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Market overview

In 2022, the energy price shock and rising food prices led to a cost-of-living crisis and lower economic growth, pushing up inflation to levels not seen for many decades.

Prices were already creeping up as a result of the economic rebound from the pandemic, its lockdowns and related supply chain constraints. But inflation soared globally after Russia’s invasion of Ukraine, which triggered the war that continues today.

Shell maintains a large business portfolio across an integrated value chain and is exposed to fluctuating prices of crude oil, natural gas, oil products, chemicals and power (see “Risk factors”). This diversified portfolio provides resilience when prices are volatile. Our annual planning cycle and periodic portfolio reviews aim to ensure that our levels of capital investment and operating expenses are appropriate in the context of a volatile price environment.

We test the resilience of our projects and other opportunities against a range of prices for crude oil, natural gas, oil products, chemicals and power. We also aim to maintain a strong balance sheet to provide resilience against weak market prices.

Global economic growth

Higher energy and food prices have caused real wages to fall in many countries, slashing purchasing power. This is hurting consumers. In addition, central banks around the world are increasing interest rates to curb inflation and anchor inflation expectations in their economies. Tighter monetary policy and higher interest rates, weak real household income growth and declining confidence have resulted in lower economic growth during 2022.

For 2023, a further growth slowdown for the world economy is projected, as well as high, but declining, inflation in many countries. In the International Monetary Fund’s latest global economic prospects report published in January 2023, global growth is forecast to decelerate from 6.2% in 2021 and 3.4% in 2022 to 2.9% in 2023. Asia is expected to be the main engine of growth in 2023 and 2024, whereas Europe, North America and South America are expected to see very low growth.

Risks to the economic outlook remain significant, including new uncertainties about natural gas supplies to Europe, the impact of the real estate and COVID-19 crises in China, and a resurgence of COVID-19 health scares around the world. Central banks must chart a difficult path as they face mixed economic signals, such as slowing economic growth with still tight labour markets and strong pressure for wage growth. In this environment, an insufficient increase in interest rates may prove a mistake. If rates are not adequately raised, inflation could become entrenched, prompting higher interest rates in the future at a significant cost to the economy. On the other hand, increasing interest rates by too much may risk sending many economies into debt distress and prolonged recession.

Global prices, demand and supply

The following table provides an overview of the main crude oil and natural gas price markers to which we are exposed:

Oil and gas average industry prices [A]





Brent ($/b)




West Texas Intermediate ($/b)




Henry Hub ($/MMBtu)




EU TTF ($/MMBtu)




Japan Customs-cleared Crude ($/b) – 3 months





Yearly average prices are based on monthly average spot prices. The 2022 average price for Japan Customs-cleared Crude is based on available market information up to the end of the period.

Crude oil and oil products

The global benchmark oil price Brent averaged $101 per barrel (/b) in 2022, the highest annual average price since 2013. This represents an increase of more than 40% increase from the annual average of $71/b recorded in 2021. High prices were mostly realised in the first half of the year, with demand recovering as economies reopened and supply constrained by the capacity of major oil producers. Russia’s invasion of Ukraine triggered concerns about supply availability, sending Brent to a high of $133/b on March 8, 2022. Prices stayed at an elevated level until the middle of the year, before falling as recession concerns weighed on the market. Brent averaged $80/b in December, the same price as it was in the fourth quarter of 2021. West Texas Intermediate (WTI) traded at a sharper discount of around $6/b to Brent in 2022, compared with a discount of about $3/b in 2021. This is because of rising demand for Brent as a replacement for Urals, the most common grade of Russian crude exports.

In 2022, global oil product demand rose by more than 2 mb/d to nearly 100 mb/d, approaching the pre-COVID-19 level of 100.5 mb/d in 2019. Growth largely came from jet fuel, supported by the rebound in air travel after the pandemic. Growth in other product segments continued in 2022, albeit at a slower pace. Global diesel/gas oil growth eased from 1.5 mb/d in 2021 to 0.66 mb/d in 2022 based on IEA estimates, reflecting weakening economic activities. Naphtha, after a strong year of growth in 2021, declined by 0.13 mb/d due to a weak petrochemical sector. Regionally, growth has largely come from non-OECD markets, particularly the Middle East and India. Chinese demand dropped by about 0.4 mb/d as lockdowns in the country affected demand. Among OECD markets, European growth was particularly weak. While high gas prices resulted in a switch from gas to oil, this was largely offset by a weak petrochemical sector which struggled with high energy costs.

Global oil production increased to 100 million b/d in 2022, up by 4.7 mb/d from 2021. Growth was largely led by the ramp-up of Saudi Arabian and US shale oil. Saudi Arabia delivered an additional 1.4 mb/d compared with 2021, about half of the OPEC supply growth. Outside OPEC, the USA added 1.2 mb/d, providing about 60% of the non-OPEC growth. During the third quarter, there were concerns about whether OPEC would raise production in step with demand recovery because a number of member countries were producing below quota. But the trend started shifting from the fourth quarter, with OPEC in November reintroducing production cuts of 2 mb/d, in view of the potential surplus should economic conditions worsen.

Russia’s invasion of Ukraine has strong ramifications for global crude and oil product supply. Before the invasion, Russian production was expected to surge by more than 0.8 mb/d in 2022, according to the IEA. But actual production growth was about 0.2 mb/d due to OECD market sanctioning. Global crude/product trade flow also shifted as Russian crude/products were redirected to non-OECD markets.

The outlook for 2023 demand is highly uncertain. One key uncertainty is the recession risk in OECD economies, particularly Europe. China’s lifting of COVID-19 restrictions to focus on economic growth could provide some support to global oil demand. The main uncertainty on the supply side is the supply from Russia after the embargo on Russian crude and oil products took effect. The EU embargo and G7 price caps on Russian crude oil took effect in early December 2022. Russian oil product embargoes and price caps followed in February 2023. These measures could lead to a further reduction in Russia’s oil supply.

Natural gas

Global demand for natural gas in 2022 is estimated to have declined by 1.6% compared with 2021. This was a result of high, volatile prices and shorter supply, particularly in Europe and emerging Asian countries, which led to reduced industrial, commercial and residential consumption. The year-on-year downturn came after gas demand rebounded in 2021 from the historically low levels during the pandemic. Europe’s gas market experienced an unprecedented supply shock from the sharp reduction in Russian pipeline gas imports. Already elevated spot gas prices in Europe rose further under the threat of Russian supply curtailments and the uncertainty about the LNG market’s ability to make up the difference. This triggered demand curtailment in Europe’s industrial sector. It also caused a slowdown in LNG import purchases in China amid economic weakness and COVID-19 lockdowns. Emerging economies, such as Pakistan and Bangladesh, struggled with the affordability of spot LNG.

European gas prices were turbulent in 2022 as almost all pipeline flows from Russia came to a halt. Exports through Gazprom’s pipelines fell from a 2022 peak of just over 300 million cubic metres per day (mcm/d) to about 65 mcm/d in November. On an annual basis, Europe’s imports of Russian pipeline gas almost halved. The European benchmark price Title Transfer Facility (TTF) was volatile, breaching $96/MMBtu at its peak. There were also large disconnections in regional European gas hub prices caused by the reconfiguration of supply flows and regasification capacity reaching maximum utilisation rates. This particularly affected the UK’s National Balancing Point (NBP) and TTF prices, as well as the price of delivered LNG.

The pricing environment was a catalyst for major demand destruction. The residential and commercial consumer sector shed more than 15% of demand year-on-year, assisted by mild temperatures. The industrial sector is estimated to have lost more demand year-on-year than any period for over a decade. But TTF prices experienced a sharp decline at the end of the third quarter after Russian gas pipeline cuts materialised and gas inventories were built beyond government-mandated levels ahead of time. Europe remained the highest-priced global gas market for 2022 and attracted substantial volumes away from other markets, especially in Asia. Higher LNG exports into Europe, coupled with demand curtailment, made up for the lack of Russian pipeline imports, allowing for a comfortable storage situation by the start of the northern hemisphere winter. European LNG imports increased by about 45 million tonnes with north-west Europe accounting for more than 30 million tonnes of this growth. A migration of floating storage and regasification units (FSRUs) to Europe reduced bottlenecks and increased import capacity, specifically to north-west Europe. The commissioning of the Eemshaven FSRU in the Netherlands in September 2022, and the commissioning of several FSRUs for Germany have set Europe up to be a major LNG importer for years to come.

Asian spot LNG prices, as reflected by the Japan Korea Marker (JKM), traded at a significant discount to European prices for most of 2022, driven largely by lower LNG imports into China. By the end of the year, China had imported about 15 million tonnes less LNG year-on-year, ceding the title of the world’s biggest LNG importer back to Japan. South Korea and Japan continued to import LNG despite the high spot prices because of JKM buyers’ high concentration of long-term LNG contract volume. Crude-oil-linked contracts were cheaper than JKM prices by an average of 50% in 2022. This was evidenced by the Japan Landed Cost (JLC), which accounts for imported LNG long-term contract and spot prices averaging about $17/MMBtu versus an average of around $33/MMBtu for the spot price of JKM.

Henry Hub gas benchmark prices in North America were volatile throughout the year, ranging from below $4/MMbtu to nearly $10/MMbtu. Henry Hub cash prices averaged $6.39/MMBtu in 2022, reaching a peak of $9.84/MMBtu in August. The rise in the first half of the year was caused by a structurally tighter market and spill-over effects from the higher prices for LNG exports. The decline towards the end of the year was a result of strong production and comfortable storage expectations for the northern hemisphere winter. US LNG export plants consumed an average of 11.81 bcf (billion cubic feet) per day throughout the year, accounting for 12% of US overall production of around 97 bcf per day. This is a 547% increase from five years ago and a 203% increase from the previous five-year average. Strong power demand for gas in the USA and lagging upstream production supported the rise.


Europe: European power prices were turbulent in 2022. In Germany, for example, the average power price in 2022 was $247/MWh, an unprecedented seven times higher than the average price of $37/MWh in the period from 2015 to 2019. Prices increased in the first quarter of the year, peaking in August with spot prices of up to $916/MWh. European power prices are strongly influenced by the power plants dependent on natural gas. Widespread unplanned outages of French nuclear power plants and low hydropower availability also pushed up power prices. The high European power prices have triggered a range of regulatory actions, including revenue caps for inframarginal power generators (generators which do not set marginal prices); national demand reduction goals; and a consultation for market reforms by the European Commission.

United States: US power prices were much higher across all major markets in 2022 compared with 2021. One of the key drivers of higher power prices and volatility in 2022 was gas prices. Henry Hub gas benchmark prices in North America were volatile throughout the year, ranging from below $4/MMbtu to nearly $10/MMbtu. Prices in the second half of the year traded back down to below $4.00/MMBtu as natural gas production steadily increased and the ability to increase storage injections prior to winter picked up. Power prices were also driven higher by weather events throughout the year and across the country. For the eastern part of the USA, cold weather in January led ISO-NE (New England) prices to average around $150/MWh, and a late December cold front led to significantly higher prices in PJM and MISO (Midcontinent) markets. For the ERCOT (Texas) market, a hot July in Texas led to record level demand and North Hub settled at $147/MWh. A heatwave in the western part of the USA in September sent Mid-C (Midcontinent) ISO and CAISO (California) prices to highs of $152/MWh and $118/MWh respectively, and a cold December resulted in even higher prices in Mid-C ($263/MWh) and CAISO ($254/MWh).

Australia: In 2022, the (East) Australia power market was volatile with spot prices averaging $191/MWh and $151/MWh in the second and third quarter respectively. This was because of unseasonal weather, unplanned outages of coal-fired power plants, and gas and hydropower supply constraints. High international coal and spot LNG prices pushed up domestic gas and coal prices. The gas market spiked to the $21 – 28 per gigajoule (GJ) range in the second and third quarters after having started the year at $7/GJ (well below international LNG prices). The spike was caused by a significant demand for uncontracted and unforecasted gas with little or no notice. This demand came primarily from the aforementioned power market disruptions, but also arose from the early onset of the Australian winter and a heavy reliance on spot markets by some industrial and power generation end-users. Prices became more moderate as Australia moved out of winter, but remained volatile as the government implemented gas and coal price caps and controls at the wholesale level for 2023 and beyond.

Crude oil and natural gas price assumptions

Our ability to deliver competitive returns and pursue commercial opportunities depends on the accuracy of our price assumptions (see “Risk factors”). We use a rigorous assessment of short-, medium- and long-term market uncertainties to determine what ranges of future crude oil and natural gas prices to use in project and portfolio evaluations. Market uncertainties include, for example, future economic conditions, geopolitics, actions by major resource holders, production costs, technological progress and the balance of supply and demand. See also Note 12 to the “Consolidated Financial Statements”.

Refining margins

Global indicative refining margin [A]









Indicative refining margin





The indicative margin is an approximation of Shell’s global gross refining unit margin, calculated using price markers from third parties’ databases. It is based on a simplified crude and product yield profile at a nominal level of refining performance. The actual margins realised by Shell may vary due to factors including specific local market effects, refinery maintenance, crude diet optimisation as the crudes in the IRM are indicative benchmark crudes, operating decisions and product demand. Gross refining unit margin is defined as the hydrocarbon margin net of purchased/sold utilities, additives and relevant freight costs, divided by crude and feedstock intake in barrels. It is only applicable to the impact of market pricing on refining business performance, excluding trading margin. Prior period comparatives are calculated on the same basis as the current year.

In 2022, gross refining margins improved in comparison with 2021, especially during the first half of the year. Economic recovery and disruption caused by the Russian war in Ukraine led to very strong refining margins, especially during the second quarter. With demand falling in sync with the economic slowdown, refining margins fell towards the end of the year. Weak chemical feedstocks and gasoline demand was partially offset by strong middle distillate demand. Middle distillate demand is supported by continued aviation demand recovery and disruptions to Russian product flows to Europe.

Construction of new capacity continued during the year, especially in the Middle East, Africa and Asia. However, several projects were delayed due to supply chain issues and inflationary cost pressures.

For 2023 and beyond, refining margins are expected to decline as refinery capacity increases and demand growth slows. This would result from weaker economic growth, high energy prices and the tightening of monetary policy by central banks.

Petrochemical margins

Global indicative chemical margins [A]









Indicative chemical margin





The Indicative Chemical Margin (ICM) is an approximation of Shell’s global chemical margin performance trend (including equity-accounted associates), calculated using price markers from third parties’ databases. It is based on a simplified feedstock and product yield profile at a nominal level of plant performance. The actual margins realised by Shell may vary due to factors including specific local market effects, chemicals plants maintenance, optimisation, operating decisions and product demand. Chemical unit margin is defined as the hydrocarbon margin net of purchased/sold utilities, additives and relevant freight costs, divided by a nominal denominator expressed in metric tons. It is only applicable to the impact of market pricing on Chemical business performance. Prior period comparatives are calculated on the same basis as the current year.

Chemical cracker margins came under pressure in 2022. The Russian war in Ukraine caused volatile energy prices, especially in Europe and Asia, leading to lower cracker margins. This has also impacted derivative trade and demand. Macroeconomic factors, including inflation and lower economic growth, further contributed to weaker global demand and lockdown restrictions in China resulted in further demand destruction in Asia. New capacity growth primarily in Asia and the USA led to global oversupply and lower margins. Producers continue to match demand through lower cracker utilisation.

The outlook for petrochemical margins in 2023 and beyond depends on feedstock costs and the balance of supply and demand. Demand for petrochemicals is expected to be affected by energy costs, macroeconomic factors, and any further COVID-19 impacts. A recovery in demand is needed to absorb the excess capacity. The supply of petrochemicals will depend on the net capacity effect of new facilities and plant closures with utilisation balancing the system. Product prices will reflect the prices of raw materials which are closely linked to crude oil and natural gas prices.

The statements in this “Market overview” section, including those related to our price forecasts, are forward-looking statements based on management’s current expectations and certain material assumptions and, accordingly, involve risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied herein.

See “About this Report” and “Risk factors”.

International Energy Agency
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liquefied natural gas
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million British thermal units
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megawatt hours
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Organisation for Economic Co-operation and Development
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Organization of the Petroleum Exporting Countries
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West Texas Intermediate
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barrels (per day)
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million barrels per day
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per day
volumes are converted into a daily basis using a calendar year
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