This year’s Energy Outlook is focused on two main scenarios: Current Trajectory and Below 2°. The scenarios are not predictions of what is likely to happen or what bp would like to happen. Rather they explore the possible implications of different judgements and assumptions concerning the nature of the energy transition. The scenarios are based on existing technologies and do not consider the possible impact of new or unknown technologies or applications.
The many uncertainties surrounding the possible speed and nature of the energy transition, as well as the many other factors shaping the energy system, mean the probability of either one of the scenarios materialising exactly as described is negligible.
Moreover, the two scenarios do not provide a comprehensive description of all possible outcomes. They do, however, span a wide range of possible outcomes and so might help to illustrate the key trends and uncertainties surrounding the possible development of energy markets out to 2050.
The Outlook is produced to inform bp’s views of the risks and opportunities posed by the energy transition and is published to help share those views with bp’s stakeholders and as a contribution to the wider debate about the factors shaping the future path of the global energy system.
But the Outlook is only one source among many when considering the prospects for global energy markets, and bp considers a wide range of other external scenarios, analysis and information when forming its long-term strategy.
The analysis of the difference in carbon emissions between Current Trajectory (CT) and Below 2° (B2) scenarios focuses on both direct and indirect emissions from the power sector and each end-use sector (industry, transport, buildings).
To separate the impact of the decarbonization of the power sector from changes in electricity use in the end-use sectors, the following approach is taken: The difference in direct emissions in the power sector between CT and B2 can be decomposed into two contributions: the change in total electricity demand, and the change in power emissions intensity. Electricity demand is higher in B2 than in CT as the world electrifies more in B2. The carbon intensity of power is lower in B2 than in CT as more low carbon power sources contribute a greater share of generation. When accounting for the difference in emissions between CT and B2 in the power sector, only contributions due to lower carbon intensity are considered. The contribution due to increased electricity demand is instead allocated to the end-use sector as a function of the change in electricity demand in each sector.
Emissions from the production of traded heat (via combined heat and power (CHP) or heat plants) are included within the power sector.
Turning to end-use sectors, the impact of decarbonizing the power sector is again separated from the impact of increasing electricity demand. This is done by initially calculating the changes in carbon emissions associated with drivers such as energy efficiency improvements and electrification while holding the carbon intensity of power at the CT level. At the end of the analysis, the final step is to calculate the reduction in emissions from moving the carbon intensity of power to the B2 level. The methodology used in each end-use sector is as follows:
The industrial sector decomposition includes the contributions from methane emissions from fossil fuel production and from the hydrogen sector. CCUS includes the capture of process emissions from cement production. The contributions from energy efficiency gains include the effects of process efficiency improvements, increased recycling of industrial products and materials, and measures to reduce the demand for industrial products and materials.
The decomposition for the transport sector includes contributions from transport activity and energy efficiency. These reflect changes in how each mode of transport is used, such as the average distance travelled by light-duty vehicles and improvements in overall energy efficiency. The remaining contributions directly reflect the impact of the shift away from fossil fuels towards low carbon alternatives.
The contribution of energy conservation includes the effects of improvements in building fabric through retrofitting, the increase in the number of zero-carbon buildings, and energy demand reductions due to behavioural changes. Also included are all other decarbonization measures that involve the switch to electricity, as well as access to fuels that reduce the use of traditional biomass and its associated methane emissions.
This analysis explores whether a region or country is in a phase of energy addition, in which both fossil fuels and low carbon energy use are rising, or energy substitution, when a region is shifting from fossil fuel consumption to low carbon energy consumption.
When overall energy demand is rising, as has been the case for many emerging economies and some developed economies, energy addition is defined to be occurring when both unabated and combusted fossil fuel consumption and low carbon energy use are rising.
If, in contrast, overall energy demand is rising but unabated fossil fuel is falling, that region is said to be in energy substitution.
In cases where overall energy demand is falling rather than rising, as has been the case for many developed economies, energy substitution is defined to be occurring when fossil fuel consumption is falling more rapidly than low carbon energy consumption, if that is also falling.
To avoid the short-term volatility inherent in annual energy data in the chart “Primary energy of countries in ‘energy substitution in Current Trajectory”, the Hodrick–Prescott (HP) filter is applied to both primary energy and unabated fossil fuel consumption. This filtering process helps isolate long-term structural trends, providing a clearer view of underlying energy transitions.
Regarding power sector addition or substitution, the same concepts of energy addition and substitution are applied exclusively to the power sector. That is, power sector substitution is defined to be occurring when unabated fossil fuel use in the power sector is falling, or is falling more rapidly than low carbon energy use in the power sector. In this case, a centred five-year average is used to smooth short-term volatility in the annual electricity generation series.
The Increased geopolitical fragmentation sensitivity takes the Current Trajectory scenario as a starting point and then layers on four shocks to illustrate the possible impacts of increased geopolitical fragmentation on the evolution of the global energy system.
The first shock is a reduction in the pace of GDP growth out to 2035 to reflect the impact of weaker global trade. The sensitivity assumes a gradual reduction in global trade openness, resulting in a reduction in the level of global economic activity of 4% by 2035 relative to Current Trajectory. The economic effects of the global trade shock differ by region, with regions affected with different magnitudes, depending on their level of trade dependency and economic development.
The second shock is an increased preference for domestically produced energy. This is modelled as a cost premium added to imports of energy. The premium is calibrated for each region depending on their relative degree of import dependency for different fuels. The applied premia lead to an increase in global weighted average fossil fuel prices of 10-15%.
The third shock is an increased preference for domestic supply chains for renewable technologies, which is modelled through increases in the levelized cost of electricity. As with the calibration used for the second shock, the applied premia vary by region and technology. The modelling approach results in an increase in the weighted average global capital costs for solar and wind of 12-18%. The calibration aims to capture existing comparative advantages in renewable technology supply chains.
The second and third shocks taken together increase the overall cost of energy for each region modelled. This, in turn, affects overall energy demand, resulting in an improvement in energy efficiency, especially for energy importing regions.
The fourth and final shock is an increased focus on energy security relative to other elements of the ‘energy trilemma’, slowing the adoption of higher-cost low carbon technologies. These technologies are delayed as countries reduce the relative weight placed on energy sustainability, and also face lower economic activity and therefore more stringent budget constraints. The shock is calibrated as a five-year delay in the deployment of SAF, low carbon hydrogen and CCUS relative to their deployment in Current Trajectory.
The first shock (lower GDP) can be interpreted as a direct consequence of lower global trade. The other three shocks aim to capture the different channels through which a heightened focus on energy security may manifest in the global energy system.
This is a stylized sensitivity in which the recent weakness in energy efficiency is assumed to be more persistent than in Current Trajectory. In particular, global energy efficiency growth between 2024 and 2035 is reduced by an average of 0.4 percentage points per year relative to the path of energy efficiency gains in Current Trajectory. That reduction is in line with the weakness in energy efficiency gains over the past five years, relative to those in the previous decade. The adjustment in this sensitivity results in energy efficiency improving by 1.4% per year between 2023 and 2035, rather than 1.8% as in Current Trajectory. Energy efficiency is defined here as total final consumption of energy divided by GDP.
In this sensitivity, bioenergy, solar, wind, nuclear, and hydropower are assumed to remain identical to those in Current Trajectory. Weak energy efficiency therefore results only in higher use of fossil fuels: oil, natural gas and coal.
The increase in total final energy consumption resulting from slower improvements in energy efficiency is allocated proportionally to each fuel and energy carrier based on their shares of TFC in Current Trajectory. After this initial allocation, the final increase in primary energy is estimated using the thermal efficiencies for power and heat generation as defined in Current Trajectory.
The assumption that weaker energy efficiency impacts only fossil fuel use is driven by the past observed correlations between different elements of primary energy and overall primary energy demand. As shown below, those past correlations are very high for fossil fuel use, but are much lower for bioenergy, solar, wind, nuclear, and hydropower, suggesting that short- to medium-term fluctuations in overall energy demand have in the past largely been reflected in fluctuations in fossil fuel use, rather than in low carbon energy vectors.
Primary energy by energy type |
Correlation* with overall primary energy |
Oil |
0.8 |
Natural gas |
0.8 |
Coal |
0.8 |
Bioenergy |
0.5 |
Solar and wind |
0.1 |
Nuclear |
0.3 |
Hydropower |
0.0 |
| *Correlation shown is first differences, 1990-2023 (annual) | |
The Delayed Below 2° sensitivity combines elements of both Current Trajectory and Below 2°.
In a first step, the adjusted emissions pathways for Current Trajectory and Below 2° are calculated. This involves removing methane emissions from energy sources and traditional biomass, and adding CO2 median emissions from agriculture, forestry and other land use (AFOLU) from the IPCC C3 and C5 scenarios (for Below 2° and Current Trajectory respectively).
In Delayed Below 2°, emissions accrue as in Current Trajectory until 2030. After 2030, the energy system transitions at broadly the same speed as in the Below 2° pathway, and CO2 emissions are calculated based on primary consumption levels for different fuels. The level of cumulative emissions of this scenario is around 900GtCO2.
This is close to the carbon budget taken from the IPCC Summary for Policymakers report (IPCC, 2021), which estimates that cumulative emissions of 900GtCO2 are consistent with limiting the global temperature increase below 2°C with a likelihood of 83%.
Emissions after 2050 are calculated on the assumption that the energy system evolves in a similar path as in 2045-50 in each scenario until they reach zero carbon emissions.
The GDP profiles used in the Energy Outlook come from Oxford Economics. These long-term forecasts incorporate estimates of the economic impact of climate change. These estimates follow a similar methodology to that used in Energy Outlooks since 2020.
The future effects of climate change on global economic activity are highly uncertain, given the unprecedented nature of the phenomenon and its interaction with a modern economic system, and the many uncertainties around the mitigation and adaptation actions that may be taken in response and the technologies that will be available for those in the future. However, there have been attempts to model its possible effects. In particular, Oxford Economics updated and extended the estimation approach developed by Burke, Hsiang and Miguel (2015), which suggests a non-linear relationship between productivity and temperature, in which per capita income growth rises until an average (population weighted) temperature of just under 15°C is reached (Burke et al.’s initial assessment was 13°C). While given the uncertainties, any such conclusions need to be treated with caution, this temperature curve suggests that the income growth of a ‘cold country’ increases with annual temperatures. However, at annual temperatures above 15°C, per capita income growth is increasingly adversely affected by higher temperatures.
The Oxford Economics baseline emissions forecasts assume average global temperatures reach 1.9°C above pre-industrial levels by 2050. The results suggest that in 2050 global GDP is around 2% lower than in a counterfactual scenario where temperatures remained at their current level. The regional economic impacts are distributed according to the evolution of regional temperatures relative to the concave function estimated by Oxford Economics. While Oxford Economics’ approach captures channels associated with average temperatures, these estimates remain uncertain and incomplete; they do not, for example, explicitly include impacts from migration or extensive coastal flooding.
The mitigation costs of actions to decarbonize the energy system are also uncertain, with significant variations across different external estimates. Most estimates, however, suggest that the upfront costs increase with the stringency of the mitigation effort, suggesting that they are likely to be bigger in Below 2° than in Current Trajectory. The IPCC (2022) estimates that mitigation costs to limit global warming to 2°C (with probability >67%) entail losses in global GDP with respect to reference scenarios of between 1.3% and 2.7% in 2050. In pathways limiting warming to 1.5°C (with probability >50%) with no or limited overshoot, costs are between 2.6% and 4.2% of global GDP. These estimates do not account for the economic benefits of avoided climate change impacts.
Given the huge range of uncertainty surrounding estimates of the economic impact of both climate change and mitigation, and the fact that the Energy Outlook scenarios include both types of costs to a greater or lesser extent, the GDP profiles used in the Outlook are based on the illustrative assumption that these effects reduce GDP in 2050 by around 2% in both scenarios, relative to the counterfactual in which temperatures are held constant at recent average levels.
Unless otherwise stated, carbon emissions refer to
CO2 emissions from industrial processes refer only to non-energy emissions from cement production. CO2 emissions associated with the production of hydrogen feedstock for ammonia and methanol are included under hydrogen sector emissions. Historical data on flaring is sourced from the Statistical Review of World Energy by the Energy Institute. Estimates of methane emissions from the production, transportation, and distribution of fossil fuels – as well as from the incomplete combustion of traditional bioenergy – are taken from the IEA’s greenhouse gas emissions database.
Future profiles of carbon-equivalent emissions in the scenarios are based on projected fossil fuel production and reflect the impact of policy initiatives such as the Global Methane Pledge. Net changes in emissions result from the combined effects of changes in fossil fuel output, traditional biomass use, and methane intensity.
There is a wide range of uncertainty with respect to both current estimates of methane emissions and the global warming potential of methane emissions. The methane to CO2e factor used in the scenarios is a 100-year Global Warming Potential (GWP) of 28, recommended by the IPCC Fifth Assessment's GWP values.
To calculate and compare cumulative emissions 2015-50 between IPCC and bp scenarios the following approach is used:
IPCC scenarios are collected from the IPCC Sixth Assessment Report (AR6) Scenario Database, maintained by the International Institute for Applied Systems Analysis (IIASA) in collaboration with the IPCC Working Group III.
In particular, emissions are compared with scenarios in category C3: scenarios that limit global warming below 2°C throughout the century with a probability of greater than 67%.
The median temperature increase of the C3 scenarios in 2100 is 1.6°C. The 5th and 95th percentiles of temperature increases of the IPCC scenarios in 2100 are 1.5°C and 1.8°C respectively.
For each scenario, the database provides CO2 emissions from energy and industry, and methane emissions from the energy sector. This information enables the calculation of CO2e emissions directly comparable to those reported in Current Trajectory and Below 2°.
Since the IPCC database offers data at five-year intervals, linear interpolation is employed to estimate emissions for intermediate years.
To mitigate potential distortions, outliers are eliminated by only including scenarios between the 10th and 90th percentiles for each emission variable within each scenario.
Finally, the resulting figures for cumulative CO2e emissions are calculated from 2015-50. This timeframe was chosen because recent emission data may deviate significantly from some scenario projections.
Data definitions are based on the Statistical Review of World Energy by the Energy Institute, unless otherwise noted. Unless otherwise noted, data used for comparisons is rebased to be consistent with the Statistical Review. Primary energy, unless otherwise noted, comprises commercially traded fuels and traditional biomass.
In this Outlook, primary energy is derived using the direct equivalent method. This method simplifies primary energy accounting by directly equating secondary energy from non-combustible sources (e.g. electricity and heat) to the primary energy used to produce it.
GDP is expressed in terms of real purchasing power parity (PPP) at 2015 prices.
Transport includes energy used in light- and heavy-duty road transport, marine, rail and aviation. Light-duty vehicles include four-wheel vehicles under 3.5 tonnes gross vehicle weight. Electric vehicles include all four wheeled vehicles capable of plug-in electric charging. Industry includes energy used in commodity and goods manufacturing, construction, mining, the energy industry including pipeline transport, agriculture, forestry, fishing, and for transformation processes outside of power, heat and hydrogen generation. Feedstocks include non-combusted fuel that is used as a feedstock to create materials such as petrochemicals, lubricant and bitumen. Buildings include energy used in residential and commercial buildings.
‘Developed economies’ is approximated as the United States, Canada, developed Europe and developed Asia. ‘Emerging economies’ refers to all other countries and regions not in ‘developed economies’. China refers to mainland China. Developed Asia includes OECD Asia plus other high-income Asian countries and regions. Emerging Asia includes all countries and regions in Asia excluding mainland China, India and developed Asia.
Oil, unless otherwise noted, includes crude (including shale oil and oil sands), natural gas liquids (NGLs), gas-to-liquids (GTLs), coal-to-liquids (CTLs), condensates, and refinery gains. Hydrogen-derived fuels are all fuels derived from low carbon hydrogen, including ammonia, methanol, and other synthetic hydrocarbons.
Renewables, unless otherwise noted, include wind, solar, geothermal, biomass, biomethane, and biofuels, and excludes large-scale hydropower. Non-fossils include renewables, nuclear and hydropower. Traditional biomass refers to solid biomass (typically not traded) used with basic technologies, e.g. for cooking.
Biofuels are liquid fuels made from bio-based solid or gaseous feedstocks. They include i) biogasoline (ethanol), ii) biodiesel, and iii) biojet (ASTM certified jet fuel). Mostly they come to market through blending with the relevant refined oil equivalent products, but the category can include directly usable bio-based liquid drop-in fuels such as renewable diesel (HVO) and bio-methanol.
Biogas is produced via a mature technology (anaerobic digestion) and is used directly for heat and power generation, or upgraded into biomethane for use in transport, utilities and other applications. Biogas which is not upgraded into biomethane is accounted for under modern solid biomass.
Hydrogen demand includes its direct consumption in transport, industry, buildings, power and heat, as well as feedstock demand for the production of hydrogen-derived fuels and for conventional refining and petrochemical feedstock demand. Low carbon hydrogen includes green hydrogen, as well as hydrogen production from biomass, gas with CCUS, and coal with CCUS. CCUS options include CO2 capture rates of 90-98% over the Outlook.
This publication contains forward-looking statements – that is, statements related to future, not past events and circumstances. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, anticipates, ‘plans’, ‘we see’ or similar expressions. In particular, the following, among other statements, are all forward looking in nature: statements regarding the global energy transition, increasing prosperity and living standards in the developing world and emerging economies, expansion of the circular economy, energy demand, consumption and access, impacts of the Coronavirus pandemic, the global fuel mix including its composition and how that may change over time and in different pathways or scenarios, the global energy system including different pathways and scenarios and how it may be restructured, societal preferences, global economic growth including the impact of climate change on this, population growth, demand for passenger and commercial transportation, energy markets, energy efficiency, policy measures and support for renewable energies and other lower carbon alternatives, sources of energy supply and production, technological developments, trade disputes, sanctions and other matters that may impact energy security, and the growth of carbon emissions.
By their nature, forward-looking statements involve risk and uncertainty because they relate to events, and depend on circumstances, that will or may occur in the future and are outside the control of bp. Actual outcomes may differ materially from those expressed in such statements depending on a variety of factors, including: the specific factors identified in the discussions expressed in such statements; product supply, demand and pricing; political stability; general economic conditions; demographic changes; legal and regulatory developments; availability of new technologies; natural disasters and adverse weather conditions; wars and acts of terrorism or sabotage; public health situations including the impacts of an epidemic or pandemic and other factors discussed in this publication. bp disclaims any obligation to update, revise or supplement this publication or to correct any inaccuracies which may become apparent. No warranty or representation is made regarding the accuracy, completeness or validity of the information contained in this publication. Neither BP p.l.c. nor any of its subsidiaries (nor their respective officers, employees and agents) accept any liability whatsoever for any loss or damage arising from reliance on or actions taken based on, any of the information set out in this publication.
| Level in 2050* | Change 2023-2050 (p.a.) | Share of primary energy in 2050 | |||||
|---|---|---|---|---|---|---|---|
| 2023 | Current Trajectory | Below 2° | Current Trajectory | Below 2° | Current Trajectory | Below 2° | |
| Primary energy by fuel | |||||||
| Total | 601 | 653 | 449 | 0.3% | -1.1% | 100% | 100% |
| Oil | 197 | 158 | 62 | -0.8% | -4.2% | 24% | 14% |
| Natural gas | 144 | 173 | 66 | 0.7% | -2.9% | 27% | 15% |
| Coal | 167 | 102 | 24 | -1.8% | -6.9% | 16% | 5% |
| Nuclear | 10 | 16 | 22 | 1.8% | 3.0% | 2% | 5% |
| Hydro | 15 | 21 | 24 | 1.2% | 1.7% | 3% | 5% |
| Renewables (incl. bioenergy) | 68 | 182 | 251 | 3.7% | 5.0% | 28% | 56% |
| Primary energy by fuel (native units) | |||||||
| Oil (Mb/d) | 100 | 83 | 34 | ||||
| Natural gas (Bcm) | 4,007 | 4,806 | 1,823 | ||||
| Primary energy by region | |||||||
| Developed | 202 | 168 | 123 | -0.7% | -1.8% | 26% | 28% |
| US | 87 | 79 | 59 | -0.3% | -1.4% | 12% | 13% |
| EU | 52 | 39 | 27 | -1.1% | -2.3% | 5.9% | 6.1% |
| UK | 6.3 | 5.0 | 4.7 | -0.9% | -1.1% | 0.8% | 1.0% |
| Emerging | 399 | 484 | 325 | 0.7% | -0.8% | 74% | 72% |
| China | 156 | 135 | 98 | -0.5% | -1.7% | 21% | 22% |
| India | 45 | 81 | 54 | 2.2% | 0.7% | 12% | 12% |
| Brazil | 13 | 16 | 13 | 0.7% | -0.1% | 2% | 3% |
| Level in 2050* | Change 2023-2050 (p.a.) | Share of final consumption in 2050 | |||||
|---|---|---|---|---|---|---|---|
| 2023 | Current Trajectory | Below 2° | Current Trajectory | Below 2° | Current Trajectory | Below 2° | |
| Total final consumption by sector | |||||||
| Total | 493 | 572 | 406 | 0.6% | -0.7% | 100% | 100% |
| Transport | 121 | 122 | 92 | 0.0% | -1.0% | 21% | 23% |
| Industry | 214 | 246 | 186 | 0.5% | -0.5% | 43% | 46% |
| Feedstocks | 41 | 58 | 42 | 1.3% | 0.1% | 10% | 10% |
| Buildings | 117 | 145 | 85 | 0.8% | -1.2% | 25% | 21% |
| Generation | |||||||
| Power ('000 TWh) | 30 | 58 | 70 | 2.5% | 3.2% | ||
| Hydrogen (Mt) | 79 | 136 | 359 | 2.0% | 5.8% | ||
| Production | |||||||
| Oil (Mb/d) | 99 | 88 | 32 | -0.5% | -4.1% | ||
| Natural gas (Bcm) | 4,059 | 4,806 | 1,844 | 0.6% | -2.9% | ||
| Coal (EJ) | 179 | 108 | 22 | -1.8% | -7.4% | ||
| Emissions | |||||||
| Carbon emissions (net Gt of CO2e) | 41 | 31 | 4.1 | -1.1% | -8.2% | ||
| Carbon capture & storage (Gt of CO2) | 0.0 | 0.7 | 5.5 | 16.4% | 25.5% | ||
| Macro | |||||||
| GDP (trillion US$ PPP) | 142 | 279 | 279 | 2.5% | 2.5% | ||
| Energy intensity (MJ of PE per US$ of GDP) | 4.2 | 2.3 | 1.6 | -2.2% | -3.5% | ||
| *Exajoules (EJ) unless otherwise stated | |||||||
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