ONG Report: U.S. Pursues Offshore Dominance While Australia Struggles with Supply

U.S. Offshore Push Meets a Fragmenting Energy System

Global Supply Shifts: 4 Key Takeaways This Week

1. Australia’s LNG Export Paradox

Australia remains one of the world’s largest LNG exporters, supplying roughly one‑fifth of global LNG trade, yet it is grappling with tightening domestic gas supply and rising prices on its east coast.

• Export strength, local strain. National gas output more than doubled between 2015 and 2021, then plateaued while demand in the populous southeast continued to rise. Production growth has stalled even as export commitments remain large.
• Structural bottlenecks. Western and northern basins feed LNG export terminals, but there is no pipeline connecting those regions to the main east‑coast demand centers. Eastern markets rely on local basins and Queensland coal‑seam gas (CSG) fed through constrained pipelines.
• Policy intervention. Regulators have moved from “light‑touch” to active intervention: the Australian Domestic Gas Security Mechanism (ADGSM) can now restrict LNG exports in quarterly assessments if a shortfall is forecast, and a mandatory Gas Market Code sets a default A$12/GJ price ceiling for many new east‑coast wholesale contracts under rules running into the next decade.

For investors, Australia is still a global LNG heavyweight, but domestic constraints, regulatory tightening, and stalled exploration are eroding the reliability of its export engine.

2. Venezuela and Russia Solidify an Energy–Sanctions Alliance

Venezuela is deepening its alignment with Russia across energy, finance, and security as both states look for ways around Western sanctions.

• Long‑term treaty framework. In 2025 the two countries signed a Strategic Partnership and Cooperation Treaty, later ratified by both capitals. The agreement runs for 10 years with automatic five‑year extensions and spans energy, mining, transport, defense cooperation, and financial systems. It explicitly commits both countries to oppose “unilateral coercive measures” and to expand joint oil and gas activities, including new field development and boosting output from existing joint ventures.
• Joint ventures extended. Venezuela’s National Assembly has approved long‑dated extensions of oil joint ventures between PDVSA and Russian partners, allowing operations in key fields to run well into the 2040s and targeting incremental investment and production growth.
• Alternative shipping and finance. The treaty encourages the creation of an alternative system of oil‑transport insurance and a separate bilateral financial system to settle trade outside Western‑dominated channels.

This emerging “sovereign energy bloc” does not remove sanctions risk, but it does give Russian and Venezuelan barrels more ways to reach the market and supports the durability of the global “dark fleet” and non‑dollar trade.

3. U.S. Offshore Drilling Expands to New Coasts

The Trump administration has announced the most aggressive offshore leasing push in decades, aiming to reinforce U.S. “energy dominance” with a new five‑year Outer Continental Shelf (OCS) program covering 2026–2031.

• New leasing frontiers. The draft plan contemplates up to 34 lease sales across federal waters: six off California between 2027 and 2030, more than 20 in Alaska (including a new “High Arctic” zone), and several in the eastern Gulf of Mexico in areas at least 100 miles from the Florida coast.
• Policy reversal and political risk. This is a clear reversal from the previous administration’s more limited offshore program. It has already triggered bipartisan resistance in California and Florida, where leaders cite spill risk, tourism exposure, and military range conflicts in the eastern Gulf.
• Regulatory bottlenecks. Even if leases are sold, development is not guaranteed. Litigation over endangered species such as Rice’s whale in the Gulf has already pushed courts to scrutinize environmental reviews and, in some cases, send lease decisions back to regulators. That precedent raises the risk that parts of the new OCS program end up in “permit purgatory” — leased but undevelopable for years.

For investors, the offshore Gulf, Alaska, and Pacific margins remain long‑cycle, high‑capex opportunities that are increasingly shaped by courts and coastal politics, not geology.

4. Australia’s Market Weight

Australia’s role as a supplier of roughly 20% of global LNG shipments gives its policy decisions outsized importance for buyers across Asia and Europe.

Any move that tightens export volumes or undermines confidence in contract sanctity will ripple through global LNG pricing and prompt buyers to diversify further toward the United States, Qatar, and emerging producers.

Structural Imbalances in a Leading Exporter

Market Dominance vs. Domestic Scarcity

Australia is a case study in the risks of building a gas system around exports without solving internal bottlenecks.

• Geographic mismatch. The most prolific basin, North Carnarvon off Western Australia, is physically separated from the main east‑coast demand centers, with no transcontinental pipeline linking them. Most western and northern offshore discoveries naturally feed LNG export plants instead of domestic users.
• East‑coast squeeze. The “eastern market” of New South Wales, Victoria, and Queensland depends on a mix of aging southern basins and CSG from Queensland. Pipeline capacity south into Victoria and NSW is constrained, so winter peaks routinely expose local shortfalls and price spikes.
• Regulator warnings. The Australian Competition and Consumer Commission (ACCC) and the Australian Energy Market Operator (AEMO) have repeatedly warned of east‑coast supply risks later this decade if new projects and infrastructure lag, including the potential for industrial curtailments and winter reliability concerns.

How Policy Choices Created the Crisis

The current situation stems less from geology than from market design and regulatory choices.

1. Pricing to the Asia netback.
   When long‑term low‑priced contracts rolled off after 2016, domestic prices on the east coast began tracking Asia LNG “netback” pricing (Asian spot prices minus liquefaction and shipping). Domestic buyers now compete directly with importers in North Asia. A weak Australian dollar further amplifies global price shocks at home.
2. Exploration slowdown.
   Offshore exploration has fallen sharply. The first new hydrocarbon exploration well in several years only appeared in 2025, after a long pause in offshore wildcats.
3. Regulatory fatigue and slow approvals.
   Large projects such as the Narrabri gas development and expansions at major LNG hubs have faced long approval timelines and heavy environmental scrutiny. A high‑profile example was a proposed multibillion‑dollar acquisition of Santos by Abu Dhabi’s ADNOC, which was ultimately abandoned amid concerns about regulatory complexity, domestic gas obligations, and environmental pressures.
4. Tightening export controls and price caps.
   • The ADGSM, introduced in 2017 and hardened in 2023, now allows quarterly export restrictions if a domestic shortfall is projected and requires LNG exporters to contribute to closing any gap.
   • A mandatory Gas Market Code sets a default A$12/GJ cap for many new east‑coast wholesale contracts, with the framework expected to run through 2033, subject to review.

These interventions support households and manufacturers in the short term but can also mute price signals just when new supply and infrastructure are needed most.

Importing What You Export

The sharpest symbol of policy failure is that Australia is now building LNG import capacity to stabilize a gas system built on exports.

• Port Kembla (NSW). Squadron Energy’s Port Kembla terminal has completed major construction and is moving through commissioning, with guidance pointing to potential first gas around mid‑decade, though schedules remain sensitive to market conditions.
• Victoria import projects. Victoria has approved a floating LNG terminal near Geelong, and another large‑scale import terminal is being advanced in Port Phillip Bay, targeting operations in the late 2020s to backstop expected shortfalls.

Importing gas into a country that already exports LNG in large volumes will embed a structurally higher cost base (liquefaction, shipping, regasification) into domestic pricing. For energy‑intensive industry, that is a durable headwind.

The “Free Gas” Controversy

Debate over whether Australians are getting fair value for their gas has intensified.

Independent research estimates that more than half of Australia’s exported gas volumes have attracted no royalties in recent years, due to the design of the Petroleum Resource Rent Tax and large carried‑forward deductions on capital‑intensive projects. Over a four‑year period, these royalty‑free exports are estimated in the hundreds of billions of Australian dollars in sales, with tens of billions in potential royalties effectively foregone.

The numbers are contested by industry, but the perception of a “giveaway” has strengthened calls for higher resource taxation and added another layer of sovereign‑risk debate for investors.

The Geopolitical Weaponization of Energy

Venezuela–Russia: Building a Parallel Energy System

The renewed Russia–Venezuela alignment is about more than one or two oilfields. It is an attempt to harden a parallel energy and financial system that is less vulnerable to Western pressure.

Key components include:

• Upstream and downstream cooperation. The treaty calls for joint exploration and development of new oil and gas fields and for increasing production from existing joint ventures. That is critical for Venezuela’s mature, technically challenging extra‑heavy oil reserves in the Orinoco Belt, which rely on specialized technology and diluents.
• Power‑grid stabilization. Russia and Venezuela have pledged joint projects to retrofit generating assets and modernize transmission and distribution infrastructure—essential for maintaining oil output and domestic stability in Venezuela’s frequently stressed grid.
• Alternative insurance and payments. The partnership explicitly contemplates developing an alternative oil‑transport insurance system and a separate bilateral financial system. Together with Russia’s existing shadow‑fleet practices and non‑Western payment tools, this is designed to reduce reliance on Western banks, dollar clearing, and traditional shipping insurance.

This architecture will not fully insulate Moscow or Caracas from sanctions, but it makes enforcement more complex and suggests the shadow fleet and non‑dollar energy trade are becoming a persistent, not temporary, feature of the market.

The 2026–2031 Offshore Strategy in the U.S.

From Minimum Compliance to Maximal Leasing

The new OCS program marks a clear shift from a minimal‑leasing posture to an expansive one.

• Alaska and the High Arctic. Over 20 proposed lease sales in Alaskan waters, including in a newly designated “High Arctic” zone, are framed as a way to maintain U.S. industrial and strategic presence in a region where Russia and China are already active.
• California returns to the map. Six planned lease sales off California between 2027 and 2030 would be the first new federal leases in those waters since the mid‑1980s. This comes as Sable Offshore Corp. seeks to restart production from platforms off Santa Barbara damaged by the 2015 Refugio spill, with vocal backing from federal officials.
• Florida and the eastern Gulf. New sales are proposed in the eastern Gulf of Mexico, at least 100 miles from Florida’s shore, with the goal of mitigating visual and tourism concerns. Florida’s political leadership—including Republicans who previously helped block similar plans—remains wary, given the state’s dependence on tourism and its history of bipartisan opposition to nearby drilling.

The Legal and Environmental Battlefield

While the plan broadens federal access on paper, the real constraint is legal and regulatory risk.

• Endangered species litigation. Lawsuits over Rice’s whale in the Gulf of Mexico have already led courts to find that some lease sale decisions did not adequately consider impacts, forcing revisions and delays. That experience gives environmental groups a tested playbook for challenging future leases if they perceive gaps in endangered‑species or climate analysis.
• State‑level “infrastructure blockades.” Even where federal leases move ahead, coastal states can slow or block pipelines and onshore terminals in their jurisdictions. California’s political leadership has signaled it will use coastal permitting to resist new offshore developments despite federal interest.

For investors, this means that bidding success in a lease auction is only the starting point. Project timelines and risk‑adjusted returns will hinge on permitting outcomes, litigation cycles, and state‑federal coordination.

The Fragmentation of Energy Security

Across Australia, the Russia–Venezuela axis, and U.S. offshore policy, a common theme emerges: security and politics are increasingly trumping pure market efficiency.

• In Australia, export‑oriented gas policy has collided with domestic affordability and security concerns. The result is heavy intervention (export controls, price caps, import terminals) layered on top of a still‑liberalized export model.
• In Venezuela and Russia, regime survival and sanctions resistance drive decisions, even when they reduce access to Western capital and technology.
• In the United States, onshore shale remains highly competitive, yet federal policy is now pushing deeper into high‑cost offshore basins to entrench long‑term supply and project “energy dominance,” despite legal and environmental friction.

What This Means for BassEXP Investors

1. Offshore remains strategic.
   The U.S. move to expand offshore leasing, coupled with geopolitical threats to key maritime routes and export infrastructure, underscores why offshore production continues to matter for long‑term supply security—not just in the Gulf of Mexico, but globally.
2. LNG buyers will diversify away from single‑point risk.
   Australia’s domestic gas crunch is a warning to other “energy superpowers”: heavy export commitments without internal balance can force abrupt policy shifts. Buyers will continue to diversify toward U.S. and Qatari LNG, and investors should expect more scrutiny of export controls and domestic‑supply guarantees in every major exporting country.
3. Sanctions are spawning a dual‑track oil market.
   The Russia–Venezuela alliance, alternative insurance systems, and shadow fleet dynamics are embedding a split between a compliance‑based market and a sanctions‑resistant sovereign market. That split affects freight costs, differentials, and the durability of official sanctions regimes—and can create episodic pricing dislocations that favor nimble operators.
4. Policy risk deserves a bigger discount.
   From Australia’s ADGSM and gas price caps to U.S. endangered‑species litigation and state‑level infrastructure fights, policy and regulatory risk are now central drivers of value. Subsurface quality and headline volumes matter, but the ability to move molecules to market under stable rules is often the real bottleneck.

For BassEXP investors, the core takeaway is straightforward: geology still sets the opportunity, but law, logistics, and politics increasingly set the realized return.