Media Type: Article

By Jonathan Rotzien, KBH Energy Center McCombs School of Business Lecturer, for American Association of Petroleum Geologists (AAPG).

Houston Chronicle, By Dr. Michael Webber

By Jack Balagia, KBH Energy Center Executive Director.

Gasoline prices are seen at a Chevron gas station in Houston, Texas, on March 16, 2026. Oil prices retreated and equities rose Monday as investors remained focused on the Strait of Hormuz, with US allies pushing back against President Donald Trump’s demands to help reopen the key waterway to oil and natural gas tankers. (Photo by RONALDO SCHEMIDT / AFP via Getty Images)

Following his trip to Venezuela earlier this month, Interior Secretary Doug Burgum seemed to imply some reprieve from the Iran War’s impact on world energy supplies when he called the South American country “a strategic ally with the largest reserves with no threat of the chokehold like we have in the Strait of Hormuz.” In the same March 8 interview with Fox News, Burgum added that “Venezuelan oil can flow to America freely and is starting to flow, will continue to flow, and these are the kinds of things that are going to bring gas prices down in America.”

The secretary undoubtedly chose his words carefully. He did not say that Venezuelan oil would cushion the current crisis in the Middle East, and for good reason. It won’t.

Chevron and other companies are moving toward expanded production agreements in Venezuela, and Energy Secretary Chris Wright told CNBC that production has increased 20% in three months. But any significant increase in production will happen far in the future.

Venezuela’s output recently hovered at less than 1 million barrels per day, far below its peak of 3 million in the late 1990s and early 2000s. Decades of mismanagement and corruption within the country’s oil company, PDVSA, under Hugo Chávez and his successor, Nicolás Maduro, combined with international sanctions and the deliberate exclusion of Western investment, have severely damaged the country’s energy industry. Having the world’s largest oil reserves means nothing without the infrastructure to tap and export production.

Since Maduro’s capture on January 3, the Trump administration has moved quickly to establish a legal framework for oil companies to move back, relaxing sanctions on PDVSA, issuing a series of general licenses from the Treasury to market Venezuelan crude, sell diluent (a product used to allow Venezuela’s thick crude to flow through pipelines) and open pathways for upstream contract negotiations. Under a U.S.-supervised oil marketing arrangement, Venezuela transported more than 280,000 barrels a day to the United States in February, with proceeds flowing into a U.S.-controlled account rather than to the Venezuelan government directly.

However, it is one thing to license and sell existing production — it is quite another to attract the capital investment required to bring Venezuela’s output up to a level that can move the global market.

Fixing Venezuela’s oil and gas industry will be a massive job. President Donald Trump has called for at least $100 billion to rebuild it, and MarketWatch reportsthat number could reach almost $200 billion. To put that in perspective, ExxonMobil, Chevron and ConocoPhillips combined report spending only less than $50 billion a year on all their projects worldwide — and those figures reflect an intense capital discipline the companies have maintained since the pandemic. There are much safer places in the world to invest their shareholders’ money than Venezuela.

Then there are the legal hurdles. FTI Consulting, advocating for a Venezuela settlement commission to resolve outstanding claims against the country and PDVSA, estimates that unsatisfied liabilities from external arbitration awards of at least $150 billion. ConocoPhillips alone holds $10 billion in outstanding arbitration claims stemming from the 2007 nationalization — the largest financial grievance of any U.S. oil company against Venezuela.

Venezuela has taken steps by passing a new hydrocarbon law seeking to open its oil sector to foreign investment, and certainly the easing of U.S. restrictions on Venezuelan exports is an important step. But those changes mean little without credible protections against a government with a history of seizing assets. And uncertain policies in Venezuela are not the only problem, as U.S. government views toward fossil fuel development continue to ping-pong under each new administration. Until industry players are satisfied that invested capital is genuinely secure, and that legal and regulatory regimes in both countries can be trusted, the gap between the Trump Administration’s ambitions and boardroom reality is likely to persist.

Venezuela’s ability to return to its peak early-2000s production levels would have a meaningful impact on global oil supply — but it isn’t happening now. And now is when Americans are facing $100-a-barrel oil. The opening in Venezuela creates a real opportunity, but converting that opportunity into barrels will take years of work, hundreds of billions in capital investment, the resolution of outstanding legal claims and governance reforms that have yet to take hold. Until then, the world’s largest oil reserves will remain underground and will not resolve a market strained by a crisis in the Strait of Hormuz.

Jack Balagia is adjunct professor and executive director at the Kay Bailey Hutchison Energy Center at the University of Texas at Austin and is the former vice president and general counsel at Exxon Mobil Corp.

Rural development that scars the land, trucks that snarl traffic and tear up the roads, security lights that brighten our dark skies, noisy operations that disturb bucolic silence, man camps with their attendant challenges, and competition for water that makes drought-weary Texans nervous — all balanced against promises of untold riches, tax revenues for local governments and job creation.

By Sabrina Conte, KBH Energy Center Graduate Fellow

Lithium is necessary to technological innovation—but it is also a glaring strategic vulnerability for the United States.

As a key component of lithium-ion batteries, lithium powers crucial technologies, from smartphones to military satellites to backup power storage in data centers. Due to its widespread use in electric vehicles, lithium is also a critical material for enabling the energy transition.

Worryingly, however, demand for lithium is on pace to exceed supply from announced projects by nearly 40% in 2035. And for the U.S., supply chain pressure is compounded by the location of the resource itself. Lithium is obtained either through hard rock mining of lithium-rich minerals or by extracting the mineral from brine pumped from underground wells. But deposits are unevenly distributed across the world, meaning that a majority of lithium production is concentrated in just a few countries: Australia, China, Argentina and Chile. Chinese companies dominate the supply chain further downstream, controlling by some estimates 70% of the world’s processing and 75% of its lithium-ion battery manufacturing. The U.S. has just one operational lithium mine, which contributes less than one percent of global production.

It is increasingly evident that lack of control over lithium supply and processing is a national security weakness. Russia and China have shown that they are willing and able to leverage their control over the supply of critical minerals against their geopolitical rivals. In June 2025, Russia seized a lithium deposit from Ukraine shortly after the latter signed a deal to provide investment opportunities in rare earth mineral extraction to the U.S. In October 2025, China placed export restrictions on lithium battery materials, using its dominance in the sector as an economic lever in its ongoing trade war with the Trump administration.

There is reason to be optimistic, however, that this security gap can be plugged. The U.S. has promising sites for lithium production—in particular, the Smackover Formation, an oilfield spanning hundreds of miles from East Texas to Florida which contains massive lithium-rich brine deposits. The Formation produced the highest reported concentration of lithium-in-brine in North America, igniting a wave of leasing activity and commitments by major energy companies, including Exxon, to extracting lithium on-site.

Federal efforts to support domestic lithium production in sites like the Smackover have been powerful, fast-moving, and bipartisan: both the Biden Trump administrations have taken steps to onshore by awarding producers hundreds of millions of dollars in government funding, streamlining mineral permitting, entering into mineral leases on federal lands, and acquiring equity stakes in domestic producers. However, regulatory power mainly rests with the states, which are responsible both for prescribing rules for lithium extraction in their jurisdiction and defining ownership rights over lithium and the brines that contain it.

Unfortunately, state laws have not developed on-pace, creating legal uncertainty that undercuts efforts to onshore production. In some states, for example, it is unclear whether any authority has responsibility over the mineral at all: both the Oklahoma Corporation Commission (the authority regulating oil and gas) and the state Department of Mines denied any jurisdiction over lithium in Oklahoma. In other states—most notably in Texas, which sits on part of the Smackover—unclear ownership rules have tied up project development.

Ownership of naturally occurring lithium brines in Texas rests with the surface estate. Additionally, the Texas Supreme Court recently clarified that producers who hold oil-and-gas rights under existing leases have the right to produced water (waste fluid from oil and gas drilling activities that can contain lithium). However, whether the “constituent” minerals within the brine or produced water are conveyed to the mineral estate upon severance or remain with the surface estate is still unsettled. As matters stand, developers must obtain permission from (and negotiate compensation with) each of the potential owners before they can extract lithium from brines. Efforts by Texas legislators to clarify brine ownership have been unsuccessful: a bill that would accord rights in brine minerals to mineral owners as a matter of law ultimately failed to pass.

The situation in Texas reflects a broader issue: regulation of lithium production in the United States is too fragmented and developing too slowly to meet ongoing needs. Failure to clarify ownership rights, in particular, has led to uncertainty and increased risk for companies hoping to capitalize on the growing demand for lithium where reserves are abundant. More broadly, however, lack of regulatory clarity hampers efforts to shore up the lithium supply chain and close a crucial security vulnerability. Given China’s dominance in the lithium and lithium-ion battery industries, catching up is a monumental task where speed is of the essence. State legislators should work quickly to fill these regulatory gaps.

Gibson Dunn is advising the Exxon Mobil Corporation on its redomestication to Texas. The company’s Board of Directors has unanimously recommended that shareholders approve changing the company’s legal domicile from New Jersey to Texas. The Board concluded that aligning ExxonMobil’s legal domicile with where its leadership and core operations have been based since 1989 will benefit shareholders.

By Jack Balagia, KBH Energy Center Executive Director

The war with Iran may be continents away, but its economic impact is at our doorstep:  the price at the gas pump, shrinking purchasing power, energy bills that suddenly bear little resemblance to last quarter’s numbers.

By Max Lies, KBH Energy Center Graduate Fellow

American energy leadership has long rested on the ability to combine scale, innovation, and reliability to produce abundant energy at home while shaping global markets abroad. As global energy demand continues to rise, this leadership will be defined not only by volumes produced, but by which countries set the terms for emerging energy commodities.

Hydrogen is poised to become one such commodity, with applications across refining, chemicals, manufacturing, and international trade. Among hydrogen pathways, blue hydrogen, produced from natural gas with carbon capture and sequestration (CCS), aligns closely with U.S. strengths: an existing natural gas base, world‑class industrial operators, and deep experience in large-scale project execution. Recognizing this opportunity, Congress included the 45V Clean Hydrogen Production Tax Credit in the 2022 Inflation Reduction Act (IRA) to catalyze early investment and overcome market failures.[1]

Recent legislative changes under the One Big Beautiful Bill (OBBB), however, substantially weaken this incentive by imposing an early sunset. As a result, U.S. firms risk forfeiting a narrow but critical window to establish international leadership in blue hydrogen, ceding economic and strategic ground in a market primed to expand over the coming decades.

The International Energy Agency’s (IEA) 2025 Global Hydrogen Review shows that global hydrogen demand reached more than 100 million metric tons (Mt) in 2024, a roughly 10% year‑over‑year increase.[2] This demand remains concentrated in established industrial sectors such as refining, ammonia production, and chemicals rather than new clean‑energy applications. China alone consumes nearly 30 Mt of hydrogen annually, compared with approximately 16 Mt across all of North America. Absent strong policy support, the IEA notes that hydrogen demand growth will remain limited to these incumbent uses, as high costs and coordination challenges prevent broader adoption.

The IRA’s 45V Clean Hydrogen Production Tax Credit was designed to address this reality. By offering up to $3 per kilogram of qualifying clean hydrogen for 10 years, the credit aimed to move projects across critical investment thresholds rather than permanently subsidize production. For capital‑intensive blue hydrogen projects, the availability and durability of 45V altered project costs and enabled firms to justify final investment decisions (FIDs) and initiate construction at scale.

The importance of 45V is simple: ExxonMobil’s proposed Baytown blue hydrogen project was expected to produce approximately 2.5 million kilograms of hydrogen per year.[3] At the full $3/kg credit level, this output would generate roughly $7.5 million annually, or $75 million over the ten‑year credit life (ignoring discounting). While modest relative to multi‑billion‑dollar capital expenditures, this support is decisive at the margin. Blue hydrogen production costs are commonly estimated at $1.50–$2.50 per kilogram before subsidies, with CCS accounting for a significant share of operating expenses.[4] The 45V credit therefore improves early‑year cash flows, raises expected internal rates of return, and reduces downside risk during the period of greatest uncertainty. Truncating or eliminating the credit can push otherwise viable projects below investment hurdles, delaying or preventing FIDs altogether.

Blue hydrogen faces a classic coordination problem. Industrial consumers are reluctant to sign long‑term offtake agreements without reliable, large‑scale supply, while producers are unwilling to invest billions of dollars without credible demand signals. Government intervention in this instance can lower early‑stage risk and improving project bankability. An intent of 45V was to break this causal loop through allowing supply to come online, costs to decline through scale and learning effects, and demand to gradually expand.

Prior to the passage of OBBB, major U.S. energy firms responded accordingly. ExxonMobil announced plans to integrate blue hydrogen production into its Baytown refinery complex, and Chevron unveiled Project Labrador, a proposed $5 billion blue hydrogen facility in Port Arthur, Texas.[5] These projects were led by firms with deep operational expertise, existing hydrogen demand, and access to CCS infrastructure, suggesting that policy support was enabling credible, execution‑ready investments rather than speculative ventures.

The United States occupies a uniquely strong position in blue hydrogen development. The IEA reports that the U.S. accounts for nearly half of announced hydrogen production projects incorporating carbon capture by 2030. In contrast, several non‑U.S. energy majors have recently retreated from blue hydrogen investments. Shell placed its Aukra blue hydrogen export project in Norway on hold in 2024, citing weak demand and poor economics, while Equinor has also slowed its hydrogen ambitions.[6] These developments show that blue hydrogen markets are unlikely to emerge organically in the near term; they will only develop where policy credibly supports early investment.

OBBB’s changes, therefore, carry outsized implications. Under the enacted legislation, the 45V credit terminates for projects that begin construction after December 31, 2027. Large hydrogen projects typically require five to seven years from concept to groundbreaking due to permitting, engineering, and financing constraints. As a result, the sunset functions less as a gradual phase‑out than as a policy cliff and reintroduces uncertainty.

Allowing the 45V credit to expire as currently enacted risks stalling a domestic blue hydrogen market just as global demand begins to materialize. This outcome would forfeit first‑mover advantages in project development, CCS integration, workforce expertise, and potential export positioning. It also increases the likelihood that other global actors, particularly China, will fill emerging supply gaps and shape standards and supply chains to their advantage.

Maintaining the 45V credit in its original form would support billions of dollars in private investment, reinforce industrial communities (especially along the U.S. Gulf Coast), and demonstrate that American energy firms can expand supply while managing emissions responsibly. In this sense, 45V functions less as a climate subsidy than as a strategic industrial policy tool aligning energy security, economic competitiveness, and environmental stewardship. Curtailing it risks undermining all three.

[1] Inflation Reduction Act, U.S. Congress (2022).

[2] International Energy Agency, Global Hydrogen Review (2025).

[3] ExxonMobil, “Advancing Low-Carbon Solutions at Baytown (ND).

[4] Eliseo Curcio, “Techno-economic analysis of hydrogen production: Costs, policies, and scalability in transition to net-zero”, International Journal of Hydrogen Energy (May 2025).

[5] Engineering News-Record, “Chevron Plans $5B Blue Hydrogen and Ammonia Project in Port Arthur” (July 2025).

[6] Reuters, “Shell shelves Norway project due to lack of demand” (September 2024).

Max Lies is a KBH Energy Center Graduate Fellow and MBA Candidate at the Texas McCombs School of Business, where he focuses on the intersection of energy finance, markets, and public policy. With prior experience at the U.S. Department of the Treasury, Goldman Sachs, and Capstone, as well as a finance internship at ExxonMobil, Max brings a strong analytical and policy-driven perspective to today’s energy challenges. His background across government and financial institutions, combined with his academic focus, positions him to contribute meaningfully to conversations shaping the future of the energy industry.

By Henry Ceverha, KBH Energy Center Graduate Fellow

Carbon accounting used to be a back-office exercise. Today, it is becoming one of the most powerful forces shaping global energy markets.

A new push led by ExxonMobil and BlackRock-backed Carbon Measures aims to move from today’s supply-chain emissions model to product-level measurement. That may sound technical, but it isn’t. How carbon is counted will influence which producers gain advantage, how capital flows, and how energy markets are regulated for decades.

For nearly 25 years, the Greenhouse Gas Protocol (GHGP) has governed corporate emissions reporting. Ninety-seven percent of the S&P 500 use it, and regulators rely on it. GHGP divides emissions into Scope 1 (direct operations), Scope 2 (purchased electricity), and Scope 3 (suppliers and customers).

Scope 3 is the most controversial. If an oil company sells gasoline and an automaker sells the car that burns it, both report the same emissions. That double-counting was intentional, meant to spread responsibility across the value chain.

In practice, it has produced confusion. Scope 3 dominates reported emissions but sits largely outside producers’ control. It relies heavily on estimates and industry averages, allowing similar companies to report very different totals. And because GHGP was never designed for product-level comparison, it lacks what investors and policymakers want: to distinguish low-methane LNG cargoes from leak-prone ones. With carbon border taxes and ESG scrutiny rising, these inconsistencies increasingly affect markets.

That gap has given rise to a new accounting movement. Carbon Measures and its corporate backers — including BASF, Linde, EQT, and Mitsubishi Heavy — are pushing a “product-level carbon ledger.” Instead of estimating emissions across the supply chain, companies would measure them where they occur (flaring, venting, energy use, methane leaks) and assign each ton of carbon to a specific product. That carbon footprint would then follow the product as it moves through the supply chain.

The appeal is obvious. Energy markets already price physical attributes. Crude trades on sulfur content and gravity; natural gas trades on heat value and location. Adding carbon intensity feels like the next step. Producers with strong methane controls could prove it. LNG exporters could certify cleaner cargoes, which is something European buyers increasingly demand. Carbon intensity could quickly become a differentiator rather than a footnote.

But the benefits will not be shared evenly.

Large integrated producers are best positioned. They have already invested in emissions monitoring, electrification, and data systems. They can absorb verification costs and manage carbon across integrated operations. For them, product-level accounting is a competitive advantage.

Smaller independent producers face a different reality. Many operate older pads, rely on variable power, or lack continuous monitoring. Installing methane detection systems and certifying production streams is expensive. Large firms call it transparency; smaller operators experience it as a new cost of doing business, often without any guarantee of growing revenues.

The result could be a two-tier energy market: carbon-advantaged barrels trading at a premium, and uncertified barrels trading at a discount. Even responsible operators may struggle if they lack the infrastructure to prove it. That dynamic could accelerate consolidation in U.S. shale, making scale synonymous with credibility.

Pipelines would face tighter monitoring expectations. LNG exporters would encounter stricter disclosure demands. Banks and insurers could steer capital toward operators able to document emissions performance. Carbon intensity would begin to shape not just regulation, but financing.

The flaws in today’s system are hard to ignore. An estimate-heavy framework that double-counts emissions and obscures real differences between producers no longer works in a world of carbon pricing, trade policy, and energy geopolitics.

Carbon accounting is ready for a market redesign. The question isn’t whether carbon will be regulated, because it already is. The real question is whether the rules reflect common sense and real-world measurement, or accounting fiction. The industry must prepare for an era in which carbon intensity becomes as important as product quality.

Regulation is inevitable. The choice is whether it’s grounded in common sense.

Henry Ceverha is a KBH Energy Center Graduate Fellow and MBA candidate at Texas McCombs School of Business. Prior to business school, he held engineering roles at SLB, Liberty Energy, and Repsol, gaining firsthand operational insight across drilling and completions. At McCombs, Henry has taken on leadership roles as President of the Energy Finance Group and Fund Manager within the Texas McCombs Investment Advisers program, where he helps manage a $24M portfolio. His experience spans both the field and the financial side of energy, positioning him to thoughtfully evaluate opportunities across the energy industry.