ONG Report: Kinetic Blockades Tighten Global Oil as US Drilling Consolidates

Heavy Crude Squeeze: Venezuela Blockade and U.S. Rig Shifts in Late 2025

The late stages of 2025 have brought an unprecedented squeeze in heavy crude oil supply. A U.S.-enforced blockade on Venezuelan oil tankers is choking off a key source of heavy, sour crude, while hopes of replacing those barrels with Middle Eastern supply are fading. At the same time, U.S. drilling activity is becoming more selective, with rig counts falling overall even as some regions add rigs. These dynamics matter because heavy crude is essential for producing diesel and other fuels at complex refineries – and yet heavy grades make up barely 10% of U.S. oil output, meaning refiners depend heavily on imports. In this report, we break down the current developments and what they mean for energy investors and operators.

Your 6 Key Takeaways This Week

The Kinetic Blockade Escalates

The US strategy has shifted from passive sanctions to active naval interdiction. With the seizure of The Skipper and the Centuries—and the pursuit of a third vessel—the US Navy is effectively enforcing a physical firewall. This "total enforcement" doctrine creates a zone of exclusion that skyrockets insurance premiums and freezes Venezuelan export logistics.

The Diluent Trap

Perhaps more damaging than the export blockade is the severing of inbound supply lines. A tanker carrying 32,000 metric tons of Russian naphtha made a U-turn to avoid US forces. Without this essential diluent, Venezuela’s extra-heavy Orinoco crude cannot flow through pipelines, forcing immediate upstream production shut-ins.

The Substitution Myth

Market hopes that Iraqi crude could seamlessly replace Venezuelan barrels are colliding with economic reality. Iraqi economists estimate that the $3.50 per barrel shipping cost to the US Gulf Coast erases the discount on Basrah Heavy crude. For traders, the arbitrage window is closed; it is more profitable to sell those barrels to Asia than to ship them to the US.

OPEC+ Handcuffs

Even if the arbitrage economics worked, Iraq is politically constrained. Baghdad is under pressure to compensate for previous overproduction within the OPEC+ framework. Ramping up exports to the US to backfill Venezuela would violate these quotas, risking a diplomatic rift with Saudi Arabia and Russia.

Drilling Divergence

The US upstream sector is displaying extreme capital discipline. While the national rig count plunged by 8 rigs this week due to price volatility, Oklahoma actually added a rig. This signals a "flight to quality," where operators are concentrating limited capital in high-return core basins (like the Cana Woodford) while abandoning marginal acreage elsewhere.

The Asset Recovery Doctrine

The Trump administration has reframed the blockade not just as a political tool, but as a debt collection mechanism. By explicitly demanding the return of "stolen" assets expropriated from companies like ExxonMobil, the US is establishing a new foreign policy precedent: using kinetic power to enforce corporate restitution claims.

What’s happening with Venezuela’s oil blockade?

The United States has escalated from sanctions to an active naval blockade of Venezuelan oil, seizing multiple tankers in the Caribbean. In early December, U.S. forces seized a supertanker called The Skipper – the first vessel targeted under President Trump’s new “total blockade” order. Just days later, on December 20, the U.S. Coast Guard intercepted a second tanker, identified as the Panama-flagged Centuries, which was carrying ~1.8 million barrels of Venezuelan heavy Merey crude bound for China. The Centuries had been operating as part of a “shadow fleet,” using a false name (“Crag”) to evade detection. Venezuelan officials denounced the seizures as “theft and hijacking” and “a serious act of international piracy”.

U.S. authorities are not stopping at two ships. A third tanker is under pursuit by the Coast Guard in international waters near Venezuela. Reports identify this vessel as the Bella 1, a Very Large Crude Carrier that was previously sanctioned for Iran-linked oil trades. If U.S. forces succeed in intercepting the Bella 1, it would mark the third tanker stopped in less than two weeks. The rapid sequence of interdictions shows that Washington’s “blockade” is not just rhetoric – it is being actively enforced with military assets.

This crackdown has immediate implications for oil supply. Since the first ship seizure, Venezuelan crude exports have plunged, with loaded tankers now essentially stranded in port rather than risk confiscation. Analysts estimate that nearly 1 million barrels per day of Venezuelan oil could be effectively sidelined if the embargo holds, a loss that “is likely to push oil prices higher” if it persists. China – Venezuela’s largest customer – is already seeing shipments disrupted, and tankers laden with Venezuelan oil are loitering rather than sailing.

Beyond blocking exports, the U.S. blockade is also choking off Venezuela’s ability to produce. Venezuela’s extra-heavy crude must be diluted with lighter oils or naphtha to be transported, much of which it usually imports from Russia. Now, tankers carrying Russian diluent are turning back to avoid interception – one ship with 32,000 tons of Russian naphtha bound for Venezuela made a U-turn and sailed to Europe instead. Without that diluent, Venezuela will quickly run out of storage and be forced to shut in oil wells. Industry experts warn that PDVSA (the state oil company) is days away from hitting storage limits, after which production cuts become unavoidable. In short, the U.S. blockade is squeezing Venezuela’s oil industry from both ends – stopping exports and cutting off the inputs needed to keep oil flowing.

Can Iraqi crude replace Venezuela’s heavy oil?

With Venezuelan barrels suddenly off the market, attention has turned to other heavy crude producers. In theory, Middle Eastern heavy sour crudes (like Iraq’s) could substitute for Venezuela’s in refineries that need that quality. Iraq’s Basrah Heavy grade is geologically similar to Venezuelan crude and currently trades at a discount of about $4 per barrel relative to Iraq’s medium grade. This raised hopes that U.S. refiners might simply import more Iraqi oil to fill the gap. However, economic reality is spoiling that idea.

Iraqi oil experts point out that shipping Basrah Heavy to the U.S. Gulf Coast costs roughly $3.50 per barrel in freight and insurance. That expense would nearly erase the price discount. “The margin just doesn’t justify it,” says Nabil Al-Marsoumi, an economist cited in Baghdad, explaining that it’s not financially viable for Iraq to replace Venezuela in the U.S. market. Essentially, any Iraqi heavy crude would arrive with almost no cost advantage – and traders aren’t going to move oil halfway around the world for free. Asian buyers remain closer and often willing to pay a premium for those barrels, so Iraq has little incentive to reroute oil to America.

There’s also a hard limit on Iraq’s ability to boost exports in the first place. Iraq is a member of the OPEC+ alliance, which means its production volumes are capped by a quota agreement. Currently, Baghdad is actually restraining output below its allowance to compensate for previous overproduction. This means Iraq cannot simply open the taps to offset a Venezuela shortfall without breaching its OPEC commitments – something it is unlikely to do given the importance of OPEC+ cohesion. In summary, the Middle East isn’t riding to the rescue. Other heavy-crude exporters like Saudi Arabia and Kuwait are also bound by quotas or long-term contracts, and diverting supply to the U.S. would carry similar shipping costs. For U.S. Gulf Coast refiners, there is no quick one-for-one replacement for Venezuela’s heavy crude. The loss of those barrels could create a tighter market for heavy sour grades, potentially driving up the price spread between heavy and light oil.

How are U.S. drilling trends diverging by region?

Even as global heavy crude supplies tighten, U.S. domestic drilling activity is sending mixed signals. The overall U.S. rig count – a key indicator of future oil and gas production – has been falling. According to Baker Hughes data, the total active drilling rigs nationwide dropped to 542 as of mid-December, down 6 rigs in a week. Most of the decline is in oil-directed rigs, which fell by 8 to about 406 active oil rigs – a sharp year-over-year drop (there were 483 oil rigs a year ago). This suggests that many companies are pulling back on drilling new oil wells, likely due to lower prices earlier in the year and investor pressure to maintain capital discipline.

However, not all regions are following the national decline. In an interesting counter-trend, Oklahoma added a rig last week, bringing it up to 42 active rigs. That’s roughly flat compared to a year ago (when Oklahoma had 43 rigs), but it stands out because many other oil-producing states saw declines. For instance, in the same week Texas (by far the largest drilling state) saw a modest increase of 2 rigs to 230, while New Mexico (the second-largest, home to part of the Permian Basin) lost 2 rigs, down to 102. Other states like Colorado and Utah each dropped a rig. The contrast between Oklahoma and the national picture highlights how operators are focusing on specific “core” areas. Oklahoma’s steady rig count likely reflects ongoing investment in its most productive shale plays (such as the SCOOP/STACK), where companies see competitive returns. In less productive or higher-cost areas, firms are content to let rigs go idle.

This high-grading of drilling portfolios means U.S. production can hold up or even grow slightly with fewer total rigs, as long as those rigs concentrate in top-tier basins. But it also signals caution: producers are not broadly ramping up activity despite the geopolitical turmoil. They appear to be prioritizing financial discipline over expanding output at any cost. If heavy crude supplies tighten globally, the U.S. shale patch isn’t racing to fill the gap – especially since most shale oil is light and not a direct substitute for Venezuelan-type crude.

Challenges and Trade-Offs

The current situation creates several challenges and trade-offs for the oil market and stakeholders:

• Refiners’ Dilemma – Feedstock Flexibility vs. Fuel Output: U.S. refiners, especially on the Gulf Coast, have hardware designed for heavy sour crude. Losing Venezuelan oil puts them in a bind: do they pay a premium for alternate heavy barrels, cut runs, or try to process lighter oil and risk lower diesel output? Each option has downsides. Heavier Canadian crude is available via pipeline and rail, but logistical limits mean not all lost Venezuelan supply can be replaced. Running lighter domestic crudes can keep refineries fed, but because light oil yields more gasoline and less diesel, it could tighten diesel supplies and reduce refining margin capture. Refiners must balance feedstock quality against output needs, and some may need to invest in process adjustments if the blockade persists.
• Geopolitical Enforcement vs. Market Stability: The U.S. government’s aggressive enforcement of oil sanctions is achieving foreign policy aims – strangling revenue to the Maduro regime – but at the cost of market predictability. This trade-off pits geopolitical strategy against energy market stability. If the blockade removes nearly 1% of global supply, oil prices could rise, undermining consumer economies. U.S. officials downplay the impact on prices (noting Venezuela’s exports are a small fraction of world supply), but traders view the seizures as an escalation that puts more barrels at risk. The challenge for policymakers is how far to go with enforcement before it backfires on global oil price stability. Other countries are watching closely – the precedent of using gunboats to halt oil trade is raising concerns about international law and future retaliations.
• Producer Caution – Capital Discipline vs. Supply Growth: U.S. oil producers face a classic trade-off between ramping up drilling to seize a market opportunity versus maintaining the capital discipline that investors demand. The heavy crude shortage might signal higher prices for those grades, but most American production is light oil that doesn’t directly fill the heavy crude gap. Companies with the ability to produce heavier oil (for example, certain conventional fields or oil sands investments) could benefit, yet few are rushing to significantly boost capex. The risk of overshooting demand and causing another price slump weighs on decision-makers. Thus, even as OPEC+ cuts and the Venezuela situation tighten supplies, U.S. producers are mostly holding steady, which could lead to tighter markets in 2026 if demand surprises to the upside. The trade-off here is short-term gain versus long-term stability: drill too much and prices could crash; drill too little and global inventories may draw down quickly.
• Substitution Constraints – Logistics vs. Demand Needs: The idea of swapping in another country’s oil (like Iraq’s) for Venezuela’s runs into logistical and economic constraints. The challenge is that not all crude is created equal – heavy, high-sulfur oil is in a specialized niche. As discussed, Iraq’s barrels are limited by both OPEC policy and high transport costs. Other heavy producers (Canada, Brazil, Mexico) have either capacity constraints or their own commitments. This means consumers and refiners face a tough reality: demand for heavy oil might outstrip readily available supply. Inventories of heavy crude could dwindle, driving up pricing differentials. In the interim, some refiners might import intermediate sour grades or blend crudes to mimic the desired spec, but these workarounds are imperfect. The market’s usual flexibility is reduced when one of the major heavy suppliers is effectively offline, highlighting a vulnerability in the energy system.

Opportunities and Recommended Actions

Despite the headwinds, there are strategic moves that investors and industry players can consider in this evolving landscape:

• Secure Alternative Heavy Supply Lines: Refiners and traders can look to Canada and Latin America (such as Mexico’s Maya crude) to lock in long-term heavy crude contracts. Canadian heavy (like Western Canadian Select) is a prime candidate, as it’s already a significant source for U.S. Gulf refiners. Why it matters: Proactively securing supply from stable partners can insulate operations from volatility and give a bargaining edge on price. Trade-off: Canadian heavy often comes with transportation bottlenecks, so investing in pipeline or rail capacity may be necessary to truly secure these barrels.
• Invest in Refinery Flexibility: Companies operating complex refineries should consider process upgrades to handle a wider range of crude quality. This might include adding pre-processing units or upgrading cokers and desulfurization equipment to cope with lighter or more sour crudes as needed. Why it matters: Enhancing flexibility means a refinery can switch feedstocks if one type becomes scarce or pricey. Risk: These capital projects are costly and take time – and if the crude slate returns to normal (e.g., Venezuela exports resume down the line), the investment might not pay off quickly. Nonetheless, flexibility is a hedge against geopolitical supply shocks.
• Monitor Heavy-Light Price Spreads: Investors in oil futures and equities should closely watch the spread between heavy and light crude prices (e.g., Mars or WCS vs. WTI). A widening spread could signal profit opportunities – for instance, upstream firms with heavy oil reserves might see improved margins, and downstream players geared to heavy crude could face higher input costs but also better diesel cracks. Why it matters: Understanding this dynamic allows investors to position for scenarios like a prolonged Venezuela outage or a sudden policy reversal. Consideration: Geopolitical situations can change abruptly (for example, a diplomatic deal with Venezuela could quickly narrow the spread), so this strategy requires staying alert to news and possibly using hedging instruments.
• Leverage Strategic Reserves or Stockpiles: Governments and large consumers should evaluate strategic petroleum reserves (SPR) with an eye on crude quality. The U.S. SPR, for example, has historically held a mix of crudes, including some sour barrels. In a severe shortage of heavy crude, releasing sour crude from reserves could alleviate refiners’ woes temporarily. Why it matters: SPR releases targeted by quality could stabilize markets in the face of an acute shortage, buying time for commercial stocks to readjust. Caveat: SPR policy is a blunt tool and political approval can be contentious; it’s typically reserved for emergencies, not to offset sanctions-driven gaps. Still, having a plan for quality-specific releases is a prudent contingency.
• Engage in Policy Dialogue and Risk Mitigation: Energy companies can play a role by engaging with policymakers about the impacts of sanctions and the importance of energy-market stability. Supporting diplomatic efforts or contingency plans (such as waiver programs for certain volumes or countries) might be in the industry’s interest. Why it matters: A seat at the table ensures that the trade-offs between national security goals and economic impacts are fully considered. Risk: This can be politically sensitive – companies must tread carefully to avoid the appearance of undermining sanction policy. However, providing data on how supply constraints affect fuel prices and industries can lead to more informed decisions at the national level.

Heavy Crude Markets are Entering 2026 Under Strain

As the U.S. blockade on Venezuela’s oil exports creates a tangible “feedstock friction” between what complex refineries need and what the market can readily supply. The single most important takeaway is that not all barrels are interchangeable – removing one of the world’s major heavy crude sources has outsized ripple effects on diesel, shipping, and global price balances. Meanwhile, U.S. drillers remain cautious, boosting efficiency rather than volume, which means the cavalry of new supply may not be coming to the rescue if prices spike.

In the near term, investors and operators should prepare for a scenario where heavy sour crude prices stay elevated relative to benchmarks, and refining margins for certain fuels fluctuate accordingly. Policymakers will be watching the effect on inflation and may adjust strategies if oil prices become a domestic concern. Looking forward, keep an eye on OPEC+ decisions – if heavy crude shortages persist, other producers (like Saudi Arabia) might adjust quality-specific output or exports to prevent an overheating of that segment of the market. Also, any diplomatic developments with Venezuela (or Iran, given the “shadow fleet” interplay) could rapidly change the equation.

Ultimately, the late-2025 events serve as a reminder of the delicate balance in global energy logistics. The oil market is well-supplied in aggregate, but the wrong barrel in the wrong place can still cause a crunch. Investors should watch how these supply dynamics evolve into 2026 and be ready to act on opportunities – or risks – arising from the heavy crude squeeze. At Bass EXP, we’ll continue to track these shifts and help our partners navigate the challenges. We don’t just follow the news – we put it to work. Learn more about direct participation in oil and gas and how to capitalize on energy market dislocations at bassexp.com.