1. Executive Summary

The Australian oil and gas sector stands at a critical inflection point in April 2026. Crude oil prices have surged to levels not seen since the immediate aftermath of the 2022 Russia-Ukraine conflict, with West Texas Intermediate (WTI) trading at approximately USD 115.10 per barrel, representing a remarkable year-on-year increase of 93.19 percent. This dramatic price appreciation has been driven by a confluence of geopolitical disruptions, most notably the escalation of tensions between the United States and Iran, the effective closure of the Strait of Hormuz to commercial tanker traffic, and the resulting removal of approximately 20 percent of global oil supply from the market. Against this backdrop, ASX-listed oil and energy companies have experienced extraordinary share price appreciation, with the sector delivering one of its strongest performances in recent memory.

2. Introduction to the Global Oil Market

Crude oil is the single most important commodity in the global economy and remains the world's most actively traded physical asset. The global oil market encompasses a vast and interconnected network of producers, refiners, transporters, traders, and consumers spanning every continent. In 2025, global oil demand reached approximately 103 million barrels per day (mb/d), a figure that has continued to climb despite the accelerating deployment of electric vehicles and renewable energy technologies. The sheer scale of the oil market, with annual revenues exceeding USD 3.5 trillion, underscores its continued centrality to global economic activity, international trade balances, and geopolitical power dynamics.

2.1 Historical Context and Market Evolution

The modern oil industry traces its origins to the mid-nineteenth century, when the first commercial oil well was drilled in Pennsylvania, United States, in 1859. Over the subsequent 167 years, the industry has undergone multiple transformative cycles, from the era of the Seven Sisters oil majors that dominated global production through the mid-twentieth century, to the formation of the Organisation of the Petroleum Exporting Countries (OPEC) in 1960, which fundamentally altered the balance of power between producing and consuming nations. The oil shocks of 1973 and 1979 demonstrated the commodity's capacity to reshape global economic fortunes, while the emergence of US shale production in the 2010s represented perhaps the most significant supply-side revolution since the opening of the Middle Eastern oilfields.

Australia's participation in the global oil market has evolved considerably over the decades. The nation's first significant oil discovery was made at Moonie in Queensland in 1961, followed by the transformative Bass Strait discoveries off the coast of Victoria in the late 1960s. These discoveries fundamentally altered Australia's energy security profile and laid the foundations for the domestic oil and gas industry that exists today. By the early 1980s, Australia was producing approximately 600,000 barrels per day, approaching self-sufficiency in crude oil. However, the natural decline of legacy fields, particularly in the Bass Strait, has seen domestic production fall significantly, with Australia now producing approximately 350,000 barrels per day and importing the majority of its refined fuel requirements.

2.2 Market Structure and Key Participants

The global oil market operates through a complex hierarchy of participants, each playing a distinct role in the value chain. At the upstream end, national oil companies (NOCs) such as Saudi Aramco, the Abu Dhabi National Oil Company (ADNOC), and the Kuwait Petroleum Corporation control the majority of the world's proven reserves and production capacity. International oil companies (IOCs) including ExxonMobil, Shell, BP, TotalEnergies, and Chevron operate across the full value chain, from exploration and production through refining and retail distribution. Independent exploration and production companies focus exclusively on the upstream segment, accepting higher geological and operational risk in exchange for leveraged exposure to commodity prices.

The midstream segment encompasses the transportation, storage, and wholesale trading of crude oil and refined products. This includes pipeline operators, tanker fleets, storage facility owners, and the trading desks of major financial institutions. The downstream segment involves the refining of crude oil into usable products such as gasoline, diesel, jet fuel, and petrochemical feedstocks, followed by the distribution and retailing of these products to end consumers. Each segment of the value chain exhibits distinct risk-return characteristics, capital requirements, and sensitivity to oil price fluctuations, a dynamic that is clearly reflected in the diversity of ASX-listed oil and energy companies.

2.3 The Role of Oil in the Modern Economy

Despite the growing prominence of renewable energy sources, oil continues to supply approximately 31 percent of global primary energy demand, making it the single largest source of energy consumed worldwide. The transportation sector remains the dominant source of oil consumption, accounting for approximately 57 percent of total demand, with road transport, aviation, and maritime shipping all heavily dependent on oil-derived fuels. Industrial uses, including petrochemical production, represent a further 14 percent of demand, while power generation, heating, and other applications account for the remainder.

The inelastic nature of oil demand in the short term is a critical factor for investors to understand. Unlike many commodities, where consumers can readily switch to alternatives when prices rise, the substitution options for oil are limited in the near term. Vehicles powered by internal combustion engines cannot switch to alternative fuels, airlines have no viable substitute for jet fuel at commercial scale, and the petrochemical industry requires oil-based feedstocks for the production of plastics, fertilisers, and pharmaceutical ingredients. This demand inelasticity amplifies the price impact of supply disruptions, as the world has witnessed repeatedly throughout history and is experiencing again in 2026 with the Strait of Hormuz crisis.

For Australian investors, the oil market's significance extends well beyond the direct performance of energy equities. Oil prices influence the Australian dollar exchange rate, impact inflation readings and monetary policy decisions by the Reserve Bank of Australia, and affect the profitability of energy-intensive industries across the economy. The performance of ASX-listed oil companies also has meaningful implications for superannuation fund returns, given the significant weightings of resources and energy stocks in major index funds and institutional portfolios.

2.4 Oil Market Trading Mechanisms and Financial Instruments

The oil market operates through both physical and financial trading mechanisms, with the financial derivatives market dwarfing the physical market in terms of daily transaction volumes. Crude oil futures contracts, traded on exchanges such as the NYMEX and ICE, allow producers, refiners, and traders to hedge their exposure to price fluctuations, while also providing a venue for financial speculators to express directional views on oil prices. The open interest in crude oil futures and options contracts regularly exceeds several billion barrels, far exceeding annual global physical oil consumption of approximately 37 billion barrels.

Options on crude oil futures provide additional risk management and speculative tools, allowing market participants to hedge against extreme price movements or to position for specific price scenarios. The options market has been particularly active in 2026, with implied volatility surging to multi-year highs as traders price in the wide range of possible outcomes arising from the Strait of Hormuz crisis. For institutional investors analysing ASX-listed oil companies, understanding the derivatives market is important because many producers use hedging programmes to lock in future production revenues, which can either protect against price declines or limit participation in price rallies.

Exchange-traded funds (ETFs) have become an increasingly popular vehicle for investors seeking exposure to oil prices without the complexity of direct futures trading or individual stock selection. On the ASX, the BetaShares Crude Oil Index ETF (ASX: OOO) provides exposure to WTI crude oil futures, while broader energy ETFs include the VanEck Australian Resources ETF and the BetaShares Global Energy Companies ETF. These products offer diversification and liquidity benefits, although they are subject to contango effects in the futures market that can erode returns over extended holding periods.

3. Crude Oil Pricing Explained: WTI vs Brent

Understanding the mechanics of crude oil pricing is essential for investors analysing ASX-listed oil companies, as the choice of benchmark, the quality of crude produced, and the geographic location of production assets all influence the revenues that companies ultimately realise. The two primary global benchmarks for crude oil pricing are West Texas Intermediate (WTI) and Brent crude, each of which serves as a reference price for different segments of the global market.

3.1 West Texas Intermediate (WTI)

West Texas Intermediate is a light, sweet crude oil that serves as the primary benchmark for oil pricing in the United States and the Americas. WTI has an API gravity of approximately 39.6 degrees, indicating a relatively light density, and a sulphur content of approximately 0.24 percent, classifying it as sweet crude. WTI futures are traded on the New York Mercantile Exchange (NYMEX), with the delivery point specified at Cushing, Oklahoma, a major oil storage and pipeline hub. As of early April 2026, WTI is trading at approximately USD 115.10 per barrel, having surged from approximately USD 57.42 per barrel at the start of the year, representing a year-to-date increase of more than 100 percent.

3.2 Brent Crude

Brent crude is the international benchmark most widely used for pricing oil outside the Americas. Originally derived from crude oil produced in the Brent oilfield in the North Sea, the benchmark has evolved to incorporate production from multiple North Sea fields and is now formally known as Brent-Forties-Oseberg-Ekofisk-Troll (BFOET). Brent futures are traded on the Intercontinental Exchange (ICE), and the benchmark is used to price approximately two-thirds of the world's internationally traded crude oil. Brent has historically traded at a premium to WTI, reflecting its seaborne delivery mechanism and its greater relevance to international markets. As of April 2026, Brent crude is trading above USD 113 per barrel, with the Brent-WTI spread having narrowed amid the global supply disruption.

3.3 Implications for Australian Producers

Australian crude oil and condensate production is typically priced relative to Brent crude or regional Asian benchmarks such as the Dated Brent or Tapis crude markers. This is significant for ASX-listed producers because the revenues they generate are directly influenced by Brent pricing dynamics rather than WTI. Woodside Energy, as Australia's largest oil and gas producer, realises prices that closely track Brent-linked contract prices, particularly for its liquefied natural gas (LNG) cargoes, which are predominantly sold under long-term contracts with oil-indexed pricing formulas. Santos similarly reports realised prices relative to Brent-linked benchmarks, while Karoon Energy's Brazilian production is priced against Brent with quality adjustments.

The quality of crude oil produced by ASX-listed companies also influences the premiums or discounts they receive relative to the benchmark. Lighter, sweeter crudes generally command higher prices due to their lower refining costs and higher yield of valuable products such as gasoline and diesel. Conversely, heavier, more sour crudes trade at a discount. Woodside's condensate production from the North West Shelf and Pluto LNG facilities is a light, premium product that typically commands prices at or above Brent. Beach Energy's Cooper Basin production includes a mix of crude oil and condensate with varying quality characteristics, while Karoon's Bauna field in Brazil produces medium-gravity crude that trades at a modest discount to Brent.

Currency effects add a further layer of complexity to the pricing equation for Australian oil companies. Because crude oil is denominated in US dollars, the Australian dollar exchange rate has a material impact on the AUD-equivalent revenues received by producers. A weaker Australian dollar amplifies the AUD value of USD-denominated oil revenues, providing a natural hedge for Australian producers during periods of global risk aversion when both oil prices and the Australian dollar tend to move in opposite directions. In the current environment, with the Australian dollar trading near AUD/USD 0.63, Australian oil producers are benefiting from the dual tailwind of elevated oil prices and a relatively weak domestic currency.

4. Current Oil Price Trends and Key Drivers

The oil market in 2026 has experienced one of its most dramatic price rallies in recent history, driven by a convergence of geopolitical, supply-side, and demand-side factors that have fundamentally altered the market's equilibrium. Understanding these drivers is critical for assessing the sustainability of current price levels and their implications for ASX-listed oil companies.

4.1 The Iran-US Conflict and Strait of Hormuz Disruption

The most significant factor underpinning the 2026 oil price surge has been the escalation of military tensions between the United States and Iran, which reached a critical inflection point in early 2026 when Iranian military forces effectively closed the Strait of Hormuz to commercial tanker traffic. The Strait of Hormuz is the world's most important oil chokepoint, connecting the Persian Gulf to the Gulf of Oman and the open ocean. Approximately 20 to 21 million barrels per day of crude oil and petroleum products transit the strait, representing roughly 20 percent of global oil supply. The disruption to this critical supply corridor has removed millions of barrels per day from the global market, creating a supply deficit of unprecedented scale in modern oil market history.

The impact on oil prices has been immediate and severe. WTI crude has surged from approximately USD 57 per barrel at the start of 2026 to USD 115.10 per barrel in early April, a gain of more than 100 percent in approximately three months. Brent crude has followed a similar trajectory, rising above USD 113 per barrel. The one-week price change alone has been USD 13.72 per barrel, representing a 13.54 percent increase, while the one-month change has been USD 20.33 per barrel, or 21.46 percent. The 52-week trading range has expanded dramatically, from a low of USD 54.98 to a high of USD 119.48 per barrel, reflecting the extreme volatility that characterises supply-disrupted oil markets.

4.2 OPEC+ Production Policy

The Organisation of the Petroleum Exporting Countries and its allies, collectively known as OPEC+, have been navigating a complex policy landscape throughout 2026. Prior to the Strait of Hormuz crisis, OPEC+ had been gradually unwinding the production cuts implemented in previous years, seeking to balance the desire for higher output volumes against the need to maintain supportive price levels. The cartel's spare production capacity, estimated at approximately 5 to 6 million barrels per day prior to the crisis, was concentrated primarily in Saudi Arabia and the United Arab Emirates. However, the Strait of Hormuz disruption has rendered much of this spare capacity inaccessible to global markets, as the bulk of OPEC's spare capacity is located in Persian Gulf states whose exports must transit the strait.

Saudi Arabia, as the de facto leader of OPEC, has found itself in an unprecedented position. While the kingdom possesses substantial spare production capacity, its ability to deliver additional barrels to global markets has been constrained by the strait closure. Alternative pipeline routes, including the East-West Pipeline (Petroline) to the Red Sea port of Yanbu, provide some capacity for bypassing the strait, but total bypass capacity is estimated at only 6 to 7 million barrels per day, far less than the pre-crisis strait transit volumes. This logistical constraint has effectively neutralised OPEC's traditional role as the swing producer capable of moderating price spikes through production increases.

4.3 US Shale Production Response

The US shale industry has been the primary supply-side response mechanism to the 2026 price shock, with producers in the Permian Basin, Eagle Ford, and Bakken formations ramping up drilling activity and completions in response to elevated prices. US crude oil production has climbed to approximately 13.5 million barrels per day, approaching its all-time high. However, the US shale response has been more measured than in previous price cycles, reflecting several structural constraints including depleted Tier 1 drilling inventory, capital discipline imposed by shareholders, supply chain bottlenecks in oilfield services, and regulatory uncertainty regarding federal leasing policy.

The lag between drilling activity and production growth means that the full impact of the US shale response is unlikely to be felt until the second half of 2026 or early 2027. In the interim, the market remains undersupplied, with global stockpiles drawing rapidly and commercial inventories in OECD countries falling well below their five-year average. This inventory deficit provides a floor for prices even as the market anticipates eventual supply normalisation, and it underscores the importance of US shale as a marginal supply source for the global oil market.

4.4 Macroeconomic and Currency Factors

Macroeconomic conditions have provided a mixed backdrop for oil demand in 2026. Global GDP growth is forecast at approximately 3.0 percent, slightly below historical trend but sufficient to support modest oil demand growth in the absence of a major recession. However, the oil price shock itself poses a meaningful risk to economic growth, as elevated energy costs act as a tax on consumers and businesses, eroding purchasing power and compressing profit margins in energy-intensive sectors. Central banks in major economies face a difficult policy dilemma, as the oil-driven surge in headline inflation occurs against a backdrop of slowing underlying economic activity.

The US dollar has strengthened modestly in 2026, reflecting safe-haven demand amid geopolitical uncertainty. A stronger dollar typically exerts downward pressure on oil prices by increasing the cost of oil imports for non-dollar economies, but this relationship has been overwhelmed by the magnitude of the supply disruption. For Australian oil companies, the combination of elevated USD-denominated oil prices and a weaker Australian dollar has created an exceptionally favourable revenue environment, as the AUD-equivalent value of each barrel produced has reached record levels.

5. Australia's Oil Industry Overview

Australia's oil and gas industry is a cornerstone of the national economy, contributing tens of billions of dollars in export revenues, supporting hundreds of thousands of direct and indirect jobs, and playing a critical role in the nation's energy security framework. While Australia is far better known as a major exporter of liquefied natural gas (LNG), coal, and iron ore, the petroleum sector encompasses a diverse range of activities spanning crude oil production, condensate extraction, gas processing, refining, and fuel distribution.

5.1 Production and Reserves

Australia holds approximately 0.3 percent of global proven oil reserves, a modest share that belies the country's significance as a petroleum producer and exporter. Domestic crude oil and condensate production currently stands at approximately 350,000 barrels per day, having declined substantially from its peak of more than 600,000 barrels per day in the early 2000s. This decline reflects the natural depletion of legacy fields, particularly in the Bass Strait and the Cooper Basin, which have been producing for several decades. However, the ramp-up of new projects, including condensate associated with LNG developments in Western Australia and the Northern Territory, has partially offset the decline in conventional crude oil output.

Western Australia is the dominant producing state, accounting for approximately 71 percent of Australia's crude oil and condensate production. The majority of this production is sourced from offshore fields on the North West Shelf, the Carnarvon Basin, and more recently, the Browse Basin. The Northern Territory also contributes meaningful volumes through the Bayu-Undan and Darwin LNG operations, while Victoria's Bass Strait fields, operated by the Gippsland Basin Joint Venture between ExxonMobil and the Woodside-operated BHP Petroleum assets, continue to produce declining but still significant volumes.

5.2 Key Producing Basins

Australia's oil production is concentrated across several major sedimentary basins, each with distinct geological characteristics, production histories, and remaining potential. The Carnarvon Basin, located offshore Western Australia, is the nation's most prolific petroleum province, hosting the giant North West Shelf, Pluto, Wheatstone, and Gorgon LNG projects, as well as numerous standalone oil and condensate fields. The basin's combination of world-class gas reserves, associated liquids production, and proximity to Asian LNG markets has made it the centrepiece of Australia's energy export industry.

The Cooper-Eromanga Basin, straddling the South Australia and Queensland border, is Australia's most extensively explored onshore petroleum province. Originally discovered in the 1960s, the basin has produced more than 300 million barrels of oil and significant quantities of natural gas. Beach Energy and Santos are the largest operators in the Cooper Basin, with extensive portfolios of producing wells, processing facilities, and pipeline infrastructure. While the basin is mature and production is declining from many individual fields, continued drilling activity and enhanced oil recovery techniques continue to add incremental volumes.

The Browse Basin, located offshore north-western Australia, represents one of the country's most significant remaining undeveloped petroleum resources. The basin hosts several world-class gas-condensate fields, including the Ichthys field operated by Inpex and the proposed Browse to North West Shelf development. The Perth Basin, located onshore and offshore Western Australia, has emerged as a focus of renewed exploration and development activity, with Strike Energy and Mineral Resources (through Norwest Energy) pursuing gas development opportunities. The Otway and Bass basins in southern Australia, the Gippsland Basin offshore Victoria, and the Bonaparte Basin offshore the Northern Territory round out the major producing regions.

5.3 Regulatory and Fiscal Framework

Australia's petroleum industry operates within a comprehensive regulatory framework that encompasses environmental approvals, production licensing, royalty and tax obligations, and safety requirements. The National Offshore Petroleum Titles Administrator (NOPTA) is responsible for the administration of petroleum titles in Commonwealth offshore areas, while the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) oversees environmental and safety regulation. State and territory governments retain jurisdiction over onshore and coastal petroleum activities.

The fiscal regime for Australian petroleum producers includes the Petroleum Resource Rent Tax (PRRT), which applies to offshore petroleum projects and operates as a profits-based tax, allowing the full recovery of project costs before tax liabilities commence. The PRRT rate is 40 percent on taxable profits, in addition to the standard corporate income tax rate of 30 percent. State-based royalties apply to onshore production, with rates varying by jurisdiction. The fiscal regime has been a source of ongoing policy debate, with successive governments seeking to balance the objectives of maximising public revenue from non-renewable resource extraction while maintaining a competitive investment environment that attracts exploration and development capital.

Environmental regulation has become increasingly stringent in recent years, reflecting community concerns about the impacts of petroleum production on marine ecosystems, air quality, and greenhouse gas emissions. The approval process for new projects has lengthened considerably, with Woodside's Scarborough and Santos's Barossa projects both experiencing significant delays due to environmental objections and legal challenges. These regulatory dynamics represent a material risk factor for investors in Australian oil and gas companies, particularly for projects in the pre-development phase where approval timelines remain uncertain.

6. Supply Analysis

Global oil supply dynamics in 2026 are dominated by the unprecedented disruption to Persian Gulf exports caused by the Strait of Hormuz crisis. Understanding the magnitude and potential duration of this disruption, together with the supply response from non-OPEC producers and the implications for Australian producers, is essential for assessing the sustainability of current oil price levels and their impact on ASX-listed energy companies.

6.1 OPEC+ Supply and Spare Capacity

OPEC+ entered 2026 with a combined production capacity of approximately 38 million barrels per day and actual production of approximately 33 million barrels per day, implying spare capacity of roughly 5 million barrels per day. This spare capacity was concentrated primarily in Saudi Arabia (approximately 3 million barrels per day), the United Arab Emirates (approximately 1 million barrels per day), and Iraq (approximately 0.5 million barrels per day). Under normal circumstances, this level of spare capacity would provide a substantial buffer against supply disruptions, allowing OPEC to ramp up production and moderate price spikes.

However, the Strait of Hormuz closure has fundamentally altered this calculus. Saudi Arabia, the UAE, Kuwait, and Iraq all rely on the strait for the bulk of their crude oil exports. While Saudi Arabia possesses the East-West Pipeline with a capacity of approximately 5 million barrels per day to its Red Sea port at Yanbu, and the UAE has the Abu Dhabi Crude Oil Pipeline (ADCOP) with a capacity of approximately 1.5 million barrels per day to Fujairah outside the strait, total bypass capacity is estimated at only 6 to 7 million barrels per day. This compares to pre-crisis strait transit volumes of approximately 20 to 21 million barrels per day, leaving a residual supply shortfall of approximately 13 to 14 million barrels per day that cannot be rerouted.

6.2 Non-OPEC Supply Response

Non-OPEC oil producers have been ramping up output in response to elevated prices, but the supply response has been constrained by structural limitations. The United States, as the world's largest oil producer at approximately 13.5 million barrels per day, has seen modest production increases in 2026, with shale producers adding rigs and accelerating completion timelines. However, the industry faces constraints including declining well productivity in mature areas of the Permian Basin, skilled labour shortages in the oilfield services sector, and continued capital discipline by public E&P companies responding to shareholder demands for returns over growth.

Other non-OPEC producers, including Brazil, Guyana, Canada, and Norway, have limited ability to rapidly increase production. Brazil's pre-salt deepwater fields operate on long development timelines, with new floating production, storage, and offloading (FPSO) vessels requiring several years from sanction to first oil. Guyana's Stabroek block, operated by ExxonMobil, is ramping up production with new FPSO vessels but is constrained by its planned development schedule. Canada's oil sands production is relatively stable but faces pipeline capacity constraints that limit incremental growth. Norway's production is mature and declining, with new Arctic developments insufficient to offset legacy field declines.

6.3 Australian Supply Dynamics

Australian oil and condensate production has been on a gradual declining trend but has stabilised in recent years thanks to new project start-ups and investment in existing field rejuvenation. Total domestic crude oil and condensate production is approximately 350,000 barrels per day, with the majority sourced from offshore Western Australia. Key producing assets include Woodside's Pluto and North West Shelf operations, Santos's Cooper Basin and GLNG portfolio, Beach Energy's diversified basin portfolio, and numerous smaller fields operated by independent producers.

The Australian supply outlook is influenced by several major development projects. Woodside's Scarborough gas project, currently under development, will produce significant volumes of condensate alongside natural gas when it reaches first production. Santos's Barossa gas-condensate project offshore the Northern Territory is progressing towards first gas in 2026, with associated condensate production expected to contribute meaningfully to Santos's overall liquids output. Beach Energy's Waitsia gas project in the Perth Basin reached first gas in late 2024 and is ramping up production, although its contribution to national oil supply is primarily through natural gas rather than liquids.

The pipeline of exploration activity in Australian basins has accelerated in response to elevated prices, with companies including Karoon Energy, Buru Energy, Bass Oil, and numerous small-cap explorers pursuing drilling programmes targeting both oil and gas prospects. The Carnarvon Basin, Browse Basin, and Bonaparte Basin remain the primary focus areas for offshore exploration, while the Perth Basin and Cooper Basin continue to attract onshore drilling investment. However, the lead time from exploration success to commercial production typically spans several years, meaning that new discoveries are unlikely to materially impact Australia's production profile before 2028 at the earliest.

6.4 Strategic Petroleum Reserves and Emergency Response

The oil price shock of 2026 has reignited the debate about the adequacy of strategic petroleum reserves (SPR) among major consuming nations. The United States holds the world's largest strategic reserve, with a capacity of approximately 714 million barrels, although the reserve has been drawn down significantly in recent years and currently holds approximately 370 million barrels. The International Energy Agency's collective reserve obligations require member nations, including Australia, to maintain reserves equivalent to 90 days of net oil imports, although compliance and accounting methodologies vary.

Australia's strategic petroleum reserve position has been a recurring policy concern, as the nation relies heavily on imported refined fuels and holds limited physical stockpiles within its borders. The government has entered into agreements with the United States to hold ticketed reserves in US storage facilities, supplementing domestic commercial stocks. However, the accessibility and logistical viability of these offshore reserves during a major supply disruption remains questionable. The current crisis has intensified calls for greater investment in domestic fuel storage capacity and refining infrastructure, potentially benefiting downstream companies such as Viva Energy and Ampol.

6.5 Global Refining Capacity and Crack Spreads

The global refining sector has experienced significant structural change in recent years, with closures of older, less efficient refineries in developed markets partially offset by new capacity additions in the Middle East and Asia. The net effect has been a tightening of refining capacity relative to demand, which has supported crack spreads, the difference between refined product prices and crude oil input costs. In 2026, the Strait of Hormuz disruption has further tightened the refining market, as several major refineries in the Persian Gulf region have experienced feedstock shortages, reducing global refined product output.

For Australian downstream companies, the refining margin environment is exceptionally favourable. Viva Energy's Geelong refinery and Ampol's Lytton refinery are both benefiting from elevated crack spreads on gasoline, diesel, and jet fuel, translating into record or near-record refining earnings. The Australian government's fuel security programme, which provides financial support for domestic refining operations, adds an additional layer of earnings stability. However, investors should note that refining margins are inherently cyclical and will normalise as the global supply disruption eases, returning to more typical levels once Persian Gulf refining capacity is fully accessible to the market.

7. Demand Analysis

Global oil demand is a critical variable in assessing the investment outlook for ASX-listed oil companies. Demand dynamics are influenced by economic growth, demographic trends, transportation patterns, industrial activity, and the accelerating energy transition. In 2026, the interplay between these structural and cyclical factors is creating a complex demand environment that requires careful analysis by institutional investors.

7.1 Global Demand Overview

Global oil demand in 2026 is estimated at approximately 103 to 104 million barrels per day, representing a modest increase from 2025 levels. The International Energy Agency (IEA) had projected demand growth of approximately 1.0 to 1.2 million barrels per day for 2026, driven primarily by emerging market consumption growth, but the oil price shock has introduced significant downside risk to these forecasts. Higher oil prices act as a demand destroyer, reducing consumption in price-sensitive segments such as discretionary driving, non-essential air travel, and industrial fuel switching. The elasticity of oil demand with respect to price is estimated at approximately negative 0.05 to negative 0.10 in the short term, implying that a doubling of oil prices would reduce demand by approximately 5 to 10 percent over a 12-month period.

7.2 China and Asia-Pacific Demand

China remains the most important single driver of global oil demand growth, accounting for approximately 15 percent of global oil consumption and having been responsible for the majority of incremental demand growth over the past two decades. In 2026, Chinese oil demand is influenced by several competing factors. On the positive side, the government's stimulus measures aimed at supporting economic growth, the continued expansion of the petrochemical sector, and the recovery of international air travel are supporting consumption. On the negative side, the rapid adoption of electric vehicles in China, with EV sales now accounting for more than 40 percent of new car sales, is beginning to erode gasoline demand growth, while the property sector downturn is constraining diesel demand from construction activity.

India has emerged as the second major pole of oil demand growth in Asia, with consumption driven by robust economic growth, a young and expanding population, rapid urbanisation, and increasing vehicle ownership. India's oil demand is estimated at approximately 5.5 million barrels per day and is growing at approximately 3 to 4 percent annually, making it one of the fastest-growing major oil consuming nations. Unlike China, India's EV adoption rate remains relatively low, and the country's demographic profile suggests sustained oil demand growth well into the 2030s. For Australian oil and LNG producers, India represents an increasingly important strategic market, with both Woodside and Santos pursuing opportunities to supply Indian energy demand.

7.3 Transportation Sector Demand

The transportation sector continues to account for the majority of global oil demand, with road transport, aviation, and maritime shipping collectively consuming approximately 57 million barrels per day. Road transport demand is showing the first signs of structural slowdown in developed markets, as electric vehicle penetration reaches critical mass in Europe and China and begins to erode gasoline consumption. However, the global passenger vehicle fleet of approximately 1.4 billion vehicles is dominated by internal combustion engine vehicles, and the natural rate of fleet turnover means that oil demand from road transport will decline gradually rather than precipitously.

Aviation fuel demand has recovered strongly from the pandemic-era collapse and now exceeds 2019 levels, driven by the continued expansion of international air travel, particularly within and from Asia-Pacific. Maritime shipping demand for fuel oil and marine gasoil has been supported by robust global trade volumes, although the adoption of LNG as a marine fuel is beginning to displace some oil-based bunker fuel demand. For Australian oil producers, the aviation and maritime sectors represent resilient demand segments that are less susceptible to electrification than road transport.

7.4 Petrochemical Demand and Non-Combustion Uses

Petrochemical demand is increasingly recognised as the key long-term growth driver for oil consumption, as the production of plastics, synthetic fibres, fertilisers, and other chemical products requires oil-derived feedstocks that cannot readily be substituted with alternative materials. The IEA has identified petrochemicals as the single largest source of projected oil demand growth through 2040, with consumption expected to increase by approximately 4 to 5 million barrels per day over the period. This structural demand growth provides a floor for oil consumption even as transportation sector demand declines, and it has important implications for the long-term valuation of oil equities.

For ASX-listed companies, the petrochemical demand outlook is relevant both directly and indirectly. Woodside's LNG production feeds into Asian petrochemical complexes that use natural gas as both a feedstock and an energy source. Santos's GLNG project supplies the domestic east coast gas market, which includes petrochemical operations. Viva Energy operates the Geelong refinery, which produces petrochemical feedstocks alongside refined fuels. The growing importance of non-combustion oil demand reinforces the view that oil remains an essential input to the modern economy, even as the energy transition progresses.

7.5 Energy Security and Strategic Stockpiling Demand

The geopolitical disruptions of 2026 have triggered a significant increase in strategic stockpiling demand by major oil-importing nations. China, Japan, South Korea, India, and several European nations have accelerated their strategic petroleum reserve (SPR) refilling programmes, seeking to bolster energy security in an environment of unprecedented supply uncertainty. This stockpiling demand adds incremental barrels to global consumption figures and provides additional price support beyond normal commercial demand.

China's strategic petroleum reserves have been a particular focus of market attention, as the nation has reportedly increased its reserve holdings from approximately 500 million barrels to over 600 million barrels since the onset of the Strait of Hormuz crisis. India has similarly been expanding its strategic storage capacity, with new underground cavern facilities under construction to complement existing commercial storage. The aggregate impact of strategic stockpiling on global oil demand is estimated at approximately 500,000 to 1,000,000 barrels per day above normal commercial demand, representing a meaningful contribution to the overall supply-demand balance.

7.6 Seasonal Demand Patterns and the Summer Driving Season

Oil demand follows well-established seasonal patterns that influence price dynamics throughout the year. The Northern Hemisphere summer driving season, typically spanning June through September, represents the peak demand period for gasoline, as increased recreational travel and holiday activity boost consumption. The approaching summer driving season in 2026 is expected to add further upward pressure to already elevated gasoline prices, potentially pushing retail fuel prices in the United States, Europe, and Australia to record levels.

In the Southern Hemisphere, seasonal demand patterns differ, with Australian fuel consumption typically peaking during the summer months of December through February and during the Easter and school holiday periods. However, Australia's contribution to global demand is relatively small, and the domestic price impact is driven primarily by international benchmark movements and the AUD/USD exchange rate rather than local seasonal factors. For ASX-listed downstream companies such as Viva Energy and Ampol, seasonal volume fluctuations have a modest impact on annual earnings, as the companies manage their inventory and refining schedules to smooth seasonal variations in demand.