Tag: tank terminals

For years, BP has been tipped as a potential target of the next mega-merger deal in the oil industry.

Speculation about a blockbuster acquisition involving BP resurfaced again this year after activist hedge fund Elliott bought nearly 5% in the UK-based supermajor and demanded changes, big and fast.

BP’s shares have underperformed the stocks of the other four of the Big Oil group – Shell, TotalEnergies, ExxonMobil, and Chevron – ever since 2020.

Neither former BP CEO Bernard Looney, with the push toward renewables, nor his successor Murray Auchincloss, with the strategy reset to return on the path of oil and gas, have managed to erase the company’s underperformance in the past five years.

Speculation about another oil giant taking over BP is not new—such rumors have been swirling for over a decade, particularly ones suggesting that Shell could be the bidder for a merger with BP.

But this year, Elliott’s aggressive approach to the companies in which it buys significant stakes has rekindled speculation about BP becoming a target of the next mega-merger deal in the global oil industry.

Analysts aren’t ruling out anything, not even one of the U.S. supermajors – Exxon or Chevron – approaching BP for a potential deal.

At the start of this year, 6 out of 50 M&A experts surveyed by Bloomberg mentioned BP as one of Europe’s top mergers and acquisitions targets for 2025. BP collected the fourth-highest number of votes from these experts, after mining giant Anglo American, French video-game company Ubisoft Entertainment, and UK broadcaster ITV.

Elliott’s demands for changes in strategy, board reshuffles, and a swift turnaround of the stock performance have prompted analysts this year to speculate about which potential suitor could be best positioned to take over BP.

A year ago, reports emerged that Abu Dhabi National Oil Company (ADNOC) had weighed buying BP, but talks didn’t go far, and ultimately, the state firm of the United Arab Emirates decided not to pursue a takeover of the UK supermajor.

A national oil company in the Middle East could be one possible BP suitor, considering BP’s presence in the region, especially in Iraq, where BP has just been given the go-ahead to a $25-billion contract to develop Kirkuk oil fields.

Yet, analysts tend to speculate more about a Shell-BP merger of equals or a potential Chevron approach for BP if the U.S. supermajor fails to complete the deal to buy U.S. Hess Corp.

BP also has a huge presence in the U.S. oil industry.

In the U.S. Gulf of Mexico, BP looks to boost its production capacity to more than 400,000 barrels of oil equivalent per day by the end of the decade, the company said this week as it announced an oil discovery in the deepwater U.S. Gulf of Mexico 120 miles off the coast of Louisiana.

The discovery at the Far South prospect comes as BP announced a few weeks back a strategy reset to shift focus back to growing oil and gas production and investments after a few years of trying to be an integrated energy company with a major presence in renewables.

In a very unfortunate development for BP, any positive share performance from the strategy reset was obliterated within a month by the tariff and trade wars, which crashed the price of Brent Crude oil to the low $60s per barrel.

Lower oil prices could test BP’s ability to sustain its returns to shareholders, including dividends, especially as the supermajor flagged an increase in its net debt in the first quarter of 2025.

The pressure from Elliott on BP to boost returns and stock performance is likely to continue, as well as speculation over whether or not a split or acquisition of BP would give investors more bang for their buck.

As for who the potential buyer could be, Allen Good, director of equity research at Morningstar, told CNBC, “I wouldn’t take anything off on the table.”

By Tsvetana Paraskova,  Oilprice.com / Apr 17, 2025

Another oil refinery will soon be closing in California.

That’s in addition to a refinery already scheduled to close before the end of this year, 2025.just a few months from now.

Wednesday’s announcement now setting off alarm bells in Sacramento, throughout the state… and beyond.

“Our fuel supply is in jeopardy,” cautioned valley Congressman Vince Fong. “This is not a distant concern. This is not an academic conversation. This is happening right now!”

The news broke Wednesday morning.

Valero Energy Corporation announcing that its subsidiary, Valero Refining Company-California, had submitted notice to the California Energy Commission of its intent to idle, restructure, or cease refining operations at Valero’s Benicia refinery” by the end of April, 2026.

California Governor Gavin Newsom was at a news conference in Stanislaus County when asked about the announcement

“I can assure you, beginning last night we had all hands and we’re in the process of addressing any anxiety that may be created or any market disruption that may be created by that announcement,” reassured Newsom.

But, the “anxiety” was already in motion. Gas Buddy-dot-com’s Senior Petroleum Analyst Patrick De Haan posting on X;

“It’s clear that the political environment in California has been hostile to refiners, and the state badly needs to revise its mentality or face a declining number of refineries and higher prices.”

It was a sentiment that was echoed by valley congressman Vince Fong.

“This is something that is not created by the market,” Fong asserted. “This is something that is directly caused by Gavin Newsom’s poor energy policies.”

Policies such as ABX2-1 signed into law by Governor Newsom October 14th of 2024, tightening the state’s control over the California transportation fuels market.

Policies that Fong says, he and others warned the governor about.

“Not only did I warn the governor, but the governor of Arizona and the governor of Nevada,” Fong exclaimed. Arizona and Nevada. they both warned the governor, bipartisan concern, that this was going to lead to shortages and this was going to cause refinery closures

along with higher gasoline prices, job losses and not enough energy to power or attract new businesses to the state,” Fong continued.

“What can the governor do to change that,” I asked.

Fong answered, “We got to act now. We actually have to begin to reevaluate our entire energy policy of the state, remove the obstacles, remove the mandates, the restrictions and the barriers that are holding us back and provide the incentives and investments to not only build more energy infrastructure but to expand our energy production.”

“Hopefully the governor hears you,” I replied.

“I hope so too,” Fong responded.

Patrick De Haan, the oil industry analyst we mentioned earlier in this story, put some more numbers to what the closure of Valero’s Benicia refinery will mean, posting

“WOW: Valero will be shutting down its 170kbpd (thousand barrels per day) Benicia, Ca refinery by April, 2026. Coupled with the loss of $psx’s (Philipp 66’s) 139kbpd Los Angeles refinery later this year, will drop the number of refineries in California to just 7. A 309-thousand barrel per day loss in refining capacity is huge.”

The California Policy Center says California refineries process just over 1.6 million barrels worth of oil per day.

According to the U.S. Energy Information Administration, California is projected to consume about 1.85 million barrels of crude oil per day.

Two weeks ago we reported that Chevron plans to layoff or relocate about 600 employees from its headquarters in San Ramon out-of-state to Houston, Texas,

and Philipps 66 announced last year it’s Los Angeles refinery will be closing this year in just a few months.

According to representative Fong and several other sources, at one time in the late seventies, somewhere between 40 to 50 refineries were operating in the state of California.

Depending upon who you talk to, that number is now down to about 7 full refineries and 5 smaller, privately owned refineries.

So what do you think?

Is it time for state lawmakers to change policies to bring more oil refineries back to California?

We would really like to know your views on this.

By Monty Torres / Thu, April 17th 2025

 CB&I and a consortium including Shell International Exploration and Production, Inc. (Shell), a subsidiary of Shell plc, GenH2 and the University of Houston today announced the completion of a first-of-its-kind, affordable, large-scale liquid hydrogen (LH₂) storage tank concept at NASA’s Marshall Space Flight Center (MSFC) in Huntsville, Alabama, that will enable international import and export applications.

“Our collaboration with this world-class project team will help provide a path to low-cost, large-scale liquid hydrogen storage,” said Mark Butts, President & CEO of CB&I. “We are proud to leverage our six decades of experience with cryogenic insulation and storage to advance innovative solutions for the energy transition market.”

The project, which began in 2021 and is supported by the US Department of Energy (DOE), developed a novel non-vacuum tank design concept for large-scale (up to 100,000 cubic meters) storage of LH₂ that is anticipated to provide a substantial cost advantage over conventional vacuum insulated tanks. This concept is being demonstrated through the construction, startup and testing of a small-scale LH₂ demonstration tank at NASA MSFC.

“At Shell, we believe in the power of collaboration to advance technology and scale up innovative solutions,” said Theo Bodewes, General Manager, Hydrogen Technology. “With the invaluable support from the DOE, this project demonstrates how experts from industry, academia, and government can solve complex technology challenges. This novel liquid hydrogen technology promises to be more competitive, reducing costs and accelerating large-scale storage commercialization.”

The demonstration tank will significantly increase the MSFC hydrogen test facility’s LH₂ storage capacity and be used to characterize the behavior of materials under cryogenic conditions, mimicking normal fill and empty cycles and testing non-vacuum insulation materials. In addition to an estimated six-month test period included in the project scope, a Space Act Agreement among the partner organizations provides for MSFC’s use of the tank over a five-year period, during which CB&I and Shell will continue to test new insulation technologies under non-vacuum conditions.

“We take pride in participating in this industry collaboration to advance commercial liquid hydrogen storage applications,” said James Fesmire, GenH2 Chief Architect. “This initiative has allowed us to develop testing capabilities for thermal insulation systems and produce essential data for unlocking the global potential of liquid hydrogen.”

“This project is an example of a novel design brought to fruition by a partnership of academia, government agencies, and the energy companies,” said Dr. Ramanan Krishnamoorti, Vice President of Energy and Innovation at the University of Houston. “The ability to store liquid hydrogen at scale using a non-vacuum design is a pivotal advancement and opens the door to a more flexible, affordable global hydrogen trade infrastructure. Innovative solutions such as this will be key to advancing our energy economy.”

“This first-of-its-kind concept is a great example of unleashing American energy innovation – a key priority for the Department of Energy. Through collaborative expertise from industry, academic, and government agencies, this work can contribute to America’s leadership in growing global markets for hydrogen and hydrogen-based fuels and offer greater opportunities for American energy operators to store, deploy, and export liquid hydrogen,” said Dr. Sunita Satyapal, director of DOE’s Hydrogen and Fuel Cell Technologies Office.

CB&I built the first LH₂ sphere for NASA and NASA contractors in the 1960s, with a capacity of 170 cubic meters, and has expanded that threshold over the last sixty years by almost 30-fold to 5,000 cubic meters with a tank completed in 2022 at Kennedy Space Center for the Artemis program. CB&I has completed over 130 LH₂ storage vessels since the 1960s.

The company and NASA have had a partnership of more than 60 years, with CB&I contributing to many NASA projects, including several supporting the Apollo and Gemini space missions.

By: Fuel Cells Works / April 16, 2025.

The American Petroleum Institute (API) estimated that crude oil inventories in the United States rose by 2.4 million barrels for the week ending April 11. Analysts expected a loss of 1.680 million for the week. The API estimated a 1.057 million barrel drop in the prior week.

So far this year, crude oil inventories have climbed more than 24 million barrels, according to Oilprice calculations of API data.

Earlier this week, the Department of Energy (DoE) reported that crude oil inventories in the Strategic Petroleum Reserve (SPR) climbed 0.3 million barrels again to 397 million barrels in the week ending April 11. Inventory levels in the SPR are hundreds of millions shy of the levels in inventory prior to the SPR withdrawal that took place under the Biden Administration.  

At 1:43 pm ET, Brent crude was trading down another $0.32 (-0.49%) on the day, leaving the international benchmark at $64.56. While down on the day, it is a $3 rebound from the lows following the announcement of the Liberation Day tariffs.

WTI was also trading down on the day, by $0.28 (-0.46%) at $61.25—also a $3 per barrel increase over last week’s level.  

Gasoline inventories fell in the week ending April 11, by 3 million barrels, after rising by 207,000 barrels in the week prior. As of last week, gasoline inventories are now at the same level as the five-year average for this time of year, according to the latest EIA data.

Distillate inventories fell this week as well, by 3.2 million barrels in the latest week. In the week prior, distillate inventories fell by 1.844 million barrels. Distillate inventories were already about 9% below the five-year average as of the week ending April 4, the latest EIA data shows.

Cushing inventories—the benchmark crude stored and traded at the key delivery point for U.S. futures contracts in Cushing, Oklahoma—rose by 349,000 barrels, the API data showed, after last week’s 636,000 barrel hike.

By Julianne Geiger, Oilprice.com / Apr 15, 2025

Oil giant BP has been thrust into the spotlight as a prime takeover candidate — but energy analysts question whether any of the likeliest suitors will rise to the occasion.

Britain’s beleaguered energy giant, which holds its annual general meeting on Thursday, has recently sought to resolve something of an identity crisis by launching a fundamental reset.

Seeking to rebuild investor confidence, BP in February pledged to slash renewable spending and boost annual expenditure on its core business of oil and gas. CEO Murray Auchincloss has said that the pivot is starting to attract “significant interest” in the firm’s non-core assets.

BP’s green strategy U-turn follows a protracted period of underperformance relative to its industry peers, with its depressed share price reigniting speculation of a prospective tie-up with domestic rival Shell. U.S. oil giants Exxon Mobil and Chevron have also been touted as possible suitors for the £54.75 billion ($71.61 billion) oil major.

Shell declined to comment on the speculation. Spokespersons for BP, Exxon and Chevron did not respond to a request for comment when contacted by CNBC.

“Certainly, BP is a potential takeover target — no doubt about that,” Maurizio Carulli, energy and materials analyst at Quilter Cheviot, told CNBC by video call.

“I would conceptualize the question of ‘will Shell bid for BP’ in the more general consolidation that it is happening in the resources sector, both oil but also mining — particularly in the past year a lot of companies thought that to buy was better than to build,” he added.

In the energy sector, for example, Exxon Mobil completed its $60 billion purchase of Pioneer Natural Resources in May last year, while Chevron still seeks to acquire Hess for $53 billion. The latter agreement remains shrouded in legal uncertainty, however, with an arbitration hearing scheduled for next month.

In the mining space, market speculation kicked into overdrive at the start of the year following reports of a potential tie-up between industry giants Rio Tinto and Glencore. Both companies declined to comment at the time.

Quilter Cheviot’s Carulli named Chevron as a potential suitor for BP, particularly if the U.S. energy giant’s pursuit of Hess falls through.

Speculation about a potential merger between Shell and BP, meanwhile, is far from new. Carulli said that while the rumors have some merit, a prospective deal would likely trigger antitrust concerns.

Perhaps more importantly, Carulli added that a move to acquire BP would conflict with Shell’s steadfast commitment to capital discipline under CEO Wael Sawan.

‘An existential crisis’

“Never say never, right? I think even Exxon-Chevron in the depth of the pandemic held talks so I think that would have been even wilder to say,” Allen Good, director of equity research at Morningstar, told CNBC by telephone.

“I wouldn’t take anything off on the table. You know, oil and gas is facing an existential crisis. Now, views differ on how soon that crisis will come to head. I think we’re still decades away,” Good said.

For Shell, Morningstar’s Good said that any pursuit of BP would likely be an attempt to merge the two British peers, as opposed to an outright acquisition — although he said he doesn’t expect such a prospect to materialize in the near term.

Asked about the likelihood of Chevron seeking to purchase BP if a deal to acquire Hess collapses, Morningstar’s Good said he couldn’t rule it out.

“BP certainly doesn’t have the growth prospects that Hess does, but you could get a situation where, again, like I said with Shell, you’d have Chevron acquiring BP, stripping out a lot of costs, certainly the headquarters would no longer be in London … but it doesn’t address the growth concerns ex-Permian for Chevron. So, in that case, I would be a little skeptical,” Good said.

“The issues these companies are facing are to please shareholders, and the two ways to do that really are to reduce costs and return cash to shareholders. So if you can continue to lean into that model somehow, then that’s the probably the way to do it,” he added.

What next for BP?

Michele Della Vigna, head of EMEA natural resources research at Goldman Sachs, described BP’s recent strategic reset as “very wise” and “thoughtful,” but acknowledged that it may not have gone far enough for an activist investor.

U.S. hedge fund Elliott Management has reportedly built a near 5% stake to become one of BP’s largest shareholders. Activist investor Follow This, meanwhile, recently pushed for investors to vote against Helge Lund’s reappointment as chair at BP’s upcoming shareholder meeting in protest over the firm’s recent strategy U-turn. BP has since said that Lund will step down, likely in 2026, kickstarting a succession process.

“I think there are three major optionalities in BP’s portfolio that any activist investor would love to see monetized. The first one is not all in BP’s hands, it’s the monetization of the Rosneft stake,” Della Vigna told CNBC over a video call.

BP announced it was abandoning its 19.75% shareholding in Russian state-owned oil company Rosneft shortly after Moscow’s full-scale invasion of Ukraine in late February 2022. It had marked a costly and abrupt end to more than three decades of activity in the country.

A second optionality for BP, Della Vigna said, is the firm’s marketing and convenience business.

“I mean, within BP, a company that trades on three times EBITDA, there’s a division that can trade at 10 times EBITDA, right? Amazing. You can make the same point for a lot of the other Big Oils,” Della Vigna said.

EBITDA is a standard metric that refers to a firm’s earnings before interest, tax, depreciation and amortization.

“The third option is BP is a U.S.- centered energy company — and it’s clear, right? BP is the most U.S.- exposed of all the majors, more than Exxon and Chevron,” Della Vigna said, noting that 40% of BP’s cash flow comes from the U.S.

“So, being listed in the U.K., when the U.K. gets you the biggest discount of any other region in Big Oil, doesn’t feel right. I think some form of relocation or transatlantic merger may be worth considering,” he added.

By: Sam Meredith, cnbc / Apr 15 2025.

ASCO extends its partnership with Repsol Norge, securing a three-year contract for logistics and base services at Tananger and Farsund, Norway

ASCO has been awarded a contract with Repsol Norge AS, ensuring the continuation of logistics and base services at critical points in Norway’s oil and gas supply chain. 

The agreement, which locks in three years, covers work at the Tananger and Farsund bases.

ASCO is set to continue its comprehensive management of warehouse operations, cargo handling, helicopter coordination and customs processes, crucial elements for Norway’s energy sector operations.

For professionals in Norway’s energy sector’s supply chains, this contract represents job security and infrastructure stability, reinforcing the logistics framework for one of Norway’s key energy firms.

Since 2011, the collaboration between Repsol and ASCO has been a keystone in Norway’s energy operations.

For ASCO, being chosen again is a clear sign that their supply chain expertise is delivering on what Repsol needs.

Øyvind Salte, Commercial Director at ASCO Norge AS, says the company is ready to build further on that foundation: “We are grateful to Repsol for continuing to trust ASCO with its base and logistics services.

“This contract reinforces our strong partnership and allows us to further develop as a company while remaining a preferred and proud supplier to Repsol. It also strengthens our existing operations in Norway, providing a solid foundation for continued collaboration.

“We remain committed to simplifying, streamlining and digitising logistics delivery to enhance efficiency and service quality.”

ASCO’s responsibilities under this contract extend beyond basic warehousing.

The firm also manages cargo logistics, waste handling, transport and customs, as well as offering personnel support for logistics coordination and helicopter operations.

This is vital for the demanding offshore supply environment of the Norwegian Continental Shelf.

Strategic logistics for energy’s most vital region

This development is critical for maintaining a reliable supply chain infrastructure within one of the most influential energy-producing regions worldwide.

Norway supplies approximately 3% of the world’s natural gas and 2.3% of oil and effective logistics are critical in maintaining this efficiency.

Since the Russian gas crisis, European energy security has leaned heavily on Norwegian supplies and that trust has required flawless logistics.

The offshore infrastructure here is mature — platforms, pipelines and processing plants are already in place, which means any support work has to be precise and efficient to match production timelines.

ASCO’s operations at Tananger and Farsund are integral to this supply chain, managing the seamless transfer of materials, equipment and personnel that drive offshore exploration and production activities forward.

Digital tools, lean processes and long-term alignment

By continually advancing towards digital logistics solutions, ASCO aligns with broader industry trends focusing on cost reduction and environmental sustainability. 

In high-value sectors like oil and gas, those gains don’t just save money — they improve safety, reliability and responsiveness.

That alignment is part of what makes this new deal with Repsol work.

For the Spanish energy firm, operating efficiently in Norway is not just about productivity — it’s also a matter of staying competitive in a region with some of the highest standards and expectations in the world.

Norway itself is also investing in long-term energy resilience. Its sovereign wealth fund, the largest globally, draws heavily from oil and gas revenues and exploration on the Norwegian Continental Shelf continues.

Even with production expected to decline after 2025, new technologies and frontier projects in places like the Barents Sea are helping offset the fall.

By Jasmin Jessen, Energy Digital  / April 14, 2025.

Repair of storage tanks can be a major expense for oil, gas and petrochemical facilities.

Corrosion can lead to leaks, environmental damage and even the shutdown of operations, costing millions of dollars a day. Identifying products and processes that reduce downtime for repairs and extend the time between repairs is critical.

Industry standards and recommended practices highlight biggest challenges

API Recommended Practice 652 provides guidance on achieving effective corrosion control in above-ground storage tanks by application of tank bottom linings. Tank bottom linings are the key to preventing internal corrosion of steel tank bottoms because when stored, oil and water separate due to gravity. Water falls to the bottom due to its heavier weight and then acts as a corrosive because of its electrolytic properties. To minimize this corrosion and the downtime it can cause, industry has focused on improvements in tank bottom lining materials, surface preparation, lining application and cure speeds.

Lining innovation driven by storage tank design

Storage tanks come in a variety of sizes, with diameters sometimes exceeding 250 feet. As tanks have gotten bigger with increasing demand for storage and processing, the properties of the floor linings — and their ability to perform under greater commodity loads — have become critical.

The design of storage tank bottoms presents special challenges to linings. Tank floors are typically lap plate construction, consisting of a set of steel plates joined together using lap welds. Linings must be able to adhere and provide adequate edge retention at these weld joints. Floating roof tanks, which feature support legs and welded-in-place contact striker plates on the tank floor, also offer tests which the lining must address.

Finally, effective linings must take account of the way repairs are made to storage tank bottoms. When tank floors are compromised, plate steel is usually scabbed over holes or other severely pitted surfaces, creating an irregular surface.

To handle all these challenges, lining manufacturers have focused on 100% solids, high-build solutions with greater film thickness, excellent flexural modulus and elongation characteristics, and edge retention properties. Some are strengthened with ceramic beads, glass flakes or milled fiber reinforcements to provide even greater durability and resilience.

There are several variables that owners should consider when choosing a Maintenance, Repair and Operations lining for their storage tanks.

Ease and speed of use: The ability to spray at high temperature and pressure and achieve high film build quickly is critical to fast turnaround times. This is the key benefit of newer 100% solids solutions, which leverage plural component spray systems to reduce time and labor costs, versus solvent-based, multi-coat systems. These 100% solids systems have also shown to last up to two times longer.

Geographical location and time of year: Solutions that work well for tanks in Calgary may not be optimal for those located in Texas. A low-temperature-cure solution, for example, is probably not the best for repairs done in high heat.

Stored temperature of the commodity: The temperature of the commodity being introduced into the tank will also impact the appropriate lining solution. If the commodity needs to be heated, it may cause thermal shock to a tank in a cold location, necessitating a specific kind of lining that can resist thermal shock and elevated temperatures.

Purity of the commodity: Another factor is the type of commodity being stored, such as traditional unleaded vs. ethanol-based gas, or commodities with colorants added. Additives can attack linings in various ways causing them to leach into and contaminate the commodity.

One system for both pinhole and major repairs: Most contractors doing storage tank maintenance will do a spark or holiday test to check for pinholes or voids at the same time they are checking for more significant repairs. Having a lining system that can be applied in both a hot pot/single leg, brush and roll process as well as via a plural component spray system will make the contractor’s job easier and quicker.

Many coatings manufacturers offer a range of 100% solids, high-build systems for tank bottom repair. What differentiates them is their level of knowledge and experience with specific commodities and locations. Field service capabilities and a network of trained contractors also play a critical role in ensuring tank maintenance goes as smoothly as possible.

With the critical nature of petroleum tank linings, owners often desire to see test results for the specified internal linings in an autoclave at specific temperatures, pressures and commodities for added piece of mind.

By:  Kevin Morris, Bicmagazine / 02 April 2025

While oil and gas companies have voiced support and even enthusiasm for the administration’s “drill baby drill” policies, survey data and anonymous comments from oil and gas companies released last Thursday from the Dallas Fed’s energy survey for the first quarter reflects a different perspective.

Uncertainty rises to the fore

A major theme in survey respondents’ comments was uncertainty created by the administration’s policies, specifically around tariff-induced price increases, the price of oil and the economic and financial climate. Lower oil prices, nearing if not below breakeven points, also threaten oil companies’ willingness to drill new wells. If the administration succeeds in its goal of $50-60 per barrel oil, the result may be less oil drilling, not more.

Business leaders mentioned “uncertainty” more in the latest survey than in the last five years, sharing comments including the following:

“I have never felt more uncertainty about our business in my entire 40-plus-year career.”

“The key word to describe 2025 so far is ‘uncertainty’ and as a public company, our investors hate uncertainty.”

“Uncertainty around everything has sharply risen during the past quarter. Planning for new development is extremely difficult right now due to the uncertainty around steel-based products. Oil prices feel incredibly unstable, and it’s hard to gauge whether prices will be in the $50s per barrel or $70s per barrel. Combined, our ability to plan operations for any meaningful amount of time in the future has been severely diminished.”

“The only certainty right now is uncertainty. With that in mind, we are approaching this economic cycle with heightened capital discipline and a focus on long-term resilience.”

Higher costs

Oil and gas companies are facing increasing costs, and an administration oil price target of $50-60 per barrel would squeeze the industry’s margin and free cash flow. Tariffs, especially those on steel, are driving up costs across the energy value chain, from drilling to pipelines to refineries and more. Companies focused on natural gas have the benefit of a sunnier outlook for prices that provides more room to recover those costs.

U.S. Interior Secretary Doug Burgum said during the 2025 CERAWeek conference in Houston that he expects savings from deregulation of $6 to $8 per barrel, outweighing tariff-related cost increases. However, 49% of survey respondents estimated their total cost of regulatory compliance ranged between $0 to $1.99 per barrel, and only 9% of respondents estimated their regulatory costs at $6 or more per barrel.

Risk of lowering production

The administration has a goal to increase U.S. oil production by 3 million barrels per day, a 22% increase from recent levels of approximately 13.5 million barrels per day, but the threat of lower oil prices puts this at risk.

In the Dallas Fed energy survey and in the Kansas City Fed energy survey released in January, respondents said the breakeven cost for profitably drilling new wells averaged between $60-64 per barrel. If oil reaches $60, the U.S. risks oil companies delaying plans for new drilling. The risk of slowed drilling and even curtailed production increases further if prices get closer to $50.

Takeaways

Uncertainty around policies and rates of return raises the risk of delayed investment decisions, while unfavorable economics may shelve new projects entirely until conditions improve. Long development timelines for energy infrastructure means that delayed decisions today can have a ripple effect for years to come.

Policymakers must keep in mind that in the U.S., the price of oil is king in determining oil production volumes. The goals of lower oil prices and higher production do not align, and higher costs and uncertainty further complicate the picture.

In the meantime, oil companies must continue their focus on capital discipline and improving operational efficiency. We have seen this already as they streamline assets and business units, as well as look for opportunities to innovate with new technologies that drive further efficiency in production and business operations. Through these, the industry will continue driving costs down and open new opportunities for the next decade of production.

By David Carter, RealEconomy / 01, April , 2025.