Energy Outlook 2023 is focused on three main scenarios: Accelerated, Net Zero and New Momentum. 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 and the uncertainties around those judgements. 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 transition of the global energy system mean that the probability of any one of these scenarios materializing exactly as described is negligible. Moreover, the three scenarios do not provide a comprehensive range of possible paths for the transition ahead. They do, however, span a wide range of possible outcomes and so help to illustrate the key uncertainties surrounding energy markets out to 2050.
The scenarios in this year’s Outlook have been updated to take account of two major developments over the past year: the Russia-Ukraine war and the passing of the Inflation Reduction Act in the US. Aside from updating for those two developments, the scenarios are based largely on the analysis and scenarios in Energy Outlook 2022. They do not include a comprehensive assessment of all the changes and developments since Outlook 2022.
The Energy Outlook is produced to inform bp’s strategy and is published as a contribution to the wider debate about the factors shaping the energy transition. But the Outlook is only one source among many when considering the future of global energy markets and bp considers a wide range of other external scenarios, analysis and information when forming its long-term strategy.
The impact of the Russia-Ukraine war was modelled by capturing three types of economic shock associated with the war: near-term commodity price (stagflation) shock, heightened energy security concerns, and a reduced pace of globalization.
This shock is modelled as a sharp but transitory increase in fossil fuel prices, combined with significantly lower global GDP. Real interest rates are also higher as central banks tighten monetary policy to control inflation, which increase the levelized costs of different energy sources, affecting the relative prices of alternative technologies. The shock dissipates by 2030, by which time prices and, in almost all cases, GDP levels have returned to their long-term trend. The exception to this is the level of GDP in Russia and Ukraine, where the war is assumed to have a persistent negative impact on GDP.
The Russia-Ukraine war is assumed to cause governments to implement policies to reduce their dependency on imported energy. The shock is modelled by adding a c.30% ‘security’ premium to the price of the energy imported into each region or country. This premium is increased to roughly 60% for energy imported by the EU given its particular exposure to war-related disruption and the need to reduce imports from Russia rapidly. The security premium imposed on imported energy increases the competitiveness of domestically produced energy, including renewables, nuclear and hydro power.
The war in Ukraine is assumed to reduce the pace of globalization, as countries and regions heighten their focus on domestic resilience and reduce their exposure to international shocks. The lower profile for international trade and openness has a small but negative impact on global economic growth. Although the effect is small on a yearly basis – reducing average annual growth by around 0.1 percentage point – the impact on the level of GDP compounds over time, reducing the level of global GDP by around 4% in 2050.
The impact from this reduced pace of globalization is assumed to have different effects in different countries and regions: with those economies whose future economic growth is particularly dependent on international trade and on the sharing of ideas and productivity the most heavily impacted. For example, the shock has a much larger impact on emerging Asian economies than on the United States. The methodology used to calibrate the deglobalization shock is based on the trade growth literature, including studies by the World Bank (2017) and Alcala and Ciccone (2004).
Although these three shocks are assumed to take effect immediately, their peak effects occur over different time frames. In the short term (up until around 2025), the commodity price shock is the most impactful. In the medium term (around 2030-2035), the impact from heightened energy security concerns has the largest impact on the energy system. In the longer term, the lower level of global activity caused by reduced pace of globalization is preeminent.
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 draw on the latest research in the scientific literature and follow a similar methodology to that used in Energy Outlook 2020 and Energy Outlook 2022.
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 to an average (population weighted) temperature of just under 15°C (Burke et al.’s initial assessment was 13°C). 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 emissions forecasts are broadly in line with the IEA STEPS scenario and assume average global temperatures will reach 2°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 the temperature change remained at the current level. The regional impacts are distributed according to the evolution of their 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 Accelerated and Net Zero than in New Momentum. Estimates published by the IPCC (AR5 – Chapter 6) suggest that for scenarios consistent with keeping global temperature increases to well below 2°C, median estimates of mitigation costs range between 2-6% of global consumption by 2050.
Given the huge range of uncertainty surrounding estimates of the economic impact of both climate changes and mitigation, and the fact that all three of the main 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 all three 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 production from producing and sanctioned assets declines, incremental production from infill drilling and new, unsanctioned assets is 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 producing and sanctioned projects. The average 2022-2050 decline rate for assets currently producing and under development is around 4.5% p.a. for both oil and for natural gas, although this varies widely by segment and hydrocarbon type. All estimates are derived using asset-level assessments from Rystad Energy.
Wind and solar energy investment requirements are based on the capital expenditure costs associated with the deployment profiles of each technology in each scenario.
Wind and solar deployment profiles include both renewable power capacity for end-use and for green hydrogen production. The deployment profiles also consider the potential impact of curtailment.
Capital expenditure costs are assigned to each scenario based on their historical values and estimated future evolution. They are differentiated by technology, region and scenario using a combination of internal bp estimates and external benchmarking. The capital expenditure figures do not include the incremental wider system integration costs associated with wind and solar deployment.
Unless otherwise stated, carbon emissions refer to CO2 emissions from:
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 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 recent policy initiatives such as the Global Methane Pledge. The net change in methane emissions is the aggregation of future changes to fossil fuel production 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 25, recommended by the IPCC in AR4. This conversion factor is used to ensure alignment with financial and government reporting standards, and to ensure consistency across all bp corporate reporting. In particular, this is the same factor to be used in the bp Annual Report, also published in Q1 2023.
We use scenarios that are in the database corresponding to the Sixth Assessment Report published in 2022. This database is hosted by the International Institute for Applied Systems Analysis (IIASA) as part of a cooperation agreement with Working Group III of the IPCC.
The scenarios used in the analysis are those labelled as:
Data definitions are based on the bp Statistical Review of World Energy, unless otherwise noted. Data used for comparisons, unless otherwise noted, are rebased to be consistent with the bp Statistical Review.
Primary energy, unless otherwise noted, comprises commercially traded fuels and traditional biomass. In this Outlook, primary energy is derived using:
Gross Domestic Product (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. 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, and for transformation processes outside of power, heat and hydrogen generation. Feedstocks includes non-combusted fuel that is used as a feedstock to create materials such as petrochemicals, lubricant and bitumen. Buildings includes energy used in residential and commercial buildings, agriculture, forestry, and fishing.
Developed is approximated as North America plus Europe plus Developed Asia. Emerging refers to all other countries and regions not in Developed. 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 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 exclude 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.
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, and hydrogen produced from biomass with CCUS, gas with CCUS, and coal with CCUS. CCUS options include CO2 capture rates of 93-98% over the Outlook. The global average methane emissions rate for the gas or coal consumed to produce blue hydrogen is between 1.4-0.7% 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, urbanization and increasing industrialization and productivity, 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.
Forward-looking statements involve risks and uncertainties because they relate to events, and depend on circumstances, that will or may occur in the future. 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 this publication or to correct any inaccuracies which may become apparent. Neither BP p.l.c. nor any of its subsidiaries (nor any of their respective officers, employees and agents) accept liability for any inaccuracies or omissions or for any direct, indirect, special, consequential or other losses or damages of whatsoever kind in or in connection with this publication or any information contained in it.
|Level in 2050*||Change 2019-2050 (p.a.)||Share of primary energy in 2050|
|Primary energy by fuel|
|Renewables (incl. bioenergy)||74||377||403||256||5.4%||5.6%||4.1%||57%||64%||35%|
|Primary energy by fuel (native units)|
|Natural gas (Bcm)||3900||2422||1658||4616|
|Primary energy by region|
|Level in 2050*||Change 2019-2050 (p.a.)||Share of total consumption in 2050|
|Total final consumption by sector|
|Energy carriers (generation)|
|Electricity ('000 TWh)||27||57||61||50||2.4%||2.7%||2.0%||52%||66%||35%|
|Natural gas (Bcm)||3976||2422||1658||4616||-1.6%||-2.8%||0.5%|
|Net emissions from energy and industry (Gt of CO2e)||39.8||9.1||2.0||28.7||-4.7%||-9.1%||-1.1%|
|Carbon capture, use and storage (Gt)||0.0||4.1||6.1||1.1||56%||58%||49%|
|GDP (trillion US$ PPP)||128||266||266||266||2.4%||2.4%||2.4%|
|Energy intensity (MJ of TFC per US$ of GDP)||3.7||1.5||1.3||1.9||-2.9%||-3.5%||-2.1%|
|* Exajoules (EJ) unless otherwise stated|