DOE taps Texas companies for $56M in Strategic Petroleum Reserve deliveries

reserve refill

Two Texas companies will deliver crude oil from Dec. 1 through Jan. 31 to the Strategic Petroleum Reserve, the world’s largest emergency supply of crude oil. Photo via Getty Images

Two companies with ties to the Houston area have been awarded federal contracts totaling nearly $55.8 million to supply about 1 million barrels of crude oil for the nation’s depleted Strategic Petroleum Reserve.

Houston-based Trafigura Trading will provide two-thirds of the oil, and Dallas-based Energy Transfer Crude Marketing will provide the remaining one-third. Energy Transfer, the parent company of Energy Transfer Crude Marketing, operates a 330-acre oil terminal at the Houston Ship Channel.

The U.S. Department of Energy (DOE), which awarded the contracts, said Trafigura and Energy Transfer will deliver the crude oil from Dec. 1 through Jan. 31 to the Strategic Petroleum Reserve’s Bryan Mound storage site near Freeport.

The Strategic Petroleum Reserve, the world’s largest emergency supply of crude oil, can hold up to 714 million barrels of crude oil across 61 underground salt caverns at four sites along the Gulf Coast. The reserve currently contains 410 million barrels of crude oil. During the pandemic, the Biden administration ordered a 180 million-barrel drawdown from the reserve to help combat high gas prices triggered by Russia’s war with Ukraine.

The four strategic reserve sites are connected to 24 Gulf Coast refineries, and another six refineries in Kentucky, Michigan and Ohio.

“Awarding these contracts marks another step in the important process of refilling this national security asset,” U.S. Energy Secretary Chris Wright said.

In March, Wright estimated it would take $20 billion and many years to fill the Strategic Petroleum Reserve to its maximum capacity, according to Reuters

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Last Energy will build a 5-megawatt reactor at the Texas A&M-RELLIS campus. Photo courtesy Last Energy.

Micro-nuclear reactor to launch next year at Texas A&M innovation campus

nuclear pilot

The Texas A&M University System and Last Energy plan to launch a micro-nuclear reactor pilot project next summer at the Texas A&M-RELLIS technology and innovation campus in Bryan.

Washington, D.C.-based Last Energy will build a 5-megawatt reactor that’s a scaled-down version of its 20-megawatt reactor. The micro-reactor initially will aim to demonstrate safety and stability, and test the ability to generate electricity for the grid.

The U.S. Department of Energy (DOE) fast-tracked the project under its New Reactor Pilot Program. The project will mark Last Energy’s first installation of a nuclear reactor in the U.S.

Private funds are paying for the project, which Robert Albritton, chairman of the Texas A&M system’s board of regents, said is “an example of what’s possible when we try to meet the needs of the state and tap into the latest technologies.”

Glenn Hegar, chancellor of the Texas A&M system, said the 5-megawatt reactor is the kind of project the system had in mind when it built the 2,400-acre Texas A&M-RELLIS campus.

The project is “bold, it’s forward-looking, and it brings together private innovation and public research to solve today’s energy challenges,” Hegar said.

As it gears up to build the reactor, Last Energy has secured a land lease at Texas A&M-RELLIS, obtained uranium fuel, and signed an agreement with DOE. Founder and CEO Bret Kugelmass said the project will usher in “the next atomic era.”

In February, John Sharp, chancellor of Texas A&M’s flagship campus, said the university had offered land at Texas A&M-RELLIS to four companies to build small modular nuclear reactors. Power generated by reactors at Texas A&M-RELLIS may someday be supplied to the Electric Reliability Council of Texas (ERCOT) grid.

Also in February, Last Energy announced plans to develop 30 micro-nuclear reactors at a 200-acre site about halfway between Lubbock and Fort Worth.

The Clean Hydrogen Buyers Alliance plans to create the Gulf Coast Hydrogen Index to bring to bring transparency and confidence to hydrogen pricing. Photo via Getty Images

Houston organization proposes Gulf Coast index for hydrogen market

hydrogen index

The Clean Hydrogen Buyers Alliance has proposed an index aimed at bringing transparency to pricing in the emerging hydrogen market.

The Houston-based alliance said the Gulf Coast Hydrogen Index, based on real-time data, would provide more clarity to pricing in the global market for hydrogen. The benchmarking effort is being designed to benefit clean hydrogen buyers, sellers and investors. The index would help position the U.S. “as the trading anchor for hydrogen’s next chapter as a globally traded commodity,” the alliance said.

According to ResearchAndMarkets.com, the global market for clean hydrogen was valued at $200 billion in 2024 and is projected to reach $700 billion by 2040.

John Flory, president of the alliance, said the lack of a pricing index has relegated hydrogen to niche-market status.

“Capital is waiting. Buyers are ready. But until now, there’s been no credible, transparent pricing signal to guide clean hydrogen investing or contracting,” Edward Morse, co-chairman of the Clean Hydrogen Transaction Advisory Committee, said in a news release.

The index would treat the Gulf Coast as the primary delivery hub for pipeline-grade hydrogen in three categories: basic, low-carbon and ultra-low-carbon. It would be similar to the Henry Hub index for pricing of natural gas.

Roger Ballentine, co-chairman of the clean energy advisory committee, said the hydrogen index would build confidence in this energy source among government agencies, companies and investors. A Henry Hub-style benchmark for hydrogen “provides clarity, reduces risk, and lays the foundation for clean energy to become a globally traded commodity critical to decarbonization,” he said.

The Gulf Coast, with Texas as the focal point, is key to the evolution of the U.S. clean hydrogen economy, according to the Fuel Cell and Hydrogen Energy Association.

At the core of the Gulf Coast’s role is the U.S. Department of Energy's selection of the Gulf Coast as one of the country’s seven regional hubs for clean hydrogen. However, the DOE has proposed cutting funding for the HyVelocity Gulf Coast Hydrogen Hub, a $1.2 billion development in Texas and Louisiana by AES, Air Liquide, Chevron, ExxonMobil, MHI Hydrogen Infrastructure and Ørsted, according to a new list of proposed DOE funding cancellations.

A list of proposed DOE funding cancellations shows potential cuts for Houston-area companies. Photo via Getty Images.

DOE proposes cutting $1.2 billion in funding for hydrogen hub

funding cuts

The U.S. Department of Energy has proposed cutting $1.2 billion in funding for the HyVelocity Gulf Coast Hydrogen Hub, a clean energy project backed by AES, Air Liquide, Chevron, ExxonMobil, Mitsubishi Power Americas and Ørsted.

The HyVelocity project, which would produce clean hydrogen, appears on a new list of proposed DOE funding cancellations. The list was obtained by Latitude Media.

As of November, HyVelocity had already received $22 million of the potential $1.2 billion in DOE funding.

Other than the six main corporate backers, supporters of HyVelocity include the Center for Houston’s Future, Houston Advanced Research Center, Port Houston, University of Texas at Austin, Shell, the Texas governor’s office, Texas congressional delegation, and the City of Fort Worth.

Kristine Cone, a spokeswoman for GTI Energy, the hub’s administrator, told EnergyCapital that it hadn’t gotten an update from DOE about the hub’s status.

The list also shows the Magnolia Sequestration Hub in Louisiana, being developed by Occidental Petroleum subsidiary 1PointFive, could lose nearly $19.8 million in federal funding and the subsidiary’s South Texas Direct Air Capture (DAC) Hub on the King Ranch in Kleberg County could lose $50 million. In September, 1Point5 announced the $50 million award for its South Texas hub would be the first installment of up to $500 million in federal funding for the project.

Other possible DOE funding losses for Houston-area companies on the list include:

A little over $100 million earmarked for Houston-based BP Carbon Solutions to develop carbon storage projects
$100 million earmarked for Dow to produce battery-grade solvents for lithium-ion batteries. Dow operates chemical plants in Deer Park and LaPorte
$39 million earmarked for Daikin Comfort Technologies North America to produce energy-efficient heat pumps. The HVAC company operates the Daikin Texas Technology Park in Waller
Nearly $6 million earmarked for Houston-based Baker Hughes Energy Transition to reduce methane emissions from flares
$3 million earmarked for Spring-based Chevron to explore development of a DAC hub in Northern California
Nearly $2.9 million earmarked for Houston-based geothermal energy startup Fervo Energy’s geothermal plant in Utah

U.S. Rep. Morgan Luttrell, a Magnolia Republican, and Hertha Metals founder and CEO Laureen Meroueh toured Hertha’s Conroe plant in August. Photo courtesy Hertha Metals/Business Wire.

Houston-area sustainable steel company emerges from stealth with $17M in VC funding

heavy metals

Conroe-based Hertha Metals, a producer of substantial steel, has hauled in more than $17 million in venture capital from Khosla Ventures, Breakthrough Energy Fellows, Pear VC, Clean Energy Ventures and other investors.

The money has been put toward the construction and the launch of its 1-metric-ton-per-day pilot plant in Conroe, where its breakthrough in steelmaking has been undergoing tests. The company uses a single-step process that it claims is cheaper, more energy-efficient and equally as scalable as conventional steelmaking methods. The plant is fueled by natural gas or hydrogen.

The company, founded in 2022, plans to break ground early next year on a new plant. The facility will be able to produce more than 9,000 metric tons of steel per year.

Hertha said in a news release that its process, which converts low-grade iron ore into molten steel or high-purity iron, “doesn’t just materially lower cost and energy use — it fundamentally expands our capacity to produce iron and steel at scale, by unlocking a wider range of iron ore feedstocks.”

Laureen Meroueh, founder and CEO of Hertha, says the company’s process will fill a gap in U.S. steel production.

“We’re not just reinventing steelmaking; we’re redefining what’s possible in materials, manufacturing, and national resilience,” Meroueh says.

Hertha says it’s in talks with magnet producers — which make permanent magnets and magnetic assemblies from raw materials such as iron — to become a U.S. supplier of high-purity iron. In its next stage of growth, Hertha will aim to operate at a capacity of 500,000 metric tons of steel production per year.

The company won the Department of Energy's Summer Energy Program for Innovation Clusters (EPIC) Startup Pitch Competition last summer. Read more here.

A new report from the Department of Energy says the risk of power blackouts will be 100 times greater in 2030. Photo via Getty Images.

DOE report warns of widespread power blackouts by 2030 amid grid challenges

grid report

Scheduled retirements of traditional power plants, dependence on energy sources like wind and solar, and the growth of energy-gobbling data centers put the U.S. — including Texas — at much greater risk of massive power outages just five years from now, a new U.S. Department of Energy report suggests.

The report says the U.S. power grid won’t be able to sustain the combined impact of plant closures, heavy reliance on renewable energy, and the boom in data center construction. As a result, the risk of power blackouts will be 100 times greater in 2030, according to the report.

“The status quo of more [plant] retirements and less dependable replacement generation is neither consistent with winning the AI race and ensuring affordable energy for all Americans, nor with continued grid reliability … . Absent intervention, it is impossible for the nation’s bulk power system to meet the AI growth requirements while maintaining a reliable power grid and keeping energy costs low for our citizens,” the report says.

Avoiding planned shutdowns of traditional energy plants, such as those fueled by coal and oil, would improve grid reliability, but a shortfall would still persist in the territory served by the Electric Reliability Council of Texas (ERCOT), particularly during the winter, the report says. ERCOT operates the power grid for the bulk of Texas.

According to the report, 104 gigawatts of U.S. power capacity from traditional plants is set to be phased out by 2030. “This capacity is not being replaced on a one-to-one basis,” says the report, “and losing this generation could lead to significant outages when weather conditions do not accommodate wind and solar generation.”

To meet reliability targets, ERCOT would need 10,500 megawatts of additional “perfect” capacity by 2030, the report says. Perfect capacity refers to maximum power output under ideal conditions.

“ERCOT continues to undergo rapid change, and supply additions will have a difficult time keeping up with demand growth,” Brent Nelson, managing director of markets and strategy at Ascend Analytics, a provider of data and analytics for the energy sector, said in a release earlier this summer. “With scarcity conditions ongoing and weather-dependent, expect a volatile market with boom years and bust years.”

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Houston investment firm closes $105M energy venture fund

seeing green

Houston-based investment firm Veriten has announced the initial close of its second flagship energy venture fund with more than $105 million in capital commitments.

Fund II will build on Veriten’s initial fund and aim to support “scalable technology solutions for energy, power and industrial applications,” according to a company news release.

"Our differentiated network, research-driven process, and first principles approach to investing are having an impact across multiple verticals including traditional energy, electrification, and industrial technology. Fund II builds on that platform,” John Sommers, partner, investments at Veriten, added in the release. “In this environment, the differentiator isn't capital – it's all about connectivity, deep sector expertise, and an economically-driven approach. As new technologies and approaches develop at breakneck speed, the need for more reliable, affordable energy and power continues to grow dramatically. The current backdrop accentuates the need for Veriten's solution."

Veriten is supported by over 50 strategic partnerships in the energy, power, industrial and technology sectors, including major players like Halliburton and Phillips 66.

"Veriten continues to build a differentiated platform at the intersection of energy, technology and industry expertise," Jeff Miller, chairman and CEO of Halliburton, said in the release. "We were early believers in the team and their ability to identify practical solutions to real challenges across the energy value chain. As all industries increasingly adopt digital tools, automation and AI-enabled technologies to improve performance and execution, we are proud to partner with Veriten again to help accelerate high-impact solutions across the broader energy landscape."

Veriten closed its debut fund, NexTen LP, of $85 million in committed capital in October 2023. It was launched in January 2022 by Maynard Holt, co-founder and former CEO of the energy investment bank Tudor, Pickering, Holt & Co.

It has invested in Houston-based AI-powered electricity analytics provider Amperon and led a $12 million Seed 2 funding round for Houston-based Helix Technologies to scale manufacturing of its energy-efficient commercial HVAC add-on earlier this year. In the past year it has contributed to funding rounds for San Francisco-based Armada and Calgary-based Veerum.

Veriten also named Nick Morriss as its new managing director earlier this month. Morriss most recently served as vice president of business development at next-generation nuclear technology company Natura Resources and spent nearly 20 years at NOV Inc.

Houston energy expert asks: Who pays when AI outruns the power grid?

Guets Column

For most of the past 20 years, U.S. electricity policy relied on predictable trends in demand. Electricity use, in most regions, increased gradually, forecasts were stable, and utilities adjusted the system in small steps. Power plants, transmission lines, and substations were generally added to reflect shifts in load, rather than growth, and costs were recovered through modest adjustments to customer bills.

Growth in AI data centers has disrupted this model. A single facility can add as much electricity demand as a small town. That demand comes all at once, runs continuously, and has little tolerance for outages. If electricity service drops even briefly, computation stops, and services shut down. Ironically, data centers need reliable service, a point that their emergence is driving concern around for the rest of the grid.

What the numbers say

The International Energy Agency projects global electricity consumption from data centers to double by 2030, reaching roughly 945 TWh, nearly 3 percent of global electricity demand, with consumption growing about 15 percent per year this decade. McKinsey projects that U.S. data center demand alone could grow 20–25 percent per year, with global capacity demand more than tripling by 2030.

After years of roughly 0.5 percent annual demand growth, many forecasts now place total U.S. electricity demand growth closer to 2–3 percent per year through the mid-2030s, with much higher growth in specific regions. In Texas, some forecasters are saying electricity demand could double over the next five years, a staggering 10 percent per year growth rate. What sounds incremental on paper translates into a major challenge on the ground. Meeting this pace of growth is estimated to require $250–$300 billion per year in grid investment, about double what the system has been absorbing.

Where the system starts to strain

The strain appears first in the interconnection queue. It shows up as long waits, backlogs, and delays for connecting new loads and new generation.

Before new generators or large load customers can be connected, a study is required to assess their impact on the grid, whether it can physically handle the added load, and whether upgrades are required. With AI-driven data centers, utilities face far more connection requests than they can realistically support. In ERCOT, large-load interconnection requests exceed 200 gigawatts, most tied to data centers. That amount exceeds historical norms, and it is several times larger than what can be practically studied or built in the near term.

To be clear, public utility commissions are required to study these requests because they must manage system capabilities to ensure minimal disruption. This means engineers spend time evaluating projects that may never be built, while other more commercially viable projects may wait longer for approvals. This extends timelines and makes infrastructure planning less reliable.

Why policymakers are rethinking the rules

Utilities and their regulators must decide how much generation, transmission, and substation capacity to build years before it comes online. Those decisions are based on expected demand at the time projects are approved. When it comes to data centers, by the time infrastructure is completed, they may end up deploying newer, more efficient chips that use less power than originally assumed. This can result in grid infrastructure built for a higher load than what actually materializes, leaving excess capacity that still must be paid for through system-wide rates.

That’s the central dilemma. If utilities build too little capacity, the system operates with less reserve margin. During periods of grid stress, operators have fewer options, increasing the likelihood of curtailments or outages. However, if utilities build too much, customers may be asked to pay for infrastructure that is not fully used.

In response, policymakers are adjusting the rules. In some regions, regulators are moving toward bring-your-own-power approaches that require large data centers to supply or fund part of the capacity needed to serve them or reduce demand during system stress. At the federal level, permitting reforms tied to datacenter infrastructure increasingly treat electricity as a strategic economic input.

As Ken Medlock, senior director at the Baker Institute Center for Energy Studies (CES), explains:

“Many of the planned data centers are now also adding behind-the-meter options to their development plans because they do not anticipate being able to manage their needs solely from the grid, and they certainly cannot do so with only intermittent power sources.”

Behind-the-meter (BTM) refers to power that a consumer controls on its side of the utility meter, such as on-site gas generation or a dedicated power plant. These resources allow data centers to keep operating during grid-related service. Most facilities remain connected to the grid, but the backup BTM generation serves as insurance for operating their core business.

This shifts responsibility. Utilities traditionally manage reliability across all customers by maintaining an operating reserve margin, or spare capacity. Increasingly, large-load customers manage part of their own electricity reliability needs, which changes how infrastructure is planned and how risk is distributed.

Bottom line

AI-driven load growth is arriving faster and in more concentrated places than the power system was built to accommodate. Utilities and regulators are being forced to make decisions sooner than planned about where to build, how fast to build, and which customers get priority when capacity is limited. The effects extend beyond data centers, showing up in system costs, reliability margins, competition for grid access, and pressure on communities and industries that depend on affordable and dependable power. The issue is not whether electricity can be generated, but how the costs and risks of rapid demand growth are distributed as the system tries to keep up. How regulators balance these decisions will determine who pays as AI demand outruns the power grid.

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Scott Nyquist is a senior advisor at McKinsey & Company and vice chairman, Houston Energy Transition Initiative of the Greater Houston Partnership. The views expressed herein are Nyquist's own and not those of McKinsey & Company or of the Greater Houston Partnership. This article originally appeared on LinkedIn.

Texas solar set to overtake coal for first time in 2026, EIA forecasts

solar on the rise

Solar power promises to shine even brighter in Texas this year.

A new forecast from the U.S. Energy Information Administration (EIA) indicates that for the first time, annual power generation from utility-scale solar will surpass annual power generation from coal across the territory covered by the Electric Reliability Council of Texas (ERCOT).

Solar generation is expected to reach 78 billion kilowatt-hours in 2026 in the ERCOT grid, compared with 60 billion kilowatt-hours for coal, the EIA forecast says. The ERCOT grid supplies power to about 90 percent of Texas, including the Houston area.

“Utility-scale solar generation has been increasing steadily in ERCOT as solar capacity additions help meet rapid electricity demand growth,” the forecast says.

Although natural gas remains the dominant source of electricity generation in ERCOT, accounting for an average 44 percent of electricity generation from 2021 to 2025, solar’s share of the generation mix rose from four percent to 12 percent. During the same period, coal’s share dropped from 19 percent to 13 percent.

EIA predicts about 40 percent of U.S. solar capacity, or 14 billion kilowatt-hours, added in 2026 will come from Texas.

Although EIA expects annual solar generation to exceed annual coal generation in 2026, solar surpassed coal in ERCOT on a monthly basis for the first time in March 2025, when solar generation totaled 4.33 billion kilowatt-hours and coal’s totaled 4.16 billion kilowatt-hours. Solar generation continued to exceed that of coal until August of that year.

“In 2026, we estimate that solar exceeded coal for the first time in March, and we forecast generation from solar installations in ERCOT will continue to exceed that from coal until December, when coal generation exceeds solar,” says EIA. “We expect solar generation to exceed that of coal for every month in 2027 except January and December.”

For 2027, EIA forecasts annual solar generation of 99 billion kilowatt-hours in the ERCOT grid, compared with 66 billion kilowatt-hours of annual coal generation.

In April, ERCOT projected almost 368 billion kilowatt-hours of demand in ERCOT’s territory by 2032. ERCOT’s all-time peak demand hit 85.5 billion kilowatt-hours in August 2023.

“Texas is experiencing exceptional growth and development, which is reshaping how large load demand is identified, verified, and incorporated into long-term planning,” ERCOT President and CEO Pablo Vegas said. “As a result of a changing landscape, we believe this forecast to be higher than expected … load growth.”

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