased with the 590,000 barrel-a-day expansion of the Trans Mountain pipeline. The additional capacity should be more than enough to support Canadian exports for years, according to S&P Global Commodity Insights. In May, Western Canadian Select was on average 12% cheaper than the West Texas Intermediate, or WTI -- narrower than the 19% discount seen in 2022 and 2023, according to data from S&P.

The long wait and negative publicity might not have been worth the trouble for supermajors, but a similar move was a lot more consequential for oil and gas producer Ovintiv, which used to be called Encana. It thought it was following the smart money when it spun off its oil-sands producer, focusing its attention on booming shale. Since the spinoff, shares of the unit left with oil sands -- Cenovus -- has outpaced Ovintiv by 63 percentage points. Over the same period, the four largest Canadian oil-sand producers have appreciated about 84% on average, outpacing an index of the largest U.S. energy companies by 25 percentage points.

In addition to being able to export more, operating costs per barrel for Canadian oil sands have declined about 19% over the last five years, according to estimates from energy research firm Wood Mackenzie. Oil-sands production didn’t reach scale until the early 2000s, which means the industry is still fine-tuning the amount of steam and solvent needed to coax oil-like bitumen out of oil sands.

More recently, some companies have started replacing human-operated trucks with autonomous ones. Suncor Energy sees room for even more efficiency: On a call with analysts last month, the company said the WTI crude-oil price at which it can reach corporate break-even could come down by $10 a barrel, or about 19%, by year-end 2026.

For long-term investors, signs that production from prolific U.S. basins such as the Permian may be nearing a plateau is another reason to look north. The advantage of oil sands is that, while the upfront cost is high, it keeps producing oil at a steady rate for decades. The opposite is true for shale which, like a shaken-up bottle of soda, releases a lot of oil in the beginning but quickly declines.

“Oil sands are costly to produce, but there’s no shortage of the resource,” said Wells Fargo equity analyst Roger Read.

Analysts at BMO estimate that Canadian oil-sands producers on average need U.S. benchmark oil prices of $43.50 per barrel to fund sustaining capital and base dividends, compared with about $57 a barrel required for large-capitalization U.S. peers that have invested heavily in shale. Most oil-sands projects are now expansions that can piggyback off existing infrastructure, translating to lower capital expenditures per incremental barrel, noted Mark Oberstoetter, analyst at Wood Mackenzie.

Oil-sands producers also offer generous cash returns. Canadian Natural Resources reached its net debt target last year and is now returning 100% of its free cash flow to shareholders in dividends and repurchases, up from 50% in 2023. Suncor began allocating 75% of its post-dividend free cash flow to share buybacks. Analysts at BMO expect Cenovus to start returning 100% of free cash flow in 2025.

The caveat is that Canadian oil sands remain among the most carbon-intensive sources of oil. The industry is, however, making progress: It reduced methane emissions by 45% from 2014 levels in 2022, three years ahead of the target set by the province of Alberta, according to the government website. Technological progress on solvent-based extraction and carbon capture are further-out solutions but could ultimately help reduce emissions in the long term.

The energy industry’s one-time ugly duckling suddenly looks more like a beauty.

Write to Jinjoo Lee at jinjoo.lee@wsj.com

Copyright © 2024 Dow Jones & Company, Inc.

.
.

[Jon Koplik] Barrons / large oil company valuations ............................................

Jon Koplik — 5/21/2024 4:22:54 PM

Barrons / large oil company valuations ............................................................

this was from :

Barrons

May 17, 2024

12 Stocks to Play Growing Energy Demand, From Oil and Gas to Nuclear and Solar

Fossil fuels and clean-energy shares are unloved by investors. That's an opportunity, say our roundtable experts. Why some stocks could double, and then some.

-------------------------------

This commentary was from : Lucas White, a natural-resources and climate-focused portfolio manager at GMO.

<<<<< The fossil fuels industry is unloved by equity investors. A lot of endowments, foundations, and institutional investors have divested from the sector. That means it is unlikely fossil fuel companies will go from being really cheap, as they are right now, to the more normal valuations they had historically. To put some numbers on that, fossil fuel companies are now trading at about a 70% discount to the broad equity market. On average over the past 100 years, they have traded at closer to a 20% discount to the broad equity market.

You could invest in fossil fuel companies thinking that gap is going to shrink. If the discount goes from 70% to 20%, you'll make a lot of money quickly. But I suspect that isn't the most likely path. >>>>>

Jon.

.
.
.

[Selectric II] 'We understand the detailed language because we wrote it,’ senior vice president...

Selectric II — 3/6/2024 9:22:31 PM

'We understand the detailed language because we wrote it,’ senior vice president Neil Chapman said of the right of first refusal provision that could stop Chevron’s $53-billion deal for Hess.

Raises interesting issues.

For XOM's sake, if ambiguous, and unless a different rule applies, hopefully it has an enforceable, "No construction against the drafter" clause in the contract.

In rules of contract interpretation, if all else fails, and depending on state law, ambiguous provisions may be construed against the drafter.

XOM just said that it drafted the provision.

[Jon Koplik] OGJ -- ExxonMobil files for arbitration in Chevron-Hess Guyana dispute ............

Jon Koplik — 3/6/2024 4:49:19 PM

OGJ -- ExxonMobil files for arbitration in Chevron-Hess Guyana dispute ........................

Oil & Gas Journal

March 6, 2024

ExxonMobil files for arbitration in Chevron-Hess Guyana dispute

‘We understand the detailed language because we wrote it,’ senior vice president Neil Chapman said of the right of first refusal provision that could stop Chevron’s $53-billion deal for Hess.

By Geert De Lombaerde

ExxonMobil Corp. on Mar. 6 filed to have an arbitrator rule on the details of the joint operating agreement governing its work with Chevron Corp. and Hess Corp. in the Stabroek block offshore Guyana.

Chevron and Hess leaders last fall announced a deal to have Chevron pay $53 billion for Hess. ExxonMobil officials claim they have a right of first refusal to match the value assigned to Hess’ 30% non-operated interest in the ExxonMobil-operated Stabroek block (which also includes China National Offshore Oil Corp.) and potentially increase their stake.

Chevron recently said the right of first refusal provision doesn’t apply to its Hess acquisition plans and noted that a ruling to the contrary would torpedo the planned combination (OGJ Online, Feb. 29, 2024).

Speaking at a Morgan Stanley conference Mar. 6, ExxonMobil senior vice-president Neil Chapman said the company has asked the International Chamber of Commerce to arbitrate the disagreement, which he said is a process that could take up to 6 months. Not going to arbitration, he said, “would be incomprehensible” because of the embedded present and future value of the Stabroek project.

“It’s a fiduciary responsibility to shareholders,” Chapman said.

While noting that he can’t get into contract language specifics, Chapman told the Morgan Stanley audience that the Stabroek JOA is based on industry standards and added that the ExxonMobil team feels strongly that an arbitrator will rule in its favor.

“We understand the detailed language because we wrote it,” he said. “We’re extremely confident in our position that pre-emption rights exist under this contract.”

© 2024 Endeavor Business Media, LLC.

.
.
.

[Jon Koplik] WSJ / Chevron’s $53 Billion Deal for Hess in Jeopardy on Possible Exxon Challen...

Jon Koplik — 2/26/2024 11:40:27 PM

WSJ / Chevron’s $53 Billion Deal for Hess in Jeopardy on Possible Exxon Challenge .............................

WSJ

Feb. 26, 2024

Chevron’s $53 Billion Deal for Hess in Jeopardy on Possible Exxon Challenge

Exxon says it could pre-emptively match the price Chevron offered Hess for its 30% stake in a booming oil prospect off Guyana’s coast

By Collin Eaton

Chevron warned investors Monday that Exxon Mobil and China’s Cnooc are asserting they have a right to pre-empt the company’s bid for a stake in a prolific oil project off Guyana, an emerging dispute that could derail Chevron’s megadeal for Hess.

Chevron said in a regulatory filing that Exxon and Cnooc say they have the right to counter Chevron’s offer for Hess’s stake in the Guyana project, which Exxon operates and is one of the largest oil finds in years. Chevron warned investors it may not complete its purchase of Hess “within the time frame the company anticipates or at all.”

Much of the value in Chevron’s $53 billion all-stock acquisition of Hess proposed last year was tied to the smaller New York oil company’s 30% stake in an Exxon-led drilling consortium in Guyanese waters. The partnership has expanded oil production far faster than most offshore oil projects and expects to pump over 1 million barrels a day in coming years.

The development is a potential blow to Chevron’s largest acquisition in years, though it isn’t clear if Exxon and Cnooc will make a counteroffer. At this point, they are only asserting their right to do so.

Chevron spokesman Braden Reddall said Chevron and Hess don’t believe a right-of-first refusal applies to the Hess deal. Chevron said the companies have engaged in “constructive discussions,” and though Chevron said the deal might fall apart, it believes the talks will “result in an outcome” that wouldn’t delay or prevent the deal.

“We are fully committed to the transaction,” Reddall said. “There is no possible scenario in which Exxon or CNOOC could acquire Hess’ interest in Guyana as a result of the Chevron-Hess transaction.”

If the talks fall apart, Chevron said in a regulatory filing, it or Hess could choose to have Hess’s Guyana subsidiary pursue arbitration. A Hess spokeswoman referred inquiries to Chevron, and Cnooc didn’t immediately respond to a request for comment.

The dispute boils down to the terms of a joint operating agreement, or JOA, signed more than a decade ago, which governs the consortium. Hess had entered the JOA in 2014 when it purchased its stake from Shell. Some JOAs allow existing partners, like Exxon, to participate in ownership changes, and pre-empt an offer for an ownership stake with an offer of their own.

Exxon spokeswoman Emily Mir said the conversations with Hess and Chevron are set to continue, and that the company is working with the Guyanese government on the matter.

“We owe it to our investors and partners to consider our pre-emption rights,” Mir said. Exxon is trying “to ensure we preserve our right to realize the significant value we’ve created” in Guyana. Exxon didn’t say whether it will make its own offer for Hess’s stake.

The exact terms of the JOA weren’t immediately clear, including whether pre-emption rights exist or whether Chevron or others would have the right to make another offer.

Exxon has a 45% share in the Guyana oil project and Cnooc owns the remaining 25%.

The clash with Exxon is a setback for Chevron Chief Executive Mike Wirth, who late last year disclosed delays and cost overruns for a massive oil project in Kazakhstan, as well as shareholder returns that have recently underperformed rival Exxon.

The California oil giant’s attempt to join the jungle-covered South American country’s oil boom has coincided with a retreat by the American oil majors to the Western Hemisphere as global conflicts abound. Exxon lost its stake in a major Russian project following the Ukraine war.

Exxon and Chevron have sold off billions of assets in Asia and Africa in recent years, underscoring the growing importance of the U.S. shale plays and South America. Chevron last year began pumping oil in Venezuela again as the Biden administration eased sanctions. It helped to restore production there to faster growth than the market anticipated. It also is investing in Argentina’s shale and is exploring for oil and gas off Suriname, near Guyana.

In recent months, Venezuela’s Nicholas Maduro has escalated its military presence near its border with Guyana, a country of 800,000 with little means of defense. Satellite images that became public this month showed light tanks, missile-equipped patrol boats and armored carriers near Venezuela’s border. Analysts said an invasion is unlikely.

Exxon has assumed the lion’s share of the risk in the Guyana project, drilling there for years before large amounts of oil were discovered. Exxon and its partners continue to drill for additional oil finds, and the project’s value could increase substantially. Exxon currently estimates the Guyana project to house nearly 11 billion barrels of oil and gas.

Exxon fired up a new Guyana offshore development in November, boosting output by 220,000 barrels a day to a record in the fourth quarter. The company is planning to have half-a-dozen oil projects pumping crude off Guyana by the end of 2027, with production climbing to about 1.2 million barrels a day.

Write to Collin Eaton at collin.eaton@wsj.com

Copyright © 2024 Dow Jones & Company, Inc.

.
.
.

[Jon Koplik] Bloomberg -- Chevron says Calif. plays a risky game with climate and gasoline ...

Jon Koplik — 1/28/2024 9:24:26 PM

Bloomberg -- Chevron says Calif. plays a risky game with climate and gasoline .................................

Bloomberg

January 27, 2024

Chevron Says California Plays a Risky Game With Climate and Gasoline

Golden State drivers paid highest gas premium in last quarter

Refinery renewable fuel conversions reduce overall supply

By Kevin Crowley

Chevron Corp. warns its home state of California’s climate policies are a “dangerous game” that risk causing gasoline price spikes and shortages.

The premium California drivers pay for gasoline over the national average is likely to rise significantly if state legislators continue enacting policies to discourage petroleum production, Andy Walz, who leads the oil giant’s US refining division, said in an interview. While the state has the highest penetration of electric vehicles, it’s still the country’s second-largest consumer of gasoline.

California drivers paid an average of $4.94 per gallon of gasoline in the final three months of 2023, about $1.72 above the national average and the highest quarterly premium on record, according to data compiled by Bloomberg. The state has the country’s toughest low-carbon fuel standards that are encouraging refineries to convert from petroleum to renewable diesel. Such conversions reduce gasoline supply, pushing up prices, Walz said.

“They knew it was going to happen when they wrote the legislation, he said. “The problem is the consumer is starting to realize it. It’s becoming painful. The way politicians dealt with it was ‘let’s blame the oil companies.’”

California Governor Gavin Newsom’s office said in a statement that the gasoline price spikes the state has experienced have stemmed from oil companies’ own lack of planning.

“Big Oil has been ripping off consumers for decades and lying to protect their profits,” Newsom’s office said.

Chevron’s relationship with its home state has turned increasingly adversarial in recent months. Ever-tightening regulations are squeezing profits and triggered a $4 billion write down of Chevron’s assets, mostly in California. Governor Gavin Newsom has accused Big Oil of price gouging and lying about climate change, both of which are now the subject of investigations and lawsuits. Chevron denies the allegations and says it should not be punished for responding to consumer demand for transportation fuels, which are still heavily weighted toward fossil fuels.

The latest flashpoint is a proposal to establish a maximum refining margin in California. It’s already difficult for Chevron to justify growth projects at its two California refineries -- which account for about 30% of the state’s capacity -- due to a plan to end sales of internal combustion engines by 2035, which would eviscerate the market for gasoline. But a law that effectively caps refinery profit makes them all-but impossible, Walz said.

“If they cap the upside when conditions are good it’s going to make it really challenging to want to put our money there,” Walz said, adding that Chevron is committed to keeping its refineries safe and reliable. “I cannot compete internally for big capital investments. It doesn’t stack up. I’d rather spend money at our refinery in Mississippi.”

California has long had an outsized influence on national policy, particularly on the environment. The state’s tailpipe emission regulations in the 1970s exceeded those of the federal government but quickly became the national standard because it was easier for automakers meet the country’s toughest regulations set by its biggest market than tailor cars by state. It became known as the “California Effect” and extended to consumer goods and data privacy.

Governor Newsom set a goal for California to become net zero by 2045, five years ahead of US as a whole. Frequent droughts and wildfires mean it is already suffering from catastrophic effects of climate change. The state now gets more than half its power from non-CO2 emitting sources, up from 30% a decade ago and accounts for more than a third of the country’s EV sales. Almost all of America’s renewable diesel, made from vegetable oil and natural fats, is consumed in California.

That success is one reason why gasoline prices are so high. In part to take advantage of state incentives, Phillips 66 is converting its Rodeo refinery northeast of San Francisco to produce 50,000 a day of renewable fuels. Before the conversion, it produced 90,000 barrels a day of gasoline, diesel and jet fuel, representing a 44% overall supply cut.

Chevron and Marathon Petroleum Corp. have made similar conversions, contributing to an 11% reduction in California’s refining capacity over the past decade.

Refiners “are making decisions that are kind of putting us on a pathway where there could be a reliability problem,” Walz said. “You may not have the supply of gasoline if things don’t turn out the way the government wants them to. It’s a dangerous game.”

Conversions also alter the state’s product mix, which is currently awash in renewable diesel but short of gasoline. The problem is magnified because California is essentially an island when it comes to fuel because of a lack of pipelines connecting it with the rest of the country.

“It’s a very risk energy policy situation that we’re headed toward,” Walz said. “If there’s a problem, resupply for California has to come from either Europe or Asia. And that takes a while.”

-- With assistance from Chunzi Xu and Mark Chediak

© 2024 Bloomberg L.P

.
.
.

[Jon Koplik] Bloomberg Opinion / gasoline demand / peak gasoline : not yet .....................

Jon Koplik — 12/30/2023 7:26:46 PM

Bloomberg Opinion / gasoline demand / peak gasoline : not yet ..........................................

Bloomberg
Opinion

December 28, 2023

The Peak in Gasoline Demand Turns Out to Be a Mirage

Combustion-engine vehicles still dominate the world’s highways.

By Javier Blas

Rumors that gasoline demand has peaked have been greatly exaggerated.

After fueling the 20th century automobile culture that reshaped cities and defined modern travel, gasoline was supposed to begin its long goodbye this year. It didn’t.

Sure, Tesla Inc. and its rivals sold more electric vehicles in 2023 than ever before, reducing fossil fuel demand. In the moneyed suburbs of London, New York and Beijing, EV cars are a common sight. From that narrow perspective, it looks like the world has already started ”transitioning away from fossil fuels,” as agreed at the recent COP28 climate talks. But it’s a mirage.

Even as EV sales increased, the global oil industry sold more gasoline than ever this year, surpassing the previous 2019 peak that the International Energy Agency had expected would remain an unassailable all-time high. Outside wealthy neighborhoods, the internal combustion engine still reigns supreme; in middle- and working-class areas, the energy transition remains a distant prospect.

From the 1950s onward, when Henry Ford’s dream of a car in every middle-class American driveway became a reality, gas stations sprung up next to drive-in restaurants and strip malls, transforming the US landscape and economies across the globe. The gasoline used to power automobiles accounts for roughly one-in-four barrels of petroleum-refined products consumed worldwide.

As the climate crisis garners increased attention, the fuel is destined to play an outsized role in the energy transition -- an early indicator of whether the shift away from fossil fuels is happening, and at what speed. The theory was that as EV cars became more popular, gasoline demand would be “disproportionally” impacted, the IEA predicted in its most recent five-year oil outlook, released in June. “This means that the fuel is likely to exhibit the earliest and most pronounced peak in demand” of all fractions of the oil barrel, it added.

While consumption would recover this year, it wouldn’t reach pre-pandemic levels; the outlook was for a gentle, but constant, downward trend. In the middle of the year, the IEA predicted that gasoline usage would “never return to 2019 levels,” when demand reached 26.7 million barrels a day. Instead, consumption rose to about 26.9 million barrels a day this year, according to the latest IEA figures.1 And 2024 is poised for another, even if small, increase, to just above 27 million barrels a day. As thing stand, the peak in gasoline demand has been delayed by five years, to 2024 from 2019. And I won’t be surprised if, once more data are available and forecasts are updated, the peak is pushed forward even further.

The surge past the 2019 peak is particularly significant because it came against three notable headwinds: gasoline prices have been high, particularly in local currencies outside the US dollar world; work-from-home remains far more prevalent than before the pandemic; and Chinese economic growth has slowed.

The trend of higher-for-longer demand has three important lessons for understanding the energy transition. First, the stylized forecasts showing sustained demand declines rarely survive the passage of time -- not just years later, but often as soon as a few months after publication. Second, announcements of peak demand generate lots of headlines, but when consumption surges past those peaks, the public rarely hears about it, providing a misleading picture of the pace of the transition. Third, the shift away from fossil fuels will take longer than many had expected.

It's not all bad. The world is embracing EV cars and, over time, their market share will continue to increase, particularly in China, North American and Western Europe -- boosted by generous subsidies in many nations. Even if gasoline demand continues to increase, the pace of growth is slowing. We may not have reached the peak, but probably there isn’t much growth ahead, either.

Still, gasoline demand benefits from a strong force: the world is becoming richer. In 2023, there were about 1.1 billion passenger cars in use, up from about 850 million a decade earlier. Even if a growing percentage of those cars is battery-powered, the absolute number of gasoline-fueled cars has increased. It’s a trend that will take decades, rather than years, to reverse.

Until then, gasoline remains king -- whatever the forecasts say.

© 2023 Bloomberg L.P.

.
.
.

[Jon Koplik] WSJ / Argentina’s Vaca Muerta shale field / Sleeping energy giant in South Ameri...

Jon Koplik — 12/23/2023 1:52:44 AM

WSJ / Argentina’s Vaca Muerta shale field / Sleeping energy giant in South America .............................

Dec. 21, 2023

Global Conflicts Stir Sleeping Energy Giant in South America

Argentina’s Vaca Muerta shale field is among the megaprojects ramping up around the region

By Kejal Vyas

AÑELO, Argentina -- South America has long been the world’s sleeping energy giant, with massive oil-and-gas reserves still untapped. Now it is rumbling awake, with huge implications for the global market.

From the deep waters off the northern shoulder of the continent down to Patagonia, a number of countries in the region are ramping up oil-and-gas production even as developed economies race to cut carbon emissions and reduce their dependence on fossil fuels.

And South American companies are fast trying to position themselves to become new global suppliers as Western governments and energy majors are increasingly looking at the region to diversify away from conflict-ridden choke points of the Middle East and Russia.

“What we know is that Europe and the Western world is never going back to depending on Russian gas,” said Marcelo Mindlin, president of Buenos Aires-based Pampa Energía. “This is a big opportunity.”

His company is among a number that are increasingly active in Argentina’s large oil-and-gas patch called Vaca Muerta -- which means dead cow in Spanish.

Sitting on arid, windswept terrain as big as Belgium near Argentina’s border with Chile, the shale field has potential output comparable to the Permian Basin, long the most prolific region in the U.S., according to Rystad Energy.

Chronic economic crises and rigid currency controls have long hindered infrastructure development in Argentina, economists say, leaving trucks slowly plying dirt roads around rigs while companies struggle to import drilling equipment amid dollar shortages.

But thanks to a new political landscape in the country, Vaca Muerta could soon turn into a cash cow, say government officials and oil executives.

The country’s new libertarian President Javier Milei is promising a sweeping deregulation and privatization of the industry, sending local energy stocks soaring since his victory in November’s elections.

“Argentina is starting a new stage of history in the energy sector,” said Eduardo Rodríguez Chirillo, the new government’s energy secretary.

At a U.N. climate conference in Dubai earlier this month, 190 countries agreed for the first time to transition away from fossil fuels but essentially allowed governments to choose their own paths to get there.

The recent activity in South America indicates countries in this region don’t intend to dial back soon.

Steadily rising output from non-OPEC countries in the Americas, excluding the U.S., is set to add 1.3 million barrels a day of new oil supply in 2025, more than covering the 1 million barrels a day of new demand that is projected for that year, according to J.P. Morgan.

Brazil, which posted record oil-and-gas output of 4.7 million barrels a day in September, is slated to overtake Canada as the world’s fourth-largest producer when it pumps 5.4 million daily by 2029, according to the energy ministry. President Luiz Inácio Lula da Silva has heralded the developments and has said that while his government wants to join OPEC+ next year as an observer, it doesn’t want to be bound to the cartel’s production limits.

Jean Paul Prates, chief executive of Brazilian state oil company Petrobras, said the increase is a recognition that the global economy will need oil for decades despite projections that fossil-fuel demand could peak by the end of this one. His company plans to funnel more than 70% of its $102 billion investment plan over the next four years into production and exploration.

Offshore drilling in Brazil’s smaller neighbors, Suriname and Guyana, is also contributing to the regional production boost. The latter has become one of the region’s hottest energy frontiers with Guyana’s production, via an Exxon-led consortium, slated to top a million barrels a day by 2027.

In Venezuela, which sits on the world’s largest oil reserves, President Nicolás Maduro recently said his country was ready to re-enter global energy markets after it reached a deal with the Biden administration in October that temporarily lifted oil-sector sanctions. Lobbyists for oil companies -- from U.S. giant Chevron to Indian refiner Reliance -- had pushed Washington for more than a year to ease the sanctions, arguing that restarting Venezuelan energy exports would help mitigate the disruptions in global markets caused by Russia’s invasion of Ukraine.

This week, the U.S. and Venezuela agreed to swap prisoners, in a sign that thawing relations between both sides could keep economic sanctions out of the picture.

But political risk will continue to weigh on Latin American oil prospects. The U.S. has said sanctions could be reapplied on Venezuela if Maduro’s authoritarian government fails to organize free and fair elections next year. Venezuela is also threatening to annex most of Guyana’s land.

In Argentina, despite the leadership change, the economy remains hamstrung by galloping inflation and severe restrictions on companies’ access to U.S. dollars, stymying foreign investment. The currency controls were applied by the previous left-leaning government but Milei pledges to dismantle them as part of his broad pro-business agenda.

On Wednesday, the self-described anarcho-capitalist decreed a series of economic measures that aim to remove the role of the state in key economic sectors. The announcement followed on his campaign promises to slash taxes and dramatically cut spending by eliminating half of government ministries and eventually privatizing state-run energy firm YPF, which controls about a third of Vaca Muerta’s production.

Milei’s plans, which are expected to face significant pushback from rival lawmakers and powerful unions in this politically polarized nation, already triggered thousands of demonstrators in the capital to hit the streets banging pots on Wednesday in protest.

Milei also aims to move ahead with big cuts to public works projects around the country, stoking some concerns among economists and oil workers over the future of state-backed initiatives like roads and pipelines that were meant to benefit Vaca Muerta.

“Privatizing and leaving workers out on the streets is going to generate widespread civil unrest, especially in this area,” said Fernando Banderet, a councilman in Añelo, which sits at the gateway to the Vaca Muerta region, where foreign and local oil companies have set up offices.

Banderet said his small town in a remote corner of Patagonia lacks basic infrastructure. Scant public transportation leaves many workers in YPF coveralls hitchhiking for rides back to the closest city of Neuquén, a two-hour’s drive from Añelo along a one-lane road that is sometimes cut off by indigenous protesters.

Facing housing shortages and shoddy road maintenance, Banderet, who had supported the previous Peronist government, said his town has struggled to keep up with a population that has grown about 10-fold to 10,000 in the last decade with workers from around the region flocking to the town seeking employment.

Despite the obstacles for the Milei administration, hope is rising across Argentina’s political spectrum that Vaca Muerta’s oil-and-gas deposits could boost the crippled economy.

“When you need scale and hard dollars rapidly, you have one button: Vaca Muerta’s shale oil,” said Miguel Galuccio, chief executive of Vista Energy and a former president of YPF who ran that company for four years after it was nationalized by Argentina in 2012. “Vaca Muerta is part of the solution. It can contribute to Argentina’s macroeconomic stabilization.”

Increased energy production could redraw much of the regional energy map and help eliminate Argentina’s need for gas imports during the winter, which came as a hefty burden to the state last year due to the Ukraine war. The Center for Political Economy, an Argentine policy group, estimates that replacing gas imports could generate $3 billion in annual savings.

Much depends on the country’s macroeconomic situation and whether contractors can resolve bottlenecks and unpaid import bills caused by currency controls, said Mindlin, the Pampa CEO.

Pampa holds concessions covering 8% of Vaca Muerta, but the company has only drilled 46, or about 2%, of the nearly 2,000 wells they believe they could exploit.

“We have a super aggressive plan,” said Mindlin. “With a country that is more stable, it could be something we’d be able to do.”

-- Silvina Frydlewsky, Samantha Pearson and Luciana Magalhaes contributed to this article.

Write to Kejal Vyas at kejal.vyas@wsj.com

Copyright © 2023 Dow Jones & Company, Inc.

.
.
.

[sixty2nds] The situation is very different from 3 years ago... That is when I bought my CV...

sixty2nds — 12/1/2023 8:04:24 PM

The situation is very different from 3 years ago...

That is when I bought my CVX.
International exposure was not the issue is is today.

I did not like the price action in the drop in CVX share price from $185.
I initially thought it was the market thought it was a late cycle buy of Hess.
Exxon was not punished to any where were the same degree.

I changed my mind.
Last week I sold the CVX and moved 100% of the proceeds into VNOM.

I still like CVX A LOT.
I think the Dividend is ROCK solid.

I am not prepared to take the hit if K'stan and the ME heat up

I am much more comfortable in The Permian Basin with VNOM.

Cheers,
60

[Jon Koplik] Barrons piece on Chevron / "Been Punished Enough" .................................

Jon Koplik — 11/4/2023 12:13:36 PM

Barrons piece on Chevron / "Been Punished Enough" .....................................

Barrons

November 4, 2023

Buy Chevron Stock. It’s Been Punished Enough for Earnings and the Hess Deal.

The oil titan has disappointed investors, but shares look attractive after the recent selloff.

By Andrew Bary

In less than a year, Chevron has gone from being Wall Street’s favorite Big Energy company to a show-me story. Investors who buy the stock now should end up liking what they see.

Chevron stock has fallen 17% in 2023, making it the worst performer by far among the half-dozen global super majors this year. Exxon Mobil, by comparison, is down just 2% this year, and the Energy Select Sector SPDR exchange-traded fund is about flat.

Most of the drop has come during the past few weeks after a disappointing earnings report that included news of a surprise delay in the development of a key oil field in Kazakhstan, while Chevron’s $60 billion deal to buy Hess, an independent energy producer, not only failed to excite investors but was seen as a sign of weakness by some.

Wall Street is too negative on the company’s prospects. While the situation at Chevron may take a few quarters to resolve, It looks well-positioned for what is likely to be decades of strong demand for fossil fuels. Chevron produces oil and gas around the world, with key assets in Australia, Kazakhstan, the Gulf of Mexico, and the Permian Basin of Texas and New Mexico. It produced 3.1 million barrels a day of oil equivalent in the third quarter, behind industry leader Exxon Mobil at 3.7 million.

Shares, which now trade near $147 after hitting a 52-week low in the past week, also look attractive valued at 11 times projected 2023 earnings of $13.71 a share and 10 times next year’s estimated profits of $14.44 a share. At the current price, the stock will yield 4.5%, based on the company’s plan to boost the dividend by 8% in early 2024.

“The assets and the valuation are attractive,” says Mizuho Securities analyst Nitin Kumar, who has a Buy rating and price target of $215 on the stock.

Chevron’s total yield -- encompassing dividends and stock buybacks -- should top 10%, based on its projection that it will repurchase $20 billion of stock annually, assuming the Hess deal is completed by mid-2024. Chevron has a great balance sheet, with net debt of $15 billion against a current market value of $275 billion. It was enough for BofA Securities analyst Doug Leggate to upgrade Chevron to Buy from Neutral this past week.

The stock market isn’t so sure. CEO Mike Wirth said the deal “positions Chevron to strengthen our long-term performance and further enhance our advantaged portfolio by adding world-class assets” -- chief among them a 30% interest in a massive Guyana field, which contains 11 billion barrels of oil equivalent.

On the other hand, Chevron got a richly valued company with no real overlaps, providing little opportunity for cost cutting. What’s more, there’s no current free cash flow, given investments that Hess is making with its partners to double Guyana production by 2027 from a current 400,000 barrels a day. The all-stock deal will also mean $2 billion of added annual dividend costs. Wall Street is assuming that Hess shareholders will back the deal despite a drop in Chevron’s stock price since the transaction was unveiled in October.

Greg Buckley, a portfolio manager at the Adams Natural Resources fund, says that getting control of the Guyana stake was worth the Hess price given the field’s growth outlook. Chevron seeks to boost its energy production by at least 3% annually through 2027 off a 2022 base.

Making sure that happens falls to Wirth, Chevron’s CEO of the past five years. He emerged as the top big-energy leader as Chevron generated ample returns in recent years with disciplined capital spending, smooth operations, and acquisitions like the $13 billion deal for Noble in 2020, which gave it control of a big gas field off the coast of Israel. In recognition of Wirth’s efforts, Chevron waived its mandatory retirement age for CEOs to allow Wirth, now 63, to continue to work after he turns 65.

Some of the sheen has come off the Chevron story. Chevron has run into issues with two of its most important assets. Earlier this year, the company said it was having some production shortfalls in the Permian, possibly making it harder for Chevron to hit its goal of 1 million barrels a day there by 2025 from about 775,000 now.

Issues have also cropped up in Kazakhstan, where Chevron is the lead operator and 50% owner of a large oil field called Tengiz that produces about 750,000 barrels a day. On its third-quarter conference call, Chevron announced a delay in an important expansion project that would help take production up to a million barrels a day from late 2024 to 2025.

Still, managing complex large energy fields has historically been the forte of Big Oil. Permian and Tengiz may have raised questions about how well Chevron can manage the development of large projects, but Adams Natural Resources’ Buckley thinks Chevron has been “overly punished” and will get back on track.

At Chevron stock’s current price, that’s a bet we’re willing to make.

Write to Andrew Bary at andrew.bary@barrons.com

Copyright © 2023 Dow Jones & Company, Inc.

.
.
.

[Jon Koplik] amazing how much more informative the OGJ piece is ...

Jon Koplik — 10/23/2023 3:56:46 PM

[Jon Koplik] Oil & Gas Journal -- Chevron to acquire Hess in $53-billion deal ..................

Jon Koplik — 10/23/2023 3:55:57 PM

Oil & Gas Journal -- Chevron to acquire Hess in $53-billion deal ............................

Oil & Gas Journal

Oct. 23, 2023

Chevron to acquire Hess in $53-billion deal lined with production upside

Chevron has agreed to acquire Hess in a stock deal valued at $53 billion, further diversifying the energy company’s portfolio with Stabroek block interests offshore Guyana and adding Bakken, Gulf of Mexico assets to its US portfolio.

By Mikaila Adams

Chevron Corp. has agreed to acquire Hess Corp. in an all-stock transaction valued at $53 billion, further diversifying the energy company’s portfolio with the addition of Stabroek block interests offshore Guyana and adding Bakken acreage to the company’s existing US shale position.

The deal is expected to increase Chevron’s estimated 5-year production and free cash flow growth rates and extend such growth into the next decade, the company said in a release Oct. 23.

This increased production growth and cash flow accretion -- aided by $1 billion in expected run-rate synergies within a year of the deal’s closing -- appears as motivation for the deal, TD Cowen analysts said in a note Monday.

“Hess' portfolio consists of non-op assets in Guyana, 465,000 net acres in the Bakken [with] 190,000 boe/d of production, 30,000 boe/d of production in the US Gulf of Mexico, and about 60,000 boe/d of gas production in the North Malay Basin [Southeast Asia]. There is minimal operational overlap outside of the GOM [Gulf of Mexico] and should attract little FTC [Federal Trade Commission] pushback,” the analysts said.

Production growth

Hess’s portfolio was expected to grow production by an average 12% over the next 5 years “with a portfolio break-even targeted below $50/bbl Brent by 2027,” the analysts continued. Growth is largely attributed to its share in the ExxonMobil Guyana asset where Liza 1 and Liza 2 are on production, and where Payara, the third development, is undergoing startup operations (OGJ Online, Feb. 14, 2022; Apr. 19, 2023).

In July, as part of its quarterly earnings report, Hess revised upward its full year 2023 net production guidance to 385,000-390,000 boe/d based largely on operational performance and expected startup of Payara offshore Guyana (OGJ Online, Aug. 7, 2023). Hess said net production for Guyana for full year 2023 is expected to be 115,000 b/d of oil, up from previous guidance of 105,000-110,000 b/d.

In the same report, the company noted a discovery in the Gulf of Mexico through its 100%-operated Pickerel-1 exploration well in Mississippi Canyon Block 727 that it planned to tie back to its Tubular Bells production platform with first oil expected in mid-2024.

With the deal, Chevron will acquire 30% ownership in the ExxonMobil-operated Stabroek block. The 6.6-million acre block lies 120 miles offshore Guyana, holds more than 11 billion boe discovered recoverable resource, a strong production growth outlook, and potential exploration upside.

Based on the discoveries on the block to date, six floating production, storage, and offloading (FPSO) vessels with gross production capacity of more than 1.2 million gross b/d of oil are expected to be online by end-2027 with potential for up to 10 FPSOs to develop the discovered resources on the block.

Hess also holds interest in the 3.3-million-acre Kaieteur block, which lies 155 miles offshore Guyana, adjacent to Stabroek block.

The combine’s capital expenditures budget is expected to be $19-22 billion, and Chevron expects to increase asset sales and generate $10-15 billion in before-tax proceeds through 2028.

“If we’re going to remain capital-disciplined […] we need to invest in the best and so that’s what we’ll do,” Chevron chairman and chief executive officer Mike Wirth said on a conference call with analysts. “There will be some assets we have that, in the company 2 years ago or 4 years ago, would’ve attracted capital. But with a stronger portfolio, [we] are just going to find that other assets are preferentially going to draw that capital.”

The deal is expected to close in first-half 2024 subject to Hess shareholder approval, regulatory approvals, and other customary closing conditions. Hess chief executive officer John Hess is expected to join Chevron’s board of directors.

Under the terms of the agreement, Hess shareholders will receive 1.0250 shares of Chevron for each Hess share. The total enterprise value, including debt, of the transaction is $60 billion. In aggregate, Chevron will issue about 317 million shares of common stock.

© 2023 Endeavor Business Media, LLC.

.
.
.

[Jon Koplik] WSJ -- Chevron to Buy Hess for $53 Billion ........................................

Jon Koplik — 10/23/2023 2:23:10 PM

WSJ -- Chevron to Buy Hess for $53 Billion .................................................

WSJ

ENERGY & OIL

Oct. 23, 2023
1:50 P.M.

Chevron to Buy Hess for $53 Billion

Deal is the latest sign of consolidation among oil-and-gas companies, highlighting industry’s bet on continued fossil-fuel use

By Collin Eaton and Peter Stiff

Chevron said it would buy Hess in an all-stock deal worth $53 billion in the second major oil tie-up this month, after Exxon Mobil’s deal to buy Pioneer Natural Resources.

The U.S. energy company said buying Hess would upgrade and diversify its portfolio, marking Chevron’s entrance into an Exxon-led partnership overseeing a generational oil find in Guyana, while picking up additional U.S. shale assets largely in North Dakota.

The transaction, less than two weeks after Exxon’s acquisition of Pioneer, shows America’s second-largest oil company is similarly tying its future to a bet that the world will continue to have an appetite for oil for decades, even as many countries are seeking to cut emissions and transition toward green energy.

The major oil companies’ doubling down on fossil fuels follows a recent prediction by the International Energy Agency that fossil-fuel demand globally would reach its zenith this decade.

“These are two great American companies coming together to be even stronger at a time when investment in American energy is important from the standpoint of jobs and from the standpoint of energy security,” Chevron Chief Executive Mike Wirth said in an interview on Monday.

The deal values Hess at $171 a share based on Chevron’s closing price on Friday, with Hess shareholders receiving 1.025 shares of Chevron for each Hess share. The price represents a premium of 4.9% from Hess’s closing share price on Friday and 10.3% when compared with the stock’s 20-day average price.

Hess shares edged down less than 1% to $161.80 in morning trading, while Chevron shares fell 3.3% to $161.33. Including debt, the transaction has a total enterprise value of $60 billion.

The deal comes as oil-and-gas companies are flush with cash after energy prices rocketed in the wake of Russia’s invasion of Ukraine, with executives signaling they were ready to deploy their war chests at the deals table.

Hess has been led for decades by Chief Executive John Hess, who -- along with a few other shale executives -- has made the public case for bolstering domestic energy supplies. Hess is expected to join Chevron’s board, Chevron said.

Hess, who owns about 9% of the eponymous company, led it to scoop up a large position early on in the American shale revolution, primarily in the Bakken Shale of North Dakota.

The biggest prize for Chevron is Hess’s nearly one-third share of the estimated 11 billion barrels of oil and gas found off the shores of Guyana. Exxon and its partners, Hess and China’s Cnooc, have revved up Guyana’s oil production from nothing in 2019 to 400,000 barrels a day.

The partners expect to be pumping 1.2 million barrels a day by 2027, making it one of the world’s fastest-ever oil developments. By then, the former British colony will be the source of $180 billion in market value for the consortium, some analysts have said.

Exxon Mobil earlier this month struck a nearly $60 billion agreement to buy Pioneer Natural Resources in the largest oil-and-gas deal in two decades. Both Exxon and Chevron have also agreed on smaller transactions earlier this year.

On Monday, Wirth said the deal for Hess would position his company to strengthen its long-term performance and further enhance its portfolio. The combination is also expected to achieve cost synergies of around $1 billion before taxes within a year of closing, the company said. Wirth said the combined company should have an inventory of lucrative drilling locations into the next decade.

Wirth has become a vocal defender of the U.S. oil industry as fossil-fuel producers have come under scrutiny of the Biden administration, environmental groups and European governments for their contribution to climate change.

“I don’t think this would in any way be read as not being supportive of a lower carbon future, but it also recognizes the reality that oil and gas are important today and will be for many, many years to come,” Wirth said in the interview.

Mark van Baal, founder of Follow This, a climate-focused investment group, said Chevron’s deal runs counter to the Paris climate agreement and that investors must exert more pressure on oil companies to reduce production.

Chevron’s board of directors has said it would waive the company’s fixed retirement age to allow Wirth to remain CEO for a longer period as it weighs its C-suite strategy. Wirth became CEO in 2018, when the company was reeling from years of cost overruns made more acute by an oil-market crash in 2015 and anemic energy prices. He was seen as an executive who could corral runaway costs.

In 2019, Wirth refused to enter into a bidding war when Occidental Petroleum swooped in to buy Anadarko Petroleum for billions more than Chevron had offered. Chevron received a $1 billion breakup fee and bought Noble Energy for a lower price the next year, a deal that gave the company access to Middle East natural-gas markets and a bigger U.S. footprint.

Wirth has touted his strategy since walking away from Anadarko to focus on acquisitions that offered low premiums to its targets, including its agreement in May to buy PDC Energy for more than $6 billion. Chevron’s deal to buy Hess is its third since the onset of the Covid-19 pandemic in 2020 with a premium of around 10%, Chevron said.

Wirth said he expects Chevron will make a double-digit return on capital employed, a measure closely watched by investors, at midrange oil prices and would be prepared for an oil downturn, should one occur. Echoing other oil executives and analysts, Wirth said it is time that companies scale up via mergers and acquisitions.

“Ours is an industry, particularly as you get into the shale patch, that was due for some consolidation,” Wirth said on a call with investors on Monday.

Chevron said it expected the Hess deal, which needs a green light from Hess shareholders as well as regulatory approvals, to close in the first half of 2024.

Wirth and Hess said they don’t foresee regulatory issues in closing the deal. They expected Guyana’s government to continue to honor a production-sharing agreement it had struck with the consortium, and they see approval from U.S. antitrust regulators, who have taken a close look at large corporate acquisitions under the Biden administration.

“In the global crude market, we’re a small player,” Wirth said on the call.

Chevron also said Monday that it would boost returns to shareholders. The company said it expects to increase its first-quarter dividend by 8% in January and plans to increase share repurchases.

Energy companies have reported lower results this year after record-setting levels last year, but are still reporting big profits because of elevated commodity prices. Chevron is to report its third-quarter earnings on Friday.

Hess was founded in 1933 by John Hess’s father Leon, the former owner of the New York Jets football team. Hess said his company’s legacy began about 90 years ago with his father “delivering fuel oil in a secondhand truck during the Depression.”

In recent years the company has sold off some assets in various countries to focus on its core operations. It is also known for its sale of toy trucks around Christmas, a tradition that Hess and Wirth said on Monday would continue.

Write to Collin Eaton at collin.eaton@wsj.com and Peter Stiff at peter.stiff@wsj.com

Copyright © 2023 Dow Jones & Company, Inc.

.
.
.

[sixty2nds] finance.yahoo.com Exxon in advanced talks for $60 billion acquisition of Pionee...

sixty2nds — 10/6/2023 7:30:44 AM

finance.yahoo.com

Exxon in advanced talks for $60 billion acquisition of Pioneer - sources

By David French, Anirban Sen and Sabrina Valle

(Reuters) -Exxon Mobil is in advanced talks to acquire Pioneer Natural Resources in a deal that could value the Permian shale basin producer at about $60 billion, people familiar with the matter said on Thursday.

The acquisition would be Exxon's biggest since its $81 billion deal for Mobil in 1998 and would expand its footprint in one of the most lucrative regions of the U.S. oil patch.

Pioneer's shares rose nearly 12% to $240.47 in premarket trading on Friday while Exxon slipped 1.7%.

Pioneer, which had a market value as of Thursday of $50 billion, is the third-largest producer of oil in the Permian basin after Chevron Corp and ConocoPhillips. That basin, which stretches across parts of Texas and New Mexico, is the U.S. energy industry's most coveted because of its relatively low cost to extract oil and gas.

If the negotiations conclude successfully, an agreement between Exxon and Pioneer could be reached in the coming days, the three sources said, asking not to be identified because the matter is confidential.

Spokespeople for Exxon and Pioneer declined to comment. The Wall Street Journal first reported on Thursday that a deal between the two companies was approaching.

Exxon, which has a market value of $436 billion, is the largest U.S. oil producer with an average 3.8 million barrels of oil equivalent per day (boed) from its global operations.

Last year it earned a record $55.7 billion thanks to high oil and gas prices and ended the year with $29.6 billion in cash.

Some of those profits have tapered off this year as energy prices, which surged after Russia's invasion of Ukraine, have fallen over concerns about a global economic slowdown weighing on fuel demand.

Acquiring Pioneer would give Exxon more established oil-producing land it can rely on to increase production when needed, rather than risk its cash on the development of unproven acreage.

"It makes complete sense," said Bill Smead, chief investment officer of Smead Capital Management, an investment firm which manages $5.2 billion in funds. "You replenish your reserves without poking holes in the ground."

Exxon produced about 620,000 boed in the Permian basin in the second quarter, a record for the company. Still, this was dwarfed by Pioneer's output in the basin, which averaged 711,000 boed in the same period.

The potential deal is set to attract political and regulatory scrutiny, after the White House accused Exxon in February of achieving bumper profits at the expense of consumers.

Other oil majors have also been turning to dealmaking because they find it risky to drill new acreage. Chevron Corp, for example, agreed in May to acquire shale producer PDC Energy Inc in a stock-and-debt transaction worth $7.6 billion.

Pioneer itself has bulked up through dealmaking, including the acquisitions of U.S. shale rivals DoublePoint Energy for $6.4 billion in 2021 and Parsley Energy for $7.6 billion in 2020.

The Dallas-based company is led by industry veteran Scott Sheffield, who has said he will retire at the end of this year and be succeeded by his chief operating officer Richard Dealy.

(Reporting by David French and Anirban Sen in New York and Sabrina Valle in Houston; Editing by Greg Roumeliotis, Lincoln Feast and Kim Coghill)

[sixty2nds] theepochtimes.com

sixty2nds — 9/10/2023 8:03:51 AM

[sixty2nds] seekingalpha.com Chevron Corporation (CVX) Management Presents at 2023 Barclays...

sixty2nds — 9/7/2023 12:30:25 PM

seekingalpha.com

Chevron Corporation (CVX) Management Presents at 2023 Barclays CEO Energy-Power Conference Call Transcript

Sep. 06, 2023 2:30 PM ET Chevron Corporation (CVX)

SA Transcripts

140.42K Followers

Chevron Corporation (NYSE: CVX) 2023 Barclays CEO Energy-Power Conference September 6, 2023 8:00 AM ET

Company Participants

Nigel Hearne - EVP, Oil, Products & Gas

Conference Call Participants

Betty Jiang - Barclays

Betty Jiang

It is my tremendous pleasure to introduce Chevron's EVP of Oil Products and Gas, Nigel Hearne, as our next speaker. Nigel started at Texaco and has practically been with Chevron and its - including its predecessor for over 30 years, and has held roles across upstream, downstream, and strategy. In his current role, he's responsible for the entire value chain, ensuring an integrated approach to capital allocation and value chain optimization. Nigel will start with some prepared remarks, and then we get into fireside chat. Nigel, thank you for being here, and the stage is yours.

Nigel Hearne

Thank you, Betty. Good morning, everyone. It's a pleasure to be here today. Before we begin, please be reminded this presentation contains estimates, projections, and other forward-looking statements. Please take a moment to review the cautionary statement on the screen.

Our strategy is straightforward and consistent, to safely deliver higher returns and lower carbon. We apply capital and cost discipline through a focused portfolio of advantaged assets, as we aim to sustain strong financial performance and provide superior cash returns to shareholders in a lower carbon future. Because the world's demand for energy is growing, we intend to grow both traditional and new energy supplies, focused on businesses and regions where we can leverage our strengths. We aim to remain among the lowest carbon intensity producers. Our 2022 upstream methane intensity was 64% lower than the US average, and our renewable fuels production capacity is increasing, building up our position as the country's second largest bio-based diesel producer. We continue to advance foundational projects in hydrogen and carbon capture, with plans to drill a stratigraphic well to further assess the storage potential of our Bayou Bend CCS project on the US Gulf Coast. We just delivered our eighth consecutive quarter of return on capital employed above 12%, and another quarterly record in cash return to shareholders. Over the next five years at $60 brent, we expect to grow free cash flow over 10% per year, in part from the assets that'll provide an update on over the next few slides.

We completed the acquisition of PDC Energy in early August, making our Colorado business one of Chevron's top five assets in terms of production and free cash flow. We continue to be impressed by the PDC team and are excited to have them join Chevron. Our teams are working to evaluate well spacing and frac designs to build a development playbook focused on optimizing returns and delivering $400 million in annual CapEx efficiencies. With a deep inventory of permitted locations already approved, we're confident in our ability to deliver on our plans in the DJ Basin for years to come. We're also on track to deliver $100 million in annual OpEx synergies, including early wins, like already paying off some high-cost debt. We're always looking to add high quality resource at good value. This acquisition is accretive to all important financial metrics, adds approximately 10% to our approved reserves base for a little more than 2% of our outstanding shares, and is expected to add $1 billion in annual free cash flow at $70 brent.

Capital discipline always matters in a cyclical commodity business. In our company-operated assets in the Permian, we're improving drilling and completions efficiency. For example, we have reduced non-productive time using new bottomhole assembly designs and digital tools to optimize drilling parameters. In completions, we're improving cycle time with simul-frac, and we have reduced frac crew mobilization time. We're also reducing loss production and workovers to optimize gas lift design. We are getting more out of our rig and frac fleet. We are drilling and completing more lateral feet with fewer rigs. This leads to more wells put on production while maintaining flat unit costs in an inflationary environment. We expect to average 13 to 14 company-operated rigs in 2024, fewer than previously anticipated, but up on average from this year. Higher activity levels, increased water handling facilities, and lower inflation are expected to lead to a CapEx budget next year of around $5 billion.

We still expect to hit 1 million barrels of oil equivalent per day in 2025, as we continue to focus on execution efficiencies to deliver higher free cash flow. TCO generates strong cash and has paid large dividends to Chevron over its history. Over the last several years, the base business cash flow supplemented with partner loans, has been used to invest in the Wellhead Pressure Management project, WPMP, and the Future Growth Project, FGP. We've already started to see higher dividends as CapEx levels have declined, and expect the base business cash flow and the higher oil production from FGP to further contribute to distributions in the coming years.

TCO continues to deliver base business production while we remain focused on safe, reliable startup of both projects. The project is forecast to be mechanically complete this quarter. Recent commissioning progress has been slower than expected due to technical challenges on the utility systems and lower productivity rates. We're taking actions to mitigate schedule pressure, including making resource adjustments. We'll assess the impact of these actions on project progress over the next few months.

In summary, these are just some of our key assets driving growth and free cash flow. In Q&A, I hope we'll get the chance to cover some of our other growth assets, like our upstream projects in the Gulf of Mexico and in the Eastern Med, and downstream projects in petrochemicals and renewable fuels.

And with that, I'll turn it back to Betty and welcome her to the stage.

Question-and-Answer Session

Q - Betty Jiang

Nigel, thank you for the prepared remarks and setting the stage for strategy and some of the key assets. I want to start on the strategy side. Do you think that Chevron's model of high return, lower carbon should apply to everyone in the energy sector? And it really reflects the essence of what shareholders and stakeholders are asking the sector to do. But I think you have to deliver that with increasing volatility in the commodity market. There's a lot more government regulations. The operating environment that you're in today may be different from what it was years ago. Just your thoughts on, do you think energy companies have to operate differently today than they did in the past decade to adopt to the changes that you see facing the market?

Nigel Hearne

Well, our company has been around for almost 150 years. And I would say over that time, we've constantly been evolving and changing, and I actually don't think that's going to change anytime soon. Energy companies have had to deal with price volatility, geopolitical risk, demand uncertainty. The complexities of running our business mean we have to manage and operate when our strategies and our execution across a whole range of business cycles. We're in a long-term business and we've got to be able to adapt and flex to do that. For Chevron, we're playing to our strengths. We're going to play to our strengths and leverage our strengths to safely deliver lower carbon energy to a growing world, a world that desperately needs that energy. We use our financial priorities to guide how we think about our investments. They've been consistent for decades. And if you don't know what they are, I'll remind you, they're about delivering superior shareholder return through predictable dividend growth, through investing in long-term competitive returns, maintaining a strong balance sheet, and then buying back across the cycle. So, those guide how we think about how to allocate our capital. Our company, given the discipline that we do have, has upside leverage and downside resilience. So, at $50 brent, we cover both our dividend and our capital program. We have a very strong balance sheet, with net debt less than 10%. That positions us really well to work in that volatile and uncertain space. We are going to be cost and capital disciplined. So, your comment around where we've been historically, we are going to be cost and capital disciplined and remain so. We'll invest in the highest return opportunities. We'll continue to grow our traditional oil products and gas business and our new energy business. We think the world's going to need more affordable lower carbon energy. Why? Because the world's going to need economic prosperity, energy security, and environmental protection. And Chevron, we've been around for 143 years, and we're going to be around for many decades to come, and I'll be proud to be part of that journey.

Betty Jiang

Proud to follow that. And so, the answer is not or but and.

Nigel Hearne

You have to do it all.

Betty Jiang

Yes, exactly. And so, in your prepared remarks, you touched on a number of things that's important for Chevron and really ranging from your unconventional development to major capital projects that you see in Kazakhstan, and then including M&A as well. So, wanted to ask about capital allocation. How do you (technical difficulty) between short cycle versus long cycle against that volatile commodity environment?

Nigel Hearne

So, two principles. We work on a long-term view of commodity price. It's very difficult to react and respond to short-term changes in commodity price. So, we're going to take a long-term view on commodity price, and quite simply, we're going to invest in the highest return opportunities. We have more opportunities to fund than we're going to fund. That's a good place to be in as a company. We're going to allocate our capital to the highest returns, lowest carbon intensity projects to help deliver our free cash flow growth that we're focused on.

So, if you look at our diverse and advantage portfolio, it has scale. It has materiality. It's long lived. We have a low decline rate in our company at less than 2%. So, that affords us the opportunity to invest in those high-return opportunities. To take a specific example, in upstream where most of our capital will be invested, about two-thirds of our capital is going to shale and tight over the five - if you look at our five-year forward look of capital up to 2026, about two- thirds goes into shale and tight assets. I would've said Permian and Argentina. Now I'll add the DJ Basin and the acquisition through PDC. But the balance of the other third goes into long-term projects, or MCP [Technical Difficulty] like Gulf of Mexico, like TCO, our base business and our exploration program. So, it happens that they go into shale and tight because they're short-term higher returns, but if you look at our portfolio and the opportunities we have, what we're investing in is the highest return opportunities. The short cycle project also gives us flexibility. So, I like the way we've invested our portfolio. We have lots to choose from, lots to invest in, and I think we've got the right balance.

As to M&A specifically, we've spent a lot of money in the M&A over the last three years. It's been - people often now talk about that as part of our capital program. And internally, with the tension between, if we have more capital, how would we use it? You’ve got to remind people, we've spent a lot of money in some really good investments. I would say I like our portfolio. We don't need to do anything in our portfolio. We can grow our enterprise value through our existing portfolio mix. We don't need to do a deal, but we're always looking and we're always looking in a way that creates value where we can create an advantage, either scale up an existing business or add accretive value to an acquisition. We have a high bar. We set a high bar. We’re disciplined about how we think about those things, and I think we've shown discipline around that. With financial priorities, particularly around a strong balance sheet, allows us to be opportunistic when we see value created and there's an opportunity there, but we don't need to do a deal. I think we've demonstrated discipline in the acquisitions we have made, like Noble, PDC, and the Renewable Energy Group, and we've also shown discipline in the acquisitions we didn't make, like Anadarko. That will continue.

Betty Jiang

That's definitely showed discipline there. So, with the wealth of projects - so it's not for the lack of opportunities within the portfolios. It’s more capital-constrained more than anything else. Then the output, the growth that you have projected, it’s 3% CAGR by 2027. How did you land to that production growth rate? Why is that the right number? If there's more opportunity, why not hire? And then I'm sure there you also get pushback on why grow at all.

Nigel Hearne

Yes, there's a whole range of viewpoints. I guess the first thing I would say is, production growth matters when it's profitable. That's when it really matters. So, if you think about our advantaged portfolio and our capital-efficient investments, our ability to choose where we think the most capital-efficient, highest return investment opportunities, given our scale and advantaged portfolio, means we have a rich choice of where we could spend our capital. We will continue to use our financial priorities to guide how we allocate our capital. So, again, I come back to predictably growing shareholder return, investing in long-term returns for decades, competitive long-term returns, maintaining a strong balance sheet, and then buying back across the cycle. We feel we have the right level of capital investment in our portfolio. We're growing both our traditional oil products and gas business and our new energy business. We're confident in our 3% CAGR, because we have line of sight to where the opportunities are, 3% over the five-year period. We've got a low decline rate. And that growth is going to be driven by projects like in shale and tight, the Permian and DJ Basin, completion at TCO and FGP, other shale and tight, and our Gulf of Mexico assets. So, we have line of sight to where our growth is. Could we do more? Yes. But I think we're just maintaining our focus around our capital discipline and our financial priorities. And that production growth rate at 3% is an outcome of those principles and discipline that we've brought to our business.

Betty Jiang

All right. So, let's get into some assets. I do want to want to talk about east Med, but before we get into LNG, I wanted to ask specifically about your role as the chairman of, let me get this right, Asia Natural Gas & Energy Association. And that's more of a recent advocacy group that I believe has formed. The reason I wanted to ask is because Asia is so important for the future of energy demand, and gas in particular. And this is a group that's combining suppliers, buyers and working with the government to help them with energy policy. So, would love to hear more about that. And then through that work how, sort of where are you seeing that Asia energy policy moving?

Nigel Hearne

Well, if I’d known you were so interested, you could have joined my board meeting at 4:00 a.m. this morning. We actually had an ANGEA board meeting. That's the Asia Natural Gas Energy Association. For those who don't know, actually Chevron took a really lead and instrumental role in setting that up. It's an organization of about two years old that I chair. We actually recruited the CEO, who's actually celebrated his first year anniversary on the 1st of September. What really came is we saw a need for the role of natural gas as part of the energy transition, whether that solution be part of LNG, ammonia to hydrogen, part of a hydrogen value chain, or even part of the LNG hydrogen, ammonia and CCS value chain. What you see is a lot of the resource-rich countries weren't necessarily the countries that had the demand need. And after spending a lot of time talking to customers in the LNG business, and folks don't know, I used to work in Australia in our Gorgon and Wheatstone assets. It was really understanding some of the policy changes that were going on in Australia and in Asia and the demand for resource. It goes back to the fundamentals of the business. Long-term, Asia's going to need a lot more natural gas. A lot of the countries that need it don't have some of the resource positions that they require, and they're looking to import or rely on the countries that do have advantaged natural gas to export. And we felt there was a unique position to bring both suppliers or resource holders with customers to start advocating more effectively for what's the right policy to enable and support an appropriate and effective energy transition.

Too often, I've seen many people talk about the first few chapters of the energy transition, and people talk about the last few chapters, each thinking the other one is wrong, when the reality is they're probably both right, and the emphasis needs to be on how do we get those middle chapters put together? So, and what that enabled was a business-to-business relationship, a business-to-government advocacy, and then a government-to-government advocacy. So, we're starting to put together a little bit more definitive framework around the role of each asset or country or company can play in that energy transition, because I'm confident, not one company, not one industry and one country is going to solve the energy transition or the energy mix of the future for Asia. So, that's what ANGEA has done. It was a different but very small and targeted advocacy group. I feel proud of what we've done in the first couple of years of getting going. More to come. We just set our priorities out for the next 12 months, particularly around three policy areas we want to impact. And the harder thing is saying what you're not going to do when you've got lots of good things to go work on, so.

Betty Jiang

That's great. And does that give you confidence - the bottom line, did that give you confidence that the gas demand is there and then is going to show up in a meaningful way?

Nigel Hearne

At the end of the day, there's got to be policy that develops resources so that it can access the market that needs it the most. And I'm getting more confident, but if you don't try these things and try and educate people, you won't - local policy is not going to create the right policy for the region. So, it's about setting the right policy framework across the region to both export low cost, low carbon, natural gas for markets that need the most.

Betty Jiang

Got it. So, on the supply side, East Med, it's an exciting - a new opportunity for Chevron there. So, talk to us about the growth potential. What's the plan? And is that going to be the next LNG hub to watch there?

Nigel Hearne

So, maybe I'll start with what we have in our portfolio today. We have 175 TCF of natural gas in that portfolio. The world is going to need more natural gas. We just talked about why that is, particularly, as you say, it's Europe today. It's Asia tomorrow. So, we have a great natural gas position, and our advantaged assets are really in Australia and North America, where we produce low-cost natural gas. And as you think about our overall natural gas position that we have, first and foremost, as we think about playing to our strengths, we can compete in both the Pacific Basin from Australia, and we'll have a growing position in the Gulf Coast as our advantaged Permian associated gas, and we take some export capacity in 2026, and 2027, we'll be able to grow our position in the Atlantic Basin. Both of those are very complimentary. We’ll also have positions in West Africa.

So, in our current portfolio, our emphasis is on keeping our existing infrastructure full in a cost-effective way. So, in Australia, it's about the backfill projects, developing future fields, getting to high utilization rates at Gorgon and Wheatstone, same in West Africa around keeping those facilities full, a key part of underpinning our LNG portfolio. As you start to go to Eastern Med, then it's about taking advantage of the growing positions. So, how do we grow an advantaged position of scale? We have producing assets. We have resource positions, and we have an exploration play. It's about bringing those together to create what I talked about earlier, a scaled and advantaged position where you can compete.

Today, we're supplying gas in the region to Jordan, Israel and Egypt. We've got presence in Israel, Egypt, and Cyprus. So, it's about bringing that mix together to create a competitive position. What are we doing today? We're expanding at Leviathan. So, we've added a third trunk line from the gas-gathering field. It's highly accretive project to the platform to go from 1.2 to 1.4 BCF a day. Again, there's a lot of demand in the market there locally. At Tamar, we've done our - we FID’d - sanctioned our first phase of that optimization project late last year to optimize the platform. We're going to do the same with some midstream infrastructure, either late this year or early next year, which will see that asset go from around 1.1 BCF f a day to 1.6 BCF f a day. Then the question is, with the remaining resource and the position we're taking to develop and strengthen that region is evaluating LNG opportunities. Floating LNG primarily is our current focus, where you can actually take the resource position we have with an LNG position. It doesn't have to be floating LNG, but that looks to be the most likely concept. We're in concept development. We're not there yet. It'll probably be the early part of next year. And then thinking about additional LNG resources that would complement our other LNG portfolio assets.

Betty Jiang

Shifting gears to Gulf of Mexico, it’s a growth area. So, where is the growth coming from? There's always the perception of it's not onshore, it's not unconventional. It's perhaps less repeatable, but clearly the portfolio, there's a lot of opportunity in there. So, tell us about that.

Nigel Hearne

I like our Gulf of Mexico assets. It's a growing business. We're going to be growing about - from 200,000 to 300,000 barrels a day. We've got a proven track record of strong performance. We've got a great resource position. We're one of the largest acreage holders. We added 73 new blocks of exploration opportunity. We've got some developing - we've got some infrastructure already in the Gulf. We've got a mixture of brownfield and greenfield projects developed that underpin our growth. And the focus, actually, as you say, it's not onshore and it's not shale and tight, but a lot of our emphasis is about driving to returns. And one of the ways you do that is to take a similar factory approach that you have in the shale and tight, apply it in the Gulf of Mexico. So, it's about where we can short cycle tiebacks, leverage existing infrastructure, standard designs, shortening cycle times, getting a mixture of new greenfield and brownfield development, and then a standard of application of technology to scale and replicate quickly. So, it's a different model than perhaps when we were in the Gulf of Mexico 10 or 15 years ago. It's much more returns-focused. It's much more focused on driving value. And again, it's about creating a scale and advantaged position in the basin. I'm excited about the opportunity as it comes. It is part of our growth story. We have projects coming online. We had the Mad Dog project come online this year. We have two projects coming on next year in Anchor and Whale, and then we have a Ballymore project, which is a short-cycle tieback, which is a brownfield come online in 2025. So, these are all good things to be excited about and they’re all part of underpinning our growth story.

Betty Jiang

Right. It's really interesting to see the cross pollination of knowledge from onshore to offshore and then how offshore is no longer the offshore that we've known in years past. So, excited to see these opportunities there. Maybe shifting to low carbon, and just have a few minutes left. It's been a little over a year since passage of the IRA, which was an incredibly powerful legislation in the US, providing incentives for a lot of new energy business that are [Technical Difficulty] where energy sector can make a difference. That's carbon capture, hydrogen, renewable fuels. So, since the passage of that bill, how has Chevron reevaluated any opportunities in your portfolio, where have things becoming more interesting, has the opportunity set really expanded? And yes, just what has the last year brought for new energy for Chevron?

Nigel Hearne

Yes. So, I'll go back to, we're leveraging our strengths to safely deliver lower carbon energy. So, what does that look like? We're lowering the carbon intensity of our base operations, reducing flaring, energy management, methane reduction. I said earlier, we're one of the lowest methane - we've benchmarked extremely well against our competition in the United States, with 62% lower methane emissions on average. We're also doing some new things. As you start to think about what we're doing in our traditional business, integrating new products and new solutions into our existing business.

So, we've added a new liquid fuel business in renewable energy group. We're now the second largest producer of bio-based products. We're still working to secure feedstock as we start to grow our - we intend to grow our renewable natural gas, our renewable or bio-based diesel and sustainable aviation fuels to around 100,000 barrels a day by 2030. What does that require? New capabilities, new technology, feedstocks. So, we've acquired REG. We've got a joint partnership with Bunge, where we're securing feedstocks, which is a key part of actually the future value chain of the renewable fuels integrated into our traditional hydrocarbon value chains. We've got partnerships with Calbio and Brightmark where we're getting dairy feedstock to build out our renewable natural gas stations. We've got 58 renewable natural gas points now in our CNG network. And then you start to think, well, what's the new technologies? And we're thinking about what solutions can we bring? How can you apply them at scale and how can you apply them at speed? The IRA helps. It really helps with some of that investment.

So, some of the things we're looking for is in the CCS space, how do we take a core acreage position that has the ability to store carbon dioxide. It has policy that supports it, and it's near emitters where you have customers. So, an example of that is in the Bayou Bend where we've got 140,000 acres. We believe that we could store up to a billion tons of carbon dioxide. So, when you say, as you start to evaluate those opportunities, the IRA is helpful. I think it's helping enable some lower carbon solutions. But in Chevron, we believe that we need a robust set of policy to enable more energy forms to come to market. We're all going to need more diverse, more complex, and more energy solutions to come to market domestically. So, the IRA plays a role, but it's not the only thing. Policy is going to be important. Infrastructure is going to be important. Believe it or not, markets and customers are going to be important. As you create new products, you have to have markets and customers to do that. So, as I think about the broader energy transition, the IRA is helpful. It's a good start. I don't think it fundamentally changes how we think about our business going forward in the long term. I know one thing that the energy system of the future is going to look, we need more of it, but it's going to look more complex, and it's going to be more diverse, and it's going to require energy companies like ours to integrate those solutions to create the most effective, affordable, reliable, and lowest carbon intensity solutions for the future.

Betty Jiang

That's a perfect And wrap. I can't think - I can’t say any better, but thank you so much, Nigel, for being here. It's really been a treat.

Nigel Hearne

Thank you.

[Jon Koplik] WSJ : diesel prices / feedstocks to oil refineries / which oil is in short suppl...

Jon Koplik — 9/6/2023 10:08:48 PM

WSJ : diesel prices / feedstocks to oil refineries / which oil is in short supply / etc. ..................

ENERGY & OIL

Sept. 6, 2023

Saudi Cuts Send World Diesel Prices Soaring

European refineries have been starved of both Russian and Middle Eastern crude

By Anna Hirtenstein

One corner of the global energy market is getting especially squeezed by Saudi Arabia and Russia’s oil-production cuts: diesel.

Diesel prices have climbed more than 40% in the U.S. and Europe since May, when surprise output cuts by Saudi Arabia and some other members of the OPEC+ oil cartel took effect, Argus data showed. Most actively traded futures prices for Brent crude and West Texas Intermediate, the benchmarks for crude oil, are up 13% and 14% in the same time frame.

The run-up is translating into higher pump prices and trucking costs in the U.S. and elsewhere in the West. It reflects the fact that heavier kinds of oil are better suited to making diesel, while others, such as lighter U.S. crude, are more readily turned into gasoline.

In the U.S., while the national average price for unleaded gasoline added 7 cents a gallon in August, according to AAA, the cost of diesel rose by 42 cents a gallon.

“Diesel is more heavily affected because of the type of crude that’s being taken out of the market,” said Alan Gelder, vice president for refining, chemicals and oil markets in Wood Mackenzie’s commodities research business. “Saudi’s oil provides a higher yield for diesel than lighter crude oils. This loss adds further cost to the economy.”

Saudi Arabia said Tuesday that it will extend its current cut of one million barrels of oil a day through to year-end. Traders and analysts had widely anticipated that the policy would last through to October, so the longer time frame surprised the market. Russia’s deputy prime minister, Alexander Novak, said Russia will also keep its 300,000 barrel-a-day output cut through the end of 2023.

Europe is hardest hit because its refineries were designed to process a steady stream of Russian feedstocks. But these supplies have largely wound down because of sanctions in the wake of the Ukraine invasion.

Russia’s medium-sour crude is similar to oil from the Middle East, meaning Saudi oil has commonly been used as a replacement, analysts say. The kingdom’s output cuts have made this type of crude harder to obtain.

“Europe has had more than a year to get used to this situation with Russia and for natural gas, it has adapted. But this diesel issue hasn’t been solved,” said Bjarne Schieldrop, chief commodities analyst at SEB. “And this issue is spilling into diesel markets everywhere.”

Shell operates Europe’s largest refinery in Rotterdam, the Netherlands. The Pernis facility used to churn out large quantities of diesel made with Russian feedstocks. After the Ukraine invasion, it turned to Saudi sour crude as its main input for this product. Now, it is buying more U.S. crude and producing less diesel.

Prices for sour crude have risen, with the Dubai benchmark recently at a 10-month high. Heavier, sour oils are typically cheaper because they are harder and more expensive to refine, but prices have overtaken those of lighter, sweeter crudes. They recently traded at the widest premium in over a year, Argus data showed.

Diesel has become one of the biggest trades in energy markets. Leveraged funds, or investors that trade using borrowed money, recently amassed the largest net long position in 22 months in heating-oil futures, one derivative of diesel, Commodity Futures Trading Commission data showed.

But the surge is bad news for consumers. Diesel powers trucks and trains that transport goods to end users. Higher fuel costs can feed into elevated prices in stores, as companies pass them along to consumers.

“It’s used in the delivery of everything in the last mile. High diesel prices mean delivery costs to supermarkets and other shops are high. It makes inflation more sticky,” said Wood Mackenzie’s Gelder. Diesel is also commonly used to power agricultural and industrial machinery.

About 42% of European Union cars run on diesel, according to the European Automobile Manufacturers’ Association, so higher prices also hit many consumers directly.

Some analysts are concerned that diesel prices could increase sharply during the colder months, particularly if China repeats last winter’s curbs on exports of oil products.

-- Bob Henderson contributed to this article.

Copyright © 2023 Dow Jones & Company, Inc.

.
.
.

[sixty2nds] Good morning Bob, Lets not forget the Dividend and buybacks OR The Chevron worl...

sixty2nds — 7/26/2023 6:41:30 AM

Good morning Bob,

Lets not forget the Dividend and buybacks
OR
The Chevron worldwide NG holdings acquired in the Noble deal.
It is not being talked about.
It will be.

Want to put a smile on your face?

Take a look at the Monthly CVX and EPD charts.
Use a 10 year time horizon.

Stay in the shade!
60

[robert b furman] Hi Sixty, Great leader, solid balance sheet, leaner aggressive costs, better fu...

robert b furman — 7/25/2023 9:35:49 PM

Hi Sixty,

Great leader, solid balance sheet, leaner aggressive costs, better future with variable earnings per commodity prices. I'm glad I own their shares.

Bob

[sixty2nds] seekingalpha.com

sixty2nds — 7/24/2023 10:37:46 AM

[sixty2nds] Chevron posts better than expected Q2 earnings, taps Bonner as new CFO Jul. 23,...

sixty2nds — 7/24/2023 10:35:28 AM

Chevron posts better than expected Q2 earnings, taps Bonner as new CFO

Jul. 23, 2023 7:09 PM ET Chevron Corporation (CVX)By: Carl Surran, SA News Editor 43 Comments

Justin Sullivan/Getty Images News

Chevron (NYSE: CVX) reported preliminary Q2 earnings Sunday totaling $6.01B and adjusted earnings of $5.77B, or $3.08/share, above the $2.97/share Wall Street consensus estimate.

The results were below Q1 earnings of $6.57B and year-ago quarterly earnings of $11.62B, as well as adjusted earnings of $6.74B in Q1 and $11.36B in the year-earlier quarter.

Chevron ( CVX) said its Permian Basin production set a quarterly record in Q2, rising 11% Y/Y to 772K boe/day, and is on track to meet its full-year guidance.

Q2 shareholder distributions hit a quarterly record $7.2B, including $2.8B in dividends and $4.4B in stock buybacks.

The company is scheduled to report full quarterly results on July 28.

Chevron ( CVX) also said CFO Pierre Breber will retire next year, to be succeeded by Eimear Bonner, current VP and chief technology officer, effective March 1.

Breber joined Chevron ( CVX) in 1989, becoming VP and CFO in 2019; Bonner joined the company in 1998, assuming the positions of VP and CTO in 2021.

Finally, Chevron's ( CVX) board waived the company's mandatory retirement age of 65 for Chairman and CEO Mike Wirth, who will turn 63 later this year.

More on Chevron:

Financial and valuation comparison to sector peers Analysis: Chevron: A Capital Return Record That Speaks For Itself Stock price return: Down 9% YTD, up 9% in the past 12 months

[robert b furman] Hi Jon, Exxon to buy Denbury for $89.45/share in all-stock deal Jul. 13, 2023 ...

robert b furman — 7/13/2023 9:07:49 AM

Hi Jon,

Exxon to buy Denbury for $89.45/share in all-stock deal

Jul. 13, 2023 8:21 AM ET Exxon Mobil Corporation (XOM), DENBy: Carl Surran, SA News Editor 8 Comments

Spencer Platt/Getty Images News

Denbury (NYSE: DEN) +0.8% pre-market Thursday following news that Exxon Mobil (NYSE: XOM) agreed to acquire the developer of carbon capture, utilization and storage solutions in an all-stock transaction valued at $4.9B, or $89.45/share, a 1.9% premium to Wednesday's closing stock price.

Under the deal terms, Denbury ( DEN) shareholders will receive 0.84 shares of Exxon Mobil ( XOM) for each Denbury share.

The acquisition Exxon ( XOM) with the largest owned and operated CO2 pipeline network in the U.S. at 1,300 miles, including nearly 925 miles of CO2 pipelines in Louisiana, Texas and Mississippi, as well as 10 onshore sequestration sites.

"Once fully developed and optimized, this combination of assets and capabilities has the potential to profitably reduce emissions by more than 100M metric tons/year in one of the highest-emitting regions of the U.S.," Exxon Mobil ( XOM) Low Carbon Solutions President Dan Ammann said.

In addition to Denbury's ( DEN) carbon capture and storage assets, the acquisition includes Gulf Coast and Rocky Mountain oil and natural gas operations, consisting of more than 200M boe of proved reserves with 47K boe/day of current production.

[Jon Koplik] Barrons / interesting idea : oil stock ignorers -- would have to start buying sh...

Jon Koplik — 5/24/2023 12:11:51 AM

Barrons / interesting idea : oil stock ignorers -- would have to start buying shares ............................

From : cover story this week

Barrons

May 19, 2023

10 Stocks to Play a Resurgent Energy Sector, From Our Roundtable Experts

Our energy roundtable predicts higher crude prices as global demand grows. What’s ahead for shale, energy transition.

By Avi Salzman

---------------------------------------

comment from Christyan Malek, global head of energy strategy and head of Europe, the Middle East, and Africa oil and gas equity research at J.P. Morgan

---------------------------------------

<<<<< I meet with a lot of the CIOs [chief investment officers] in Europe. I asked one in Sweden, “At what point would you get involved in energy?” And he said, “Once it gets to 7% to 8% of the index, we have a problem. Then you are under-performing your own [stock market] benchmarks.”

There’s a pain threshold. It has been OK not to be in energy, because it has underperformed, so there has been no FOMO [fear of missing out]. But as energy outperforms, then it starts to become a larger part of the index and you can’t ignore it. >>>>>

-------------------------------------

a chart (which I cannot copy here), had this :

<<<<< Energy stocks account today for less than 5% of the benchmark U.S. stock index [ the S&P 500 index ], down from 16% in 2008. >>>>>

Jon.

.
.
.

[sixty2nds] blog.gorozen.com

sixty2nds — 3/9/2023 10:29:46 AM