The Global Energy Perspective 2023 models the outlook for demand and supply of energy commodities across a 1.5°C pathway, aligned with the Paris Agreement, and four bottom-up energy transition scenarios. These energy transition scenarios examine outcomes ranging from warming of 1.6°C to 2.9°C by 2100 (scenario descriptions outlined below in sidebar “About the Global Energy Perspective 2023”). These wide-ranging scenarios sketch a range of outcomes based on varying underlying assumptions—for example, about the pace of technological progress and the level of policy enforcement. The scenarios are shaped by more than 400 drivers across sectors, technologies, policies, costs, and fuels, and serve as a fact base to inform decision makers on the challenges to be overcome to enable the energy transition. In this article, we dive into the investments and advancements needed to both meet the world’s growing power demand and strive for a decarbonized energy system.
About the Global Energy Perspective 2023
Power demand is projected to climb across scenarios due to several factors that are likely to differ by region, including the growth in emerging markets’ energy needs, electrification across the global economy (particularly in transport), and rising green hydrogen demand. The share of renewables in the global power mix could more than double in the next 20 years, and a boost in flexible capacity may be needed to ensure security of supply.
While significant growth in renewables is projected, clean firm power generation1 (including from CCUS, nuclear, and hydrogen) is projected to increase in the long term across scenarios.
Obstacles may, however, hinder the pace of some renewables build-out and trigger price spikes, creating the need for other technologies, including other renewables (such as geothermal) and non-renewable alternatives (such as nuclear). Developing economies may require economic support to bolster capacity build-out, and transmission and distribution (T&D) investments would need to increase across the globe. As the cost of power generation declines due to a projected rapid cost decline for renewables in certain regions, the share of grid costs in total delivered power costs is projected to grow, and customers in many places will potentially not see power prices decline.
Global power demand is projected to grow across sectors in all scenarios
Global electricity demand is expected to more than double from 25,000 terawatt-hours (TWh) to between 52,000 and 71,000 TWh by 2050, due to the growth in emerging markets’ energy needs and electrification across the economy.
The transport sector is projected to see a steep growth in power demand, driven by passenger electric vehicles, which are expected to reach subsidy-free cost parity with internal combustion engines by around 2025 in China, Europe, and the United States. By 2050, global passenger battery electric vehicle car parc is projected to reach 1.3 billion—almost equal to the total number of all cars today.
Within industry, power demand is projected to double by 2050 due to the electrification of low- to medium-heat processes, as well as growth in demand from data centers. Similarly, power demand in buildings is projected to double, driven by increased demand in emerging markets and electrification in OECD countries.
Demand growth is driven by different sectors across geographies
Under all scenarios, power demand is projected to grow across the globe, driven by several factors that differ by region, including population growth, increasing wealth per capita, and electrification. Although China, India, and North America are projected to represent more than half of the global power demand growth, economies in regions such as Africa and the Middle East are projected to see the fastest relative growth as their wealth per capita grows.
Demand growth may be driven by different sectors in different geographies. In North America, green hydrogen is projected to drive most of the growth in the short and long term, spurred by recent government support, while electrified transport is projected to account for around 30 percent of demand growth to 2030. In Europe, green hydrogen is projected to be the main driver in the long term, with industrial decarbonization as the driving force to 2030.
Demand growth in Latin America is projected to be driven by buildings in the short term, with hydrogen exports assuming an increasingly important role in the long term, accounting for more than a quarter of power demand growth after 2030.
China is projected to account for the largest absolute growth in power demand in both the short and medium term, with industrial electrification as the primary driver. In India, industrial growth is projected to account for the majority of the increase in power demand in the country, while the buildings sector is projected to drive around 30 percent of demand growth, due to higher demand for cooling. In Southeast Asia, buildings and industry are projected to make up over 80 percent of the total demand growth. Meanwhile, other Asian countries may experience a mixed demand growth led by buildings and industry.
Australia’s demand growth is projected to be relatively small on a global scale, with growth driven by its potential role as an exporter of commodities derived from green hydrogen.
Buildings are projected to be the primary driver of demand growth in Africa, due to increasing wealth per capita.
The share of renewables in the power mix is projected to more than double in the next 20 years
Renewables are expected to continue to grow rapidly over the next decades to provide around 45 to 50 percent of generation by 2030 and 65 to 85 percent by 2050, depending on the scenario. By 2050, in the Achieved Commitments scenario, emissions could be reduced by up to 72 percent compared to present levels, driven by rapid deployment of zero- or low-carbon emitting technologies in the global power system.
However, the build-out of renewables could face several bottlenecks, including lack of availability of key materials, infrastructure, and land availability, supply chain issues, and labor shortages, as well as to slow permitting and local resistance. The uptake of nuclear and carbon capture, utilization, and storage (CCUS) technologies could complement renewables build-out, but this depends on the political landscape and future cost and technology development.
Among thermal generating technologies, unabated coal is expected to be phased out gradually. Meanwhile, power generation and capacity build-out from clean, dispatchable plants, including renewable energy resources such as hydro reservoir, geothermal, biomass, concentrated solar power plants with storage, or clean fuels such as hydrogen, are likely to rise due to their importance for grid stability.
Flexible assets may be needed to meet peak demand in a more weather-dependent net-zero system
With the projected growth in power demand, the retirement of older, non-flexible dispatchable capacity, and the growing share of intermittent renewables, there may be a greater need for flexible assets on both the supply and demand sides to ensure security of supply.
In the long term, storage is expected to play a major role, with batteries to support bulk power generation projected to grow to more than 2,000 gigawatts (GW) in capacity by 2050 in the Further Acceleration and Achieved Commitments scenarios. Gas is projected to remain a stable source of flexibility for the system toward 2050, even in the fastest energy transition scenarios.
Africa, India, and the Middle East are projected to need the largest increase in renewables deployment
In the Current Trajectory scenario, solar and wind could make up around 70 percent of total global installed capacity by 2050. Gas and other firm capacity would still account for around 30 percent for resource adequacy.
Global yearly capacity additions for solar are projected to grow by at least 1.5 times in every region except China, and more than nine times in Africa. However, China could see an upside of 100 GW of solar capacity addition given the momentum in 2023, which could be unlocked by grid and storage build-out.
Likewise for wind, global yearly net capacity additions are projected to reach around 150 GW by 2030 and 230 GW by 2050, with most regions required to more than double the annual installations seen in 2021–22.
Economies in regions with higher interest rates could require support to reach these accelerated build-out rates, such as increased investments from abroad or more innovative financing models to lower the cost of financing and secure access to capital.
Increased transmission and distribution investments are needed to support the outlook
Total annual investments in the energy sector are projected to grow by up to 5 percent per annum to reach between $1.3 trillion and $2.4 trillion by 2040. These figures are feasible, and the necessary investments are already underway.
Investments in T&D networks are projected to experience the highest growth of between 4 and 8 percent per annum, reaching between $0.6 trillion and $1.2 trillion by 2040, depending on the scenario. This is especially the case in faster decarbonization scenarios, where larger grid upgrades are projected to be required to support higher penetration of renewables and higher electric loads from electrified final demand.
Investments in renewable power are also expected to increase under all scenarios, reaching $0.5 trillion to $1.0 trillion per year by 2040, driven by significant new wind- and solar-capacity additions. However, the continued need for firm capacity and the increase in electricity demand in developing economies is projected to maintain a high level of investments to meet demand for various types of firm power generation, even as utilization levels of these plants drop, which is expected to reach between $100 billion and $200 billion in 2040.
While the cost of power generation is projected to decline, the share of grid costs is projected to grow
The cost of power generation over time is projected to see a declining trend in future power systems. However, T&D costs per megawatt hour (MWh) are projected to grow, from around 40 percent in 2021 to between 60 and 70 percent by 2050 in the United States, for example, with a similar outlook in Australia.
In faster decarbonization scenarios, larger T&D investments could be partially offset by a higher load in a more electrified economy, but not entirely. The generation cost advantage in faster scenarios reflects the more rapid cost declines for renewables (for example, $15 to $20 per MWh for solar by 2050).
System design choices are projected to have a large impact on total costs, such as undergrounding for resiliency, grid modernization to support distributed energy resources (DERs), and siting of heavy industrial loads (like hydrogen or data center clusters).
To manage a system which is moving more toward fixed costs, updates to power market designs may be needed
In most markets today, conventional assets (such as coal, gas, oil, nuclear, and hydro) provide energy in the market as well as firming capacity. With the further expected growth in solar and wind capacity, the role of conventional plants may be decoupled, moving from providing both the primary source of energy and firm capacity to largely providing firming and flexibility in the system. As a marginal market price is projected to correlate with short-run marginal costs across the system, additional remuneration could be needed for asset types to remain profitable to enable their continued operation and especially to fund the technologies required to abate emissions from these operations. By 2040, up to 15 percent of revenues from nuclear assets, 50 percent of revenues from gas assets, and 65 percent of revenues from coal assets may need to come from market mechanisms other than marginal energy production payments for these technologies to remain viable in order to meet remaining transition demand.
Renewable assets with fixed (non-dispatchable) outputs may be subject to correlation effects that drive down prices during periods of high wind and solar production. This will tend to decrease the capture price of those technologies, where variable prices no longer link to total lifecycle cost of production. Out-of-market payments, such as contracts for difference or power purchase agreements, which often include renewable energy certificates which show that a given plant produces renewable power, will likely continue to be needed to secure financing.
Dispatchable thermal capacity, such as gas plants, are more likely to maintain positive returns in geographies with lower fuel costs, such as in the United States. Similarly, clean technologies, such as CCUS, are expected to leverage a variety of market payments as well as support initiatives to maintain profitability.
Regarding older conventional technologies, coal is likely to be largely retired in the near future, while other unabated carbon-emitting technologies will likely run less frequently than they do at present. Nevertheless, as renewable power is ramped up, managing conventional technologies still in use to minimize their environmental impact could be an important concern.
Revenue mechanisms could include capacity markets and payments, subsidies, regulated prices, active markets for clean energy certificates, and contracts for difference to limit uncertainty. Some of these mechanisms already exist in markets globally.
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