Energy Outlook 2024 explores the key trends and uncertainties surrounding the energy transition.
This year’s Energy Outlook is focused on two main scenarios: Current Trajectory and Net Zero. These 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 entirely new or unknown technologies.
The many uncertainties surrounding the possible speed and nature of the energy transition means the probability of any one of these 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 Energy Outlook is produced to inform bp’s views of the risks and opportunities posed by the energy transition and is published 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.
To calculate and compare cumulative emissions 2015-50 between IPCC and bp scenarios we use the following approach:
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. Four relevant categories of scenarios were chosen:
Descriptions of the characteristics of these types of scenarios can be found in Table 3.1 in the IPCC Sixth Assessment Report (Climate Change 2022: Mitigation of Climate Change) cited below.
For each scenario, the database provides CO2 emissions from energy and industry, and methane emissions from the energy sector. This information allows us to calculate CO2-equivalent (CO2e) emissions directly comparable to those reported in bp Current Trajectory and bp Net Zero scenarios.
Since the IPCC database offers data at five-year intervals, we employ linear interpolation to estimate emissions for intermediate years.
To mitigate potential distortions, we eliminate outliers by only including scenarios between the 10th and 90th percentiles for each emission variable within each scenario.
Finally, we calculate the resulting figures for cumulative CO2e emissions from 2015 to 2050. This timeframe was chosen because recent emission data may deviate significantly from some scenario projections.
The analysis of the difference in carbon emissions between Current Trajectory (CT) and Net Zero (NZ) 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 NZ can be decomposed into two contributions: the change in total electricity demand, and the change in power emissions intensity. Electricity demand is higher in NZ than in CT as the world electrifies more in NZ. The carbon intensity of power is lower in NZ 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 NZ in the power sector, we only consider the contribution due to lower carbon intensity. 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 NZ level. In the below, we elaborate on our end-use sector methodology by sector.
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 transport mode 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. The contribution from ‘Other’ refers to 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.
The Delayed Net Zero scenario combines elements of both Current Trajectory and Net Zero scenarios.
In a first step we calculate adjusted emissions pathways for the Current Trajectory and Net Zero scenarios. This step involves removing methane emissions from energy sources and traditional biomass and adding CO2 emissions from Agriculture, Forestry and Other Land Use (AFOLU) from the IPCC C3 (for Net Zero) and C5 (for Current Trajectory) scenarios.
In the Delayed Net Zero scenario, emissions accrue as in Current Trajectory until 2030. After 2030, the energy system transitions as in the Net Zero pathway and CO2 emissions are calculated based on primary consumption levels for different fuels. The level of cumulative emissions of this scenario is around 900 GtCO2.
This is close to the carbon budget taken from the IPCC Summary for Policymakers report (IPCC, 2021), which estimates that cumulative emissions of 900 GtCO2 are consistent with limiting global temperature increase below 2°C with a likelihood of 83%.
The Fastest IPCC decarbonization scenario discussed in the Energy Outlook is a combination of Current Trajectory and a selection of IPCC scenarios that it considers consistent with a global warming of 1.5°C degrees subject to a binding constraint for CO2 emissions.
For our analysis, we begin by selecting all the scenarios from the C1 category in the IPCC Sixth Assessment Report (AR6) Scenario Database that provide data on CO2 emissions from both CO2 emissions from energy and industrial processes and from AFOLU. C1 scenarios represent pathways where global warming is limited to below 1.5°C by 2100 with a greater than 50% chance. Finally, we choose the four scenarios with the most rapid decline in emissions following their peak.
The modelling strategy to define the Fastest IPCC decarbonization scenario is as follows: the energy system evolves as per Current Trajectory until a specific year, and then starts decarbonizing in an accelerated way, mirroring the average rate of decline in emissions of the four IPCC scenarios selected. Using this clearly highly schematic methodology, 2035 is calculated to be the latest year that the system can move from Current Trajectory to the more rapid pace of decarbonization in the fastest IPCC scenarios, while still limiting cumulative emissions to approximately 900 GtCO2.
Emissions after 2050 are calculated on the assumption that the energy system evolves in a similar path as in 2045-50 in each scenario.
The GDP profiles used in the Energy Outlook come from Oxford Economics (OE). These long-term forecasts incorporate estimates of the economic impact of climate change. These estimates follow a similar methodology to that used in Energy Outlook 2020, Energy Outlook 2022 and Energy Outlook 2023.
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 future. However there have been attempts to model its possible effects. In particular, OE 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 ‘cold country’ income growth increases with annual temperatures. However, at annual temperatures above 15°C, per capita income growth is increasingly adversely affected by higher temperatures.
The OE 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 OE. While OE’s approach captures channels associated with average temperatures, these estimates remain uncertain and incomplete; they do not, for example, explicitly include impact 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 Net Zero than in Current Trajectory. The IPCC estimates (AR6 – Working Group 3) 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 our 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 of our scenarios, relative to the counterfactual in which temperatures are held constant at recent average levels.
Implied levels of oil and gas investment are derived from the production levels in each scenario. Upstream oil and natural gas capital expenditure includes well capex (costs related to well construction, well completion, well simulation, steel costs and materials), facility capex (costs to develop, install, maintain, and modify surface installations and infrastructure) and exploration capex (costs incurred to find and prove hydrocarbons). It excludes operating costs and midstream capex such as capex associated with developing LNG liquefaction capacity.
Asset level production profiles are aggregated by geography, supply segment (onshore, offshore, shale and oil sands), supply type (crude, condensates, NGLs, natural gas) and developmental stage, i.e., classified by whether the asset is currently producing, under development, or non-producing and unsanctioned. As output from producing and sanctioned assets declines, incremental production from infill drilling and new, unsanctioned assets are called on to meet the oil and gas demand shortfalls. The investment required to bring this volume online is then added to any capital costs associated with maintaining these existing and already approved projects. The average 2023-50 decline rate for assets currently producing and under development, including any infill drilling and wells drilled but not yet producing, is around 3% per year for oil and 2% per year for gas, but varies widely by segment and hydrocarbon type. All estimates are derived using asset-level assessments from Rystad Energy.
This analysis focuses solely on the capital expenditure associated with deploying wind and solar electricity generation technologies, considering region-specific cost dynamics and deployment profiles. Additional costs related to integrating renewables into the power system including end-use assets, grid enhancements, and flexibility requirements, are not included in this assessment.
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 for natural gas flaring data is taken from VIIRS Nightfire (VNF) data and produced by the Earth Observation Group (EOG), Payne Institute for Public Policy, Colorado School of Mines. The profiles for natural gas flaring in the scenarios assume that flaring moves in line with wellhead upstream output.
Historical data on methane emissions associated with the production, transportation and distribution of fossil fuels and incomplete combustion of traditional bioenergy are sourced from IEA estimates of greenhouse gas emissions. The profiles for future methane emissions assumed in the scenarios are based on fossil fuel production and take account of policy initiatives such as the Global Methane Pledge. The net change in methane emissions is the aggregation of future changes to fossil fuel production, traditional biomass consumption, 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.
Data definitions are based on the Energy Institute Statistical Review of World Energy, unless otherwise noted. Data used for comparisons, unless otherwise noted, are 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:
In previous editions of the Energy Outlook, the primary energy accounting method used was the so-called substitution method. The substitution method reports primary energy from non-fossil fuel as if they had been substituted by fossil fuels. However, as the energy system decarbonizes, potential insights from this methodology are less informative.
For those interested in shifting to use the substitution method for primary energy, the table below shows the calorific efficiency assumed for fossil fuels in previous editions of the Energy Outlook:
| Year | Factor | |||||
|---|---|---|---|---|---|
1965 | 36% |
1980 | 36% |
1995 | 36% |
2010 | 38% |
2025 | 41% |
2040 | 44% |
1970 | 36% |
1985 | 36% |
2000 | 36% |
2015 | 40% |
2030 | 42% |
2045 | 44% |
1975 | 36% |
1990 | 36% |
2005 | 37% |
2020 | 41% |
2035 | 43% |
2050 | 45% |
GDP is expressed in terms of real Purchasing Power Parity (PPP) at 2015 prices.
Transport includes energy used in heavy road, light road, marine, rail and aviation. Light duty vehicles include 4-wheel vehicles under 3.5 tonnes gross vehicle weight. Electric vehicles (EVs) 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 United States, Canada, Europe and Developed Asia. ‘Emerging economies’ refers to all other countries and regions not in ‘Developed economies’. China refers to the Chinese Mainland. 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, includes wind, solar, geothermal, biomass, biomethane, and biofuels and excludes large-scale hydro. Non-fossils include renewables, nuclear and hydro. 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 & 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-dervied fuels and for conventional refining and petrochemical feedstock demand. Low carbon hydrogen includes green hydrogen, 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 2022-2050 (p.a.) | Share of primary energy in 2050 | |||||
|---|---|---|---|---|---|---|---|
| 2022 | Current Trajectory | Net Zero | Current Trajectory | Net Zero | Current Trajectory | Net Zero | |
| Primary energy by fuel | |||||||
| Total | 595 | 635 | 437 | 0.2% | -1.1% | 100% | 100% |
| Oil | 191 | 146 | 52 | -0.9% | -4.6% | 23% | 12% |
| Natural gas | 143 | 170 | 65 | 0.6% | -2.8% | 27% | 15% |
| Coal | 165 | 108 | 23 | -1.5% | -6.8% | 17% | 5% |
| Nuclear | 10 | 15 | 21 | 1.7% | 2.8% | 2% | 5% |
| Hydro | 16 | 22 | 28 | 1.2% | 2.0% | 3% | 6% |
| Renewables (incl. bioenergy) | 70 | 174 | 249 | 3.3% | 4.6% | 27% | 57% |
| Primary energy by fuel (native units) | |||||||
| Oil (Mb/d) | 97 | 77 | 28 | ||||
| Natural gas (Bcm) | 3,985 | 4,729 | 1,797 | ||||
| Primary energy by region | |||||||
| Developed | 208 | 163 | 125 | -0.9% | -1.8% | 26% | 29% |
| US | 88 | 73 | 60 | -0.7% | -1.4% | 11% | 14% |
| EU | 55 | 40 | 28 | -1.1% | -2.3% | 6% | 6% |
| UK | 7 | 5 | 5 | -0.8% | -1.1% | 1% | 1% |
| Emerging | 387 | 473 | 312 | 0.7% | -0.8% | 74% | 71% |
| China | 146 | 128 | 94 | -0.5% | -1.6% | 20% | 21% |
| India | 42 | 80 | 51 | 2.3% | 0.7% | 13% | 12% |
| Brazil | 13 | 16 | 13 | 0.8% | -0.1% | 3% | 3% |
| Level in 2050* | Change 2022-2050 (p.a.) | Share of final consumption in 2050 | |||||
|---|---|---|---|---|---|---|---|
| 2022 | Current Trajectory | Net Zero | Current Trajectory | Net Zero | Current Trajectory | Net Zero | |
| Total final consumption by sector | |||||||
| Total | 488 | 551 | 383 | 0.4% | -0.9% | 100% | 100% |
| Transport | 117 | 115 | 85 | -0.1% | -1.1% | 21% | 22% |
| Industry | 210 | 237 | 176 | 0.4% | -0.6% | 43% | 46% |
| Feedstocks | 41 | 54 | 38 | 1.1% | -0.2% | 10% | 10% |
| Buildings | 122 | 144 | 84 | 0.6% | -1.3% | 26% | 22% |
| Energy carriers (generation) | |||||||
| Electricity ('000 TWh) | 29 | 54 | 69 | 2.2% | 3.1% | ||
| Hydrogen (Mt) | 75 | 143 | 389 | 2.3% | 6.1% | ||
| Production | |||||||
| Oil (Mb/d) | 94 | 75 | 29 | -0.8% | -4.1% | ||
| Natural gas (Bcm) | 4,044 | 4,730 | 1,796 | 0.6% | -2.9% | ||
| Coal (EJ) | 175 | 109 | 23 | -1.7% | -7.0% | ||
| Emissions | |||||||
| Carbon emissions (Gt of CO2e) | 41 | 31 | 2 | -1.0% | -10.2% | ||
| Carbon capture use & storage (Gt) | 0.0 | 0.9 | 6.8 | ||||
| Macro | |||||||
| GDP (trillion US$ PPP) | 137 | 268 | 268 | 2.4% | 2.4% | ||
| Energy intensity (MJ of PE per US$ of GDP) | 4.3 | 2.4 | 1.6 | -2.1% | -3.4% | ||
| *Exajoules (EJ) unless otherwise stated | |||||||