Adjustments to Aluminum, Steel, and Copper Import Tariffs

Tariffs on agricultural machinery and residential heating, air conditioning, and ventilation equipment will be reduced to 15% from 25%. Two new categories of steel and aluminum derivative import products (steel racks and aluminum lithographic plates) will be ​subject to ​25% tariffs. The existing category of industrial equipment subject to a 15% tariff will include mobile industrial equipment, such as bulldozers and forklifts, when imported from trade-deal countries entitled to such treatment. To encourage foreign companies to use more U.S. steel and aluminum, the proclamation allows them to qualify for a 10% duty rate if their capital equipment includes at least 85% U.S. melted and poured or smelted and cast steel or aluminum by weight.

New Tariffs

The Trump administration proposed new tariffs of 10% and 12.5% on imports from ‌60 economies because they failed to stop the imports of products made with forced labor. Despite laws banning them, the products of forced labor are deeply embedded in supply chains across the world. The new tariffs are expected to impose a 10% import tax on Mexico, Canada, the EU, Taiwan, Britain, and 9 other trade partners. These trade partners had plans or partial schemes in place, or had made commitments, to address forced labor as part of their U.S. trade agreements. The tariffs will not apply to Canadian and Mexican imports that comply with the rules of origin under the North American trade deal.

The EU has a 2024 law that bans imports of products produced with forced labor, but it does not come into force until December 2027 and lacks key elements, according to U.S. Trade Representative Jamieson Greer. According to the EU, it is committed to the trade deal sealed with the Trump administration last year. It is unclear whether the additional tariffs would exceed those agreed between both sides last July, resulting in a 15% tariff on a broad range of the EU’s exports. According to Britain, it is in regular talks with the United States and is taking action to tackle forced labor, and the preferential access to U.S. markets it had negotiated for UK businesses remains in place. Taiwan was “hopeful and confident” that the final results would reflect agreements already reached, securing relatively preferential treatment.

Another group, including China, India, Japan, and 42 other countries, is being hit with higher levies of 12.5%. China opposes all forms of unilateral tariffs and said there was no forced labor in China. India is engaged with the Trump administration on the Section 301 proceedings, noting that the proposed tariffs were not final. Separate trade investigations that led to a 25% levy on Brazilian imports are expected to affect other trade partners as well.

The new tariffs were proposed with numerous exemptions, including for imports already subject to U.S. Section 232 national security tariffs, such as autos, steel, aluminum, and copper products. The proposal also lists 76 pages of specific product exemptions, including crude oil and petroleum products, rare earths and other ​specialty metals, beef, coffee, certain fruits and vegetables, pharmaceuticals, organic chemicals, and aircraft parts.

Analysis

The Trump administration adjusted tariffs on aluminum, steel, and copper imports to increase investment in the U.S. agriculture and manufacturing sectors. The adjusted tariffs take effect on June 8 and remain in effect through December 31, 2027.  The administration also proposed new tariffs of 10% and 12.5% on imports from ‌60 economies after determining that they did not curb trade in goods made with forced labor. Public comments on the proposed tariffs will be accepted through July 6, with a public hearing scheduled for July 7. The affected countries maintain that they do not understand whether the proposed tariffs are included in, on top of, or in the process of being made under the deals made with the Trump administration last year.

Higher duties on steel, aluminum, and copper, which are critical materials for pipelines, drilling rigs, electrical grids, and transformers, drive up capital costs for oil, gas, and power projects, potentially slowing the record output levels the administration has pursued and raising costs for American consumers and businesses. Exemptions for crude oil and petroleum products offer limited relief, as downstream equipment, construction materials, and supply chain disruptions from broad tariffs still inflate project timelines and expenses.

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“Whenever we went to the rear and saw fields packed with petrol tins as high as a house, rows of guns in their canvas covers waiting to come up, huge dumps of shells, you couldn’t doubt that we could do it.” ~ Alf Lee, Middlesex Regiment, D-Day veteran

6:30 am, June 6, 1944, Allied troops began the first landings along a fifty-mile stretch of the Normandy coastline at Utah and Omaha Beach. By 8:00 am, all other landing zones, Gold, Juno, and Sword Beaches, had Allied troops fighting their way inland. Operation Neptune, also known as D-Day, was the single largest seaborne invasion in military history. Beginning the liberation of Western Europe from Nazi occupation, the D-Day landings provided the Allied forces with the foothold they needed to push to Berlin from the East, South, and West. The success of D-Day came from incredible intelligence, exceptional bravery, and logistical mastery. Planning D-Day was no easy task. With initial planning taking place shortly after the evacuation of the stranded British military and Allied forces from Dunkirk in 1940, the full-scale logistical planning for D-Day took the better part of two years. 

The overall invasion of Western Nazi-occupied Europe is known as Operation Overlord, whereas the naval portion of the invasion is referred to as Operation Neptune. As a whole, upwards of 163,000 Allied troops landed on the beaches of Normandy, transported by an armada of 7,000 naval vessels, 4,000 of which were landing craft and 1,200 warships; an additional 12,000 aircraft supported the invasion. Fueling this invasion force required substantial amounts of oil and gas, as well as ingenuity to transport them; without the millions of gallons of fuel, the invasion could have failed. 

Choosing Normandy and Fueling the Invasion

To this day, D-Day is one of the single greatest military achievements in history. Successfully landing over a hundred thousand troops along with thousands of vehicles, including tanks, and coordinating the thousands of ships required to transport them was a logistical challenge unlike anything before. Preparing the resources required for the invasion took months of supply runs across the Atlantic and the organization of stockpiles across southern Britain. These main stockpiles were established and maintained 24 hours a day by the US Army Quartermaster Corps and included millions of 5-gallon jerrycans that would keep the invasion force fueled and mobile both on the day of the beach landings and afterward.

Given that the United States produced 60% of the world’s crude oil, securing American tankers transporting fuel across the Atlantic was equally critical to ensuring its security once it reached Britain. In addition to Allied supply ships being targeted by German U-Boats, there was an ongoing threat of the German Luftwaffe attacking southern Britain. For this reason, valuable fuel imports were sent to Liverpool, Bristol, Belfast, and Glasgow, which were deemed more difficult for the Germans to reach. Once fuel supplies were processed, they were then transported via the secretly built underground pipeline network known as the Government Pipelines and Storage System (GPSS) to the southern coast in preparation for the immense supply requirements for both the initial invasion and the ensuing campaign to liberate Europe.

To fuel the post-Normandy landings push to Berlin, more than 700 miles away, the Allies needed deep-water ports to maintain consistent supply chains. Once liberated from German control, the French Port of Cherbourg was made the primary docking point for Allied supply lines in late June of 1944, with ongoing repairs being completed by the end of the summer; as the Nazis were forced out, they sabotaged much of the port’s facilities, requiring Allied forces to use temporary ports set up within the first few days after D-Day. Securing port facilities helped the Allies handle large shipments of supplies and reinforcements once the beaches were secure, but because demand for fuel was anticipated to be insatiable, preparations had been made prior to the invasion to build the world’s first undersea pipeline network spanning the English Channel, known as Operation Pluto (Pipeline Under the Ocean). 

PLUTO was an engineering marvel, beginning in Liverpool and Bristol, crossing the Channel, and flowing to Cherbourg. With the flexibility of the material used for the pipelines, the original 21 lines were able to withstand significant pressure and were continuously expanded during the push inland, stretching to the width of Texas; they transported 172 million gallons of fuel to France by the end of the war. Once fuel arrived in France, the Allies needed to maintain an ever-growing supply route to the front lines to sustain a much more rapid invasion pace than anticipated and ensure they had enough fuel. This part of the supply chain, known as the Red Ball Express, carried everything, including rations, petroleum, oil, and lubricants (POL), to every corner of the front lines. The efficiency and 24/7 operation of the Red Ball Express was vital to the war effort, given that by the end of August of 1944, Allied forces in the north were consuming 800,000 gallons of gasoline per day. As the campaign to liberate Europe continued, the volume of fuel required only increased, and, fortunately, so did the Allies’ ingenuity and creativity to maintain a steady supply of vital fuel. 

Conclusion

The D-Day invasion was one of the most consequential events of the twentieth century. Years of planning and resource stockpiling culminated in what is, to this day, the largest seaborne invasion in history. Fueling the invasion of Normandy as part of the greater Operation Overlord required the logistical support and coordination of every aspect of the united Allied forces. From seaborne imports from the United States, all of which were under threat from German U-Boats, to the construction of supply depots and fuel pipelines constructed in utter secrecy, there were a plethora of things that could have gone wrong and risked the success of the D-Day landings and the subsequent mainland liberation of Western Europe. Fortunately, the combined efforts of the Allied nations, especially supported by the oil and gas resources of the United States, ensured the campaign’s success. 

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This article is part of Fueling America: 250 Years of Energy Innovation, a special project by the Institute for Energy Research highlighting America’s unique role as a global energy innovator. To read more related content please visit Fueling250.org.

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According to FERC’s annual summer market and reliability assessment, the capacity additions include nearly 26 gigawatts in the Electric Reliability Council of Texas footprint, close to 13 gigawatts in the Western Electric Coordinating Council region, and 11 gigawatts in the Midcontinent Independent System Operator region. Even with the new capacity, three areas in the United States face risks of power supply shortfalls during extreme conditions: the Pacific Northwest, New England, and part of western Texas.

Natural gas demand and production are both expected to increase, providing more generation. U.S. natural gas demand is expected to average 101.3 billion cubic feet per day this summer, 1.6 billion cubic feet per day more than summer 2025 levels and 8% more than the previous five-year summer average of 93.8 billion cubic feet per day. FERC expects gas-fired generators will provide 39% of capacity this summer, followed by solar at 14%, coal at 13%, wind at 12%, and nuclear and hydropower at 7% each. The new capacity consists of 7 gigawatts of gas, 30.5 gigawatts of solar, of which only 16.4 gigawatts contribute during peak summer demand due to its inefficiencies, and over 16 gigawatts of expensive battery storage capacity. The capacity additions are heavily weighted towards solar and wind as the subsidy schemes of the Inflation Reduction Act continue.

Natural gas production is expected to be slightly higher this summer than last, driven by continued strong production from major shale fields. The Energy Information Administration (EIA) forecasts U.S. dry natural gas production to average 109.3 billion cubic feet per day during summer 2026–a 1% increase from the summer 2025 average of 108.2 billion cubic feet per day and is 7% above the previous five-year average of 101.8 billion cubic feet per day.

Total electricity consumption is projected to reach 1,587 terawatt-hours this summer. EIA forecasts that electricity consumption from June to September 2026 will increase by 106 terawatt hours from the summer of 2021–a 7% increase. Summer 2026 is projected to grow 3% year-over-year compared to summer 2025, the most significant year-over-year growth since summer 2022, and is 4.5% above the previous five-year average of 1,518 terawatt hours. EIA’s projections for monthly consumption this summer indicate demand will peak in August 2026, at 426 terawatt-hours, a 5% increase from August 2025.

In several regions, coal and natural gas-fired plants that were slated to retire, more than 4,300 megawatts, are continuing to operate pursuant to DOE Orders under section 202 (c) of the Federal Power Act (FPA).

NERC projects that summer peak demand across North America will grow by about 224 gigawatts over the next decade, a 69% increase over the previous year’s ten-year forecast and about a 24% increase from 2025 peak demand.  Most of the new load is due to an increasing number of new data centers.

More new generating capacity is coming as power pools are fast-tracking interconnection reviews to get power supplies online quickly. SPP is advancing about 13.3 gigawatts concentrated in Oklahoma, Kansas, and Texas, with 2029/2030 online targets, and MISO is advancing 20.9 gigawatts mainly in Louisiana, Indiana, and Wisconsin, with 2027/2028 in-service dates.

To speed up permit times, FERC has proposed expanding its “blanket certificate” program for certain types of “routine” gas pipeline projects deemed not to require project-specific authorizations. The program was last updated in 2006. Projects identified as high risk, however, will continue to undergo a comprehensive review. In addition to gas pipeline projects, FERC is advancing blanket authorization initiatives for liquefied natural gas and hydropower facilities.

Analysis

FERC’s summer assessment views the grid to be reliable this summer under normal conditions. Under extreme weather conditions, three regions in the United States (the Pacific Northwest, New England, and part of western Texas) face risks of power supply shortfalls. U.S. utilities are adding 75 gigawatts to the grid this summer, composed of solar, wind, natural gas, and battery resources. While that increase is the largest one-year increase in over a decade, caution is warranted given the intermittency of wind and solar power, which provide only a fraction of their design capacity because the wind and sun are unreliable energy sources. Further, storage batteries are expensive and are not generators in themselves; they store power generated by other sources and release it when needed. The Trump administration has also slowed the retirement of over 4.3 gigawatts of fossil fuel generators, which will help this summer if needed.

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The Iran conflict and the effective closure of the Strait of Hormuz continue to disrupt global energy flows, prompting countries to turn to the United States for oil and petroleum products. Asian refiners cannot get the oil they need to produce their own petroleum fuels and are looking to import U.S. diesel and jet fuel, as is the case in Europe. With the U.S. summer driving season getting under way and gasoline stockpiles at multi-year seasonal lows, domestic refinery demand also will be heating up.

The United States has 132 refineries that can process 18.4 million barrels per day. The United States lost about 1.1 million barrels of daily refining capacity between 2020 and 2021, accounting for about one-third of global capacity losses during this period due to reduced demand resulting from the COVID pandemic and the resulting lock downs. Since then, some existing refineries expanded their processing capability.

ExxonMobil increased its Beaumont, Texas refinery’s capacity from 369,000 to 609,000 barrels per day at a cost of $2 billion, adding a distillation unit in 2023. Chevron invested $475 million to modernize its Pasadena, Texas, refinery in 2024, increasing its light crude processing capacity by almost 15% to 125,000 barrels a day. And, Marathon’s Galveston Bay refinery upped its capacity by 6% to 631,000 barrels per day, making it the nation’s second largest refinery behind Motiva’s Port Arthur facility that has a capacity of over 640,000 barrels per day.

Companies are choosing to upgrade their existing facilities rather than build new refineries mainly due to the onerous regulatory process. However, there has been a recent exception.  America First Refining is building a 168,000-barrel-per-day refinery in Brownsville, Texas, a deep-water port with direct rail and sea access, supported by investment from India’s Reliance Industries. The facility — the first new major U.S. refinery project in roughly 50 years — will operate on light shale oil. Many Gulf Coast refineries ‌are unable to process light, sweet oil from ⁠shale fields because they were configured in the last 40 years to run on lower-cost heavy, sour oil, which has a higher density. U.S. light oil resources were on the decline before hydraulic fracking and directional drilling brought an explosion in production. Heavy oil imports are readily available from U.S. neighbors, Canada and Mexico, and now also Venezuela.

California Shedding Refineries

Within the past nine months, California lost two refineries due to its onerous policies against oil and gas production. The Phillips 66 Los Angeles facility and the Valero Benicia Refinery closed due to stringent environmental regulations that increased operational costs, removing 17.5% of the state’s refining capacity. California now has only seven major refineries left and has to rely on more product imports, mostly from Asia. Because of the closure of the Strait of Hormuz those exports are increasingly scarce, however, forcing California to purchase fuel from refineries on the U.S. Gulf coast and to use President Trump’s waiver of the Jones Act for deliveries. Before the waiver, the state would send its product imports east to the Bahamas and then ship them to the California coast to avoid the higher costs of using U.S. ships manned by U.S. crews required by the Jones Act.

California is again making changes to its “cap-and-invest” program which could make it harder to meet and increase costs of refined products. Companies that are forced to participate in the program must either reduce their carbon emissions below a certain state-mandated limit or buy allowances from the market to offset emissions in excess of that limit. The state then “invests” in energy projects its leaders prefer under the justification of climate policy. The number of allowances available for purchase declines over time, making it harder to meet the cap and making it more expensive to do so. As the supply of available allowances falls, the price of each allowance, and the cost of compliance, rises.

The Western States Petroleum Association, a trade group, and Chevron, the state’s largest oil refiner, warned that unless the program’s emissions limits were loosened, companies could be forced to close additional refineries. The California Air Resources Board (CARB) voted to give up as much as $4 billion worth of free allowances to oil refiners and other industrial companies to help them comply with greenhouse gas limits imposed by the state’s cap-and-invest program. The plan would remove the 118 million metric tons’ worth of allowances from circulation, allowing companies to claim them for free, rather than be forced to purchase them.

Analysis

U.S. refineries are running all out to fill both domestic and international demands, many are delaying spring maintenance which normally occurs before the summer driving season. The U.S. refinery utilization rate is near 95% and diesel and gasoline margins are expected to be at $50 and $22 per barrel, respectively, in the fourth quarter. Some companies have added capacity to existing refineries to make up for some of the 1.1 million barrels per day of refining capacity lost during the COVID lockdowns. One new refinery is being built in Texas that will use light oil from shale basins rather than heavy oil that most U.S. refineries currently use. Due to its onerous regulatory program, California recently lost two refineries, forcing it to import more petroleum products.

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Over the weekend, the U.S. military targeted Iranian air defenses, a ground control station, and two drones that were threatening ships after “aggressive Iranian actions,” including shooting down a U.S. drone over international waters. On May 31, U.S. forces intercepted two Iranian ballistic missiles targeting American forces based in Kuwait; no American personnel were harmed. On June 1, Kuwait activated its air defenses and denounced Iranian missile and drone attacks since they were undermining efforts to reduce tensions in the region.

To help with the ship backlog, American ships are guiding commercial vessels through the Strait of Hormuz; most with their transponders turned off to avoid detection. U.S. Central Command has helped around 70 commercial ships pass through the strait in the last three weeks. According to shipping analysts, the U.S.-guided crossings appear to follow routes that are closer to Oman. Ships passing near Iran without obtaining Iranian approval face the threat of an attack by Iranian drones or missiles.

Data Cables May Be Targeted

Executives are worried about Iran’s threats to damage or seize control of data cables under the strait. In early May, an Iranian military spokesman said the country was threatening to demand license fees from Amazon, Google, Microsoft, and Meta to use the cable networks they operate under the strait. The cables could be cut or tampered with. A semiofficial news agency called the networks a “vulnerable point in the region’s digital economy.”

It is estimated that the cables carry financial transactions totaling about $10 trillion a day. The cables connect the Gulf region to parts of Europe, Asia, and Africa, part of a vast subsea infrastructure that carries about 99 percent of global internet traffic, according to the International Telecommunication Union, a U.N. agency. The group estimates there are about 200 cable cuts worldwide every year, mostly from earthquakes or dragging anchors. Iran still has the combat divers, unmanned underwater vessels, and munitions needed to shut down cable traffic, according to an April report by Al Habtoor Research Center.

A 2024 cable cut in the nearby Red Sea, during attacks on commercial vessels by Houthi rebels in Yemen, shut 25% of internet traffic across the region and took weeks to restore. Only four companies specialize in laying undersea cables, with about 20 repair ships available, many of which would need weeks to arrive in the Middle East.

China’s Import Situation

China’s crude oil imports dropped to the lowest level in 10 years in May, driven primarily by economic factors from the conflict in the Middle East. Seaborne imports of crude oil were 6.36 million barrels per day in May, down from 8.10 ​million barrels per day in April and 11.39 million barrels per day imported in February. China’s May imports were the weakest since October 2016. The conflict in the Middle East raised China’s oil prices, causing its demand to be cut back. A reduction of up to 2 million barrels per day in monthly imports in response to sharp price increases is not unusual for China, but from February to May, the drop was far larger at over 5 million barrels per day.

Like other regions, China is having trouble making up the import losses from the Middle East from other exporting countries. China’s imports from Iraq dropped from 790,000 barrels per day in February to 60,000 barrels per day in May, and those from Kuwait dropped from a recent high of 522,000 barrels per day in October to zero in May.

China’s refineries are likely using up their commercial inventories of both crude oil and refined products. China has also cut back on its exports of refined products, allowing more petroleum products to be kept for domestic use. Its refined product exports dropped from 777,000 barrels per day in February to 463,000 barrels per day in May—a drop of 40%. Once the commercial inventories are depleted, China will have to tap into its large strategic reserves unless it can somehow increase its oil imports and/or cut refinery processing rates substantially.

Analysis

U.S. Iran peace negotiations are at a standstill as some military activity has resumed. The United States struck Iranian military sites over ‌the weekend as Iran threatened U.S. ships and struck down a U.S. drone in international waters, and its Revolutionary Guards targeted a U.S. base. Israel also ordered troops to move further into Lebanon in its fight with the Tehran-backed Hezbollah militant group. The military activity raised oil prices by over $6 a barrel on June 1. The United States has been guiding commercial ships through the Strait of Hormuz on the Oman side over the past three weeks, but Iran is threatening to shut the strait completely. Executives are now worried that Iran will either cut or damage the underwater data cables that carry a substantial portion of internet traffic.

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Governor Sherill needs to read our recent report on data centers and electricity prices. We found that there is no statistically significant correlation between the number of data centers in a state and either current electricity prices or the rate of electricity price increases across states. In fact, prices in the top ten data center states are virtually identical to the average across other states.

We found that there was a significant correlation between electricity sales and lower increases in electricity rates and faster increases in prices and falling electricity sales. This finding actually explains what is happening in New Jersey.

If data centers were driving New Jersey’s electricity-cost crisis, statewide electricity sales would be surging. They are not. New Jersey’s electricity sales are falling. New Jersey retail electricity sales fell from 75.4 TWh in 2016 to 73.1 TWh in 2025, a decline of about 3%. Compared with 2010, when New Jersey used 79.2 TWh, demand is down about 7.7%. New Jersey currently has 82 data centers, but it still has falling electricity demand, while prices continue to rise.

According to the most recent data from EIA, New Jersey’s residential electricity price is 23.49 cents/kWh, making it the 13th-highest priced state and 25% above the U.S. average. From 2016 to 2025, New Jersey’s nominal electricity price rose from 13.38 to 18.84 cents/kWh, a 40.8% increase.

The actual cost drivers are hiding in plain sight. New Jersey’s Renewable Portfolio Standards (RPS) compliance cost rose from 0.78 cents/kWh in 2016 to 1.94 cents/kWh in 2024, equal to 11.9% of the average bill. New Jersey’s net-metering penetration rose from 2.17% of retail sales in 2016 to 6.42% in 2025, while small-scale solar rose from 1.78% to 6.27% of in-state generation.

At the same time, New Jersey has been retiring dispatchable power plants. PJM reports that Mercer 1, Mercer 2, and Hudson 2 (all coal plants) were deactivated on June 1, 2017, totaling roughly 1,259 MW of capacity. New Jersey also lost unit 1 at BL England power station in 2014 and unit 2 in 2019, totaling an additional 300 mw of coal power. In 2022, New Jersey’s Board of Public Utilities approved agreements closing facilities owned by Chambers Cogeneration Limited and Logan Generating Company, the last two coal-fired electricity generation units in New Jersey.

New Jersey has lost more than coal power. In 2018, New Jersey saw the retirement of the 625 MW Oyster Creek Nuclear Generating Station. It was a 625 MW nuclear plant and at the time it retired, EIA reported that in “2017, Oyster Creek generated 5.4 million megawatt hours of electricity, or almost twice as much as all of the solar photovoltaic systems in New Jersey.”

All of these retirements are important context that Governor Sherrill omits. New Jersey is not suffering from an uncontrolled statewide demand surge. It is a high-cost state with declining electricity sales, expensive RPS compliance, aggressive net-metering exposure, growing distributed-solar cost shifting, and a long list of retired dispatchable power plants.

Data centers should pay the direct costs they impose. But blaming them for New Jersey’s current electricity-rate problem is wrong. The problem is not data centers, but years of bad policy.

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