Energy Markets Digest - Summer 2023
Chiron Financial LLC released its first in its new series of Energy Markets Digest, where Chiron Financial LLC will review the key components of the energy markets. In this inaugural digest, the energy markets and pricing are likely to remain non-threatening in the near term as the global economic outlook remains cloudy due to the slow return of growth in China.
A more balanced market outlook
–The Brent oil price fell from its June 2022 peak of $123 per barrel to $75 in May 2023, and the Henry Hub natural gas price dropped from its August 2022 peak of $8.81 per million British thermal units (MMbtu) to $2.15 in May 2023.1 Electric power markets also saw some wild swings, especially in Europe, but those have been mitigated by renewables, nuclear, mild weather, and government subsidies.
–With the global economic outlook remaining cloudy due to the slow return of growth in China, and high inflation leading to substantially higher interest rates as well as some disruption in the banking system, energy markets and pricing are likely to remain non-threatening in the near term.
–The shift toward clean energy is accelerating, China is leading in electric car production, the IRA tax credits are jump starting green energy investments in the US, and the oil market appears to be adequately supplied.
–Despite the progress, the rate of investment in clean energy — about $1.3 T this year — is far short of what is needed to meet carbon reduction goals. The International Renewable Energy Agency says $35 T is needed by 2030 to stay on track.
The IEA Oil 2023 report released June 14 projects an adequately supplied oil market to meet reduced demand growth over the next five years and declining demand thereafter
–Global oil demand growth is projected at 2.4 million barrels per day (MMb/d) in 2023, mainly in Asia, then falling below 1.0 MMb/d.
–China’s demand recovery following COVID shutdowns has begun, but more slowly than earlier expectations.
–Oil supply growth of 5.9 MMb/d is predicted in 2023, led by the US and Brazil.
–Russian oil supply has nearly recovered after a decline in 2022; April exports reached a post-invasion high of 8.3 MMb/d.3
–OPEC+ quota cuts offset other production growth but have not been enough to sustain higher prices.
–Brent oil price predictions from various analysts are in the $70s to low $80s per barrel.
At the end of 1Q23, European hub and Asian spot liquefied natural gas (LNG) prices had fallen below their summer 2021 levels, albeit remaining well above their historic averages
–Following the supply shock sparked by Russia’s invasion of Ukraine in February 2022, spot gas prices across the key northeast Asian, North American and European markets dropped by close to 70% between mid-December and the end of the 1Q23.
–Natural gas consumption in Europe’s advanced economies fell by an estimated 55 billion cubic meters (bcm) year-over-year (YoY) during the 2022⁄23 heating season, a record drop, reflecting mild weather and reduced consumption.
–High storage levels in Europe are expected to reduce injection demand during the summer of 2023.
–The futures market in US gas is anticipating a near doubling in price by year-end to about $4/MMbtu. Key factors including adverse weather, lower availability of LNG, and the possibility of a further decline in Russian pipeline gas deliveries to Europe could easily renew market tensions and upward price pressure.
–The US is projected to account for over half of the LNG global supply increase in 2023 and become the world’s largest LNG exporter. Global LNG supply is forecast to increase by a mere 4% (or over 20 bcm) in 2023 which would not be sufficient to offset an expected reduction in Russia’s piped gas supplies to Europe.
IEA predicts world oil demand is approaching a peak
–Growth in world oil demand is set to lose momentum over the 2022 – 28 forecast period as the energy transition gathers pace, with an overall peak looming on the horizon. Led by continued increases in petrochemical feedstocks, total oil consumption growth will remain narrowly positive through 2028 as usage rises to 105.7 MMb/d, 5.9 MMb/d above 2022 levels.
Demand for oil for combustible fossil fuels – which excludes biofuels, petrochemical feedstocks and other non-energy uses – is on course to peak at 81.6 MMb/d in 2028
–The expected post-pandemic pinnacle in oil demand is expected for gasoline in 2023, road transport in 2025 and total transport in 2026. Some economies, notably China and India, will continue to register growth throughout the forecast. The Organization for Economic Cooperation and Development (OECD) may crest this year, as a result of the sweeping impact of mounting vehicle efficiencies and electrification.
–The global energy crisis sparked a movement towards lower-emission sources, as well as policy emphasis on energy efficiency improvements, with $2 T mobilized for clean energy investments by 2030, and the rapid growth in electric vehicle (EV) sales.
Non-OECD nations will be the principal engine of economic growth, accounting for almost 80% of the 2022 – 28 increase in global GDP
–The global post-pandemic economic rebound ended conclusively in 2022, after unprecedented government stimulus and supply chain disruptions caused consumer inflation to soar. This prompted an extraordinary tightening of monetary policy that is set to constrain GDP deep into 2024.
–Global oil demand growth shrivels from 2.4 MMb/d in 2023 to just 400 thousand barrels per day (Mb/d) by 2028 but strong petrochemical demand and consumption growth in emerging economies will more than offset declines in advanced economies.
–Liquified petroleum gas (LPG), ethane and naphtha will account for more than 50% of the rise between 2022 and 2028 and nearly 90% of the increase compared with pre-pandemic levels.
The expansion in global oil demand through 2028 will be powered by faster-growing economies in the developing world – especially in Asia – while oil use in advanced countries contracts
–Around three-quarters of the 2022 – 28 demand increase will come from Asia, with India surpassing China as the main source of growth by 2027. The growth in Asia is initially fueled by China’s reopening and will be more permanently underpinned by India as it consolidates its status as the world’s fastest-growing major economy. Demand growth in China slows markedly from 2024 onwards.
–As in other regions, transport fuels lead the gains in the initial stages of the recovery. Overall demand first exceeds its pre-pandemic level in 2023.
China will continue to account for around one-sixth of world oil demand and half of global oil consumption growth; however, this increase is heavily front loaded: after the massive rebound of post-lockdowns, oil demand growth decelerates massively
–This slowdown corresponds with China’s economy proceeding along a path of structurally lower GDP growth as its era of double-digit economic expansion has now ended. Its present target is 5% per year. Demographics is key, as China’s population declined in 2022 after decades of slowing birth rates.
India is set to overtake China in terms of global YoY oil demand growth in 2027
–The fastest-growing economy in the world, with GDP growth averaging 6.9% for 2024 – 2028, is aided by benign demographics. India surpassed China to become the world’s most populous country in 2023. Although its population growth has been slowing for decades, it will likely not peak until 2065. Further propelled by trends such as urbanization, industrialization, and the emergence of a wealthier middle-class keen for mobility and tourism, Indian oil demand will grow by more than 1 MMb/d between 2022 and 2028.
Neither North America nor Europe will return to their 2019 levels
–North America and Europe, where energy transition policies and efficiency gains will be most pronounced, will spend most of the forecast period in contractionary demand mode. North America will plateau in 2023 at 24.7 MMb/d, and subsequently decline by 240 Mb/d per year on average through 2028. Europe, averaging 14.9 MMb/d in 2022, will be buttressed by the increase in jet fuel consumption through 2024 before starting an overall decline averaging 120 Mb/d annually thereafter. Drivers include higher energy efficiency in the transport sector, penetration of EVs, substitution by other energy sources, teleworking, and less frequent business travel.
Price scenarios based on the brent forward curve see only modest impact on demand
–Besides GDP growth rates, assumptions of future oil prices are a key component of demand estimates, with forecasts sensitive to both the absolute price level and intertemporal changes over the outlook. The high-price scenario would lower 2028 global oil demand by 430 Mb/d. However, this would not cause demand to peak earlier. Conversely, the low-price scenario would raise world oil consumption by 670 Mb/d at the end of the forecasting period.
Capacity building eases as energy transition accelerates
–An expansion in global oil production capacity, dominated by the United States and other producers in the Americas, is set to moderate progressively over the medium term. However, the gains still keep up with the slower pace of projected demand growth over the 2023 – 28 forecast period. The world’s total supply capacity is forecast to post a net increase of 5.9 MMb/d to 111 MMb/d by 2028, but a marked slowdown in US additions sees overall global capacity growth easing annually from an average 1.9 MMb/d in 2022 – 23 to just 300 Mb/d by the end of the forecast.
Global upstream oil and gas investment is on track to increase by an estimated 11% in 2023 to $528 B, compared with $474 B in 2022
–This level of investment would be adequate to meet forecast demand in the period covered by the report. Industry investment in giant projects has slowed sharply amid the shift towards a lower carbon future. Companies are targeting smaller, short-cycle projects and select oil field developments with shorter payback periods in the Americas and Middle East.
–Oil producing countries outside the OPEC+ alliance (non-OPEC+) dominate medium-term capacity expansion plans, with a 5.1 MMb/d supply boost led by the United States, Brazil and Guyana. Saudi Arabia, the United Arab Emirates (UAE) and Iraq lead the capacity building within OPEC+, while African and Asian members struggle with continuing declines. This makes for a net capacity gain of 800 Mb/d from the 23 members in OPEC+ overall.
–The broad deceleration in production capacity building largely reflects the global pivot towards cleaner energy and a corresponding weaker demand outlook. This creates a spare capacity cushion of an average 4.1 MMb/d, concentrated in Saudi Arabia and the UAE, which should help ensure that world markets are adequately supplied.
–The outlook for Russia is clouded by the current geopolitical situation, but the IEA forecasts capacity to fall as sanctions limit its ability to export, forcing some production to be shut in. Longer term, the departure of Western companies in the wake of Russia’s invasion of Ukraine may also curb capacity growth due to project delays stemming from a lack of technology and equipment.
Global oil supply growth concentrated in the Americas
–The outlook for actual supply growth, as opposed to capacity, shows the United States, along with Brazil and Guyana, dominating gains, accounting for 80% of the increase over the forecast period.
US shale matures to a higher return, lower growth trajectory
–A post COVID-19 recovery in US oil production was solidified in 2022 with production up 1.1 MMb/d YoY. The pace of expansion markedly slows from 2024 onwards as producers navigate the energy transition and US light tight oil (LTO), companies struggle with higher costs, increasing decline rates and lower output from new wells drilled. US crude oil production grows to 13.6 MMb/d in 2028, setting new record highs through 2027. The increase is led by LTO, primarily from the Permian Basin. The shale patch has matured financially to a lower growth trajectory as it focuses on disciplined investing, de-leveraging and returning cash to shareholders.
–Despite climate action, concerns of underinvestment and a sharp slowdown in LTO, the United States is still the largest contributor to medium-term supply growth at 2.6 MMb/d by 2028, of which 1.7 MMb/d is crude oil. Natural gas liquids (NGL) production is forecast to rise by 860 Mb/d to 6.7 MMb/d, led by higher ethane exports, as US LTO continues to grow and natural gas production shifts to more liquids-rich plays.
–Investment rates have continued to recover but may never return to pre-COVID levels as improvements in productivity had, in aggregate, been leading to lower recovery costs from 2016 until 2022. Although that may be little consolation for drillers today as they feel the pinch of high spec rig day rates that have increased over 50% in the last year, continued tightness of hydraulic fracking equipment and persistent labor issues, as well as reduced well flow rates.
Refinery activity and trade upended
–A third wave of refinery capacity closures, conversions to biofuel plants and project delays since the pandemic reduced the overhang in global refinery capacity. This, combined with a sharp drop in Chinese oil product exports and an upheaval of Russian trade flows, resulted in tight capacity and record profits for the industry in 2022.
–While net refinery capacity additions of 4.4 MMb/d expected by 2028 outpace demand growth for refined products, contrasting trends among products means that a repeat of the 2022 tightness in middle distillates is possible.
Refining sector on cusp of transformational shift
–Refiners may need to shift their product yields towards middle distillates and petrochemical feedstocks to reflect changing demand patterns. Demand for petroleum-based premium road transport fuels, such as gasoline and diesel, is 1 MMb/d below 2019 levels at the end of the forecast period.
–At the same time, robust petrochemical activity and slower growth in NGLs supply raises demand for refinery-supplied LPG and naphtha. China’s internal policies aimed at reducing emissions could lead to continued volatility in product export volumes and again upend global supply flows and margins in the medium term. China now has the greatest share of installed capacity in the world, after overtaking the United States in 2022. Crucially, product balances are heavily dependent on higher Chinese product exports, especially for diesel, and the middle distillate markets could be very tight by 2028.
–China’s dominance of spare refining capacity and the looming peak in transportation fuel consumption will require refiners to deftly manage their operations to sustain the profitability of their assets and meet oil demand in their markets. They will also need to adjust to a changing crude oil slate amid slower growth in US LTO and the potential for OPEC+ producers to reduce exports of heavier crudes. Those refineries most exposed to these changes face the renewed risk of closure.
Natural Gas Overview
Global gas demand is expected to remain flat in 2023, with higher demand in Asia Pacific and the Middle East offsetting the expected declines in Europe and North America
–In Asia, gas demand is projected to increase by close to 3%, with China and India as the main drivers. Gas demand in China is forecast to increase by over 6% in 2023, supported by a recovery in economic activity and potentially higher gas use in industry.
–Gas demand in Europe’s advanced economies is projected to decline by 5% as rapidly expanding renewables weigh on gas-fired generation. After strong growth in 2022, gas demand in North America is expected to decline by 2% as a result of lower gas use for space heating, power generation and industry.
–The Russian gas industry is facing multiple challenges. If flows to the European Union continue at the levels seen in the first quarter, Russian piped gas deliveries to Europe’s advanced economies would drop by 45% (or over 35 bcm) in 2023 compared with 2022. Following a 90 bcm drop in Russian gas production in 2022, lower exports and muted domestic demand are expected to further reduce Russia’s output by over 50 bcm in 2023.
North American gas demand increased during the winter, but is expected to contract in 2023
–Natural gas consumption in the US saw a 5.3% rise in 2022, driven by the use of natural gas for power generation, stimulated by the retirement of coal-fired power plants and relatively high coal prices, along with lower than average coal stocks.
–North American gas consumption is expected to decrease by about 2.9% in 2023. In the United States, slower economic growth is set to depress gas demand in industry, while an unseasonably mild Q1 reduced gas use in the residential and commercial sectors, weighing on the outlook for the full year. The economic slowdown coupled with the strong expansion of renewables is set to reduce the call on gas-fired power plants, although continued coal-to-gas switching could moderate the overall decline in gas demand for power generation.
European gas demand dropped by a record 55 bcm during the 2022⁄23 heating season
–High gas prices continued to weigh on gas use in industry, while milder weather conditions – together with energy saving measures – depressed distribution network-related demand and gas burn in the power sector.
–Gas-saving measures enacted in public buildings (such as mandatory temperature controls), fuel-switching in rural households (including to biomass, fuel oil and waste), the installation of heat pumps, efficiency gains and behavioral changes all played a critical role in reducing distribution network-related demand.
–In 2021, the share of people unable to heat their homes in the EU stood at 6.9%. This situation is expected to have significantly worsened during the 2022⁄23 winter season.
Asian gas demand came under pressure in 2022; recovery in 2023 is expected to be modest
–Asia’s gas consumption experienced an unprecedented slowdown of 2% in 2022 because of high LNG prices, COVID-related disruption in China and mild weather for most of the year in Northeast Asia. Demand is projected to return to modest growth of around 3% in 2023 due to the lifting of China’s zero-COVID policy.
–China’s coal imports reached record levels during 1Q23; this trend may continue throughout the year supported by the extension of the provisional “zero” import tax policy until the end of 2023 as part of Beijing safeguarding its energy security. The largest coal ports in China are located on the east coast, where some of China’s largest LNG import terminals are based where power producers can switch between coal and natural gas for energy generation to achieve the most cost-effective production.
China gradually recovers its appetite for LNG, although imports are set to remain below their 2021 levels
–China’s LNG imports declined by an unprecedented 20% in 2022, enabling higher LNG deliveries to the European market. China’s LNG import growth recovered to double-digit growth in March 2023, supported by higher domestic gas demand. The country’s LNG inflows are expected to increase by 10 – 15% compared with 2022 while remaining below their 2021 levels.
LNG became effectively a new baseload supply for Europe, accounting for two-third of the region’s gas imports and meeting around one-third of its gas demand through the 2022⁄23 winter season
–After strong growth in 1Q23, OECD Europe’s LNG imports are expected to decline for the remainder of the year amidst lower injection needs and a continued decline in European gas consumption.
Global LNG demand moderated in Q1, expanding by 2% YoY (net of re-exports), with strong growth in Europe
–After months of YoY declines in China’s LNG imports (net of re-exports), volumes rebounded in February, up by 2% on the same month in 2022 according to ICIS LNG Edge. This was the first time that monthly Chinese LNG imports recorded a YoY increase since December 2021. This rebound seemed to be confirmed in March as net LNG imports increased by 11% YoY.
–Although they remained well above historical averages, Asian LNG spot prices fell significantly in 1Q23 from the record levels reached in the summer of 2022. In 1Q23 the average JKM spot price was around $18/MMbtu, compared with $30/MMbtu in the first quarter of 2022 and having reached $70/MMbtu at the peak in August 2022. In March 2023 spot LNG prices in Northeast Asia averaged at $13/MMbtu, encouraging South Asian buyers to return to spot markets via tenders.
–Europe’s net LNG imports rose by 8% (or 3.5 bcm) YoY in 1Q23 as the continent continued to offset declining Russian pipeline gas supplies, mainly by increasing LNG imports and taking advantage of low gas price levels not seen since August 2021. However, LNG inflows into France dropped by 23% YoY in 1Q23 (or 2 bcm) and by 55% YoY in March alone, due to a strike at French LNG terminals. France accounts for around 12% (or 26 million tons per year (MMt/yr)) of Europe’s total regasification capacity. It became the largest importer of LNG in Europe in 2022, with its LNG imports more than doubling on the previous year.
Global LNG supply was up by 2% YoY in 1Q23 measured on an import basis. This was driven by the Asia Pacific region and the Middle East
–In contrast to 1Q22, the United States experienced a moderate 4% (or 1 bcm) decline in LNG exports, explained by the delayed and only partial restart of the Freeport LNG facility following an eight-month outage caused by a fire. Once the Freeport LNG facility fully resumes operation, global LNG trade is expected to increase by 4% in 2023.
–Demand growth will be largely driven by Asia. China’s LNG imports are expected to increase at a rate of 10 – 15% compared with 2022, while remaining below their 2021 levels. After strong growth in 1Q23, OECD Europe’s LNG imports are expected to decline for the remainder of the year amidst lower injection needs and a continued decline in European gas consumption.
LNG became a baseload supply for Europe accounting for two-thirds of gas imports during the 2022⁄23 heating season
–LNG imports are expected to remain broadly flat compared to last year. Following a strong increase in 1Q23, OECD Europe’s LNG inflows are expected to decline through the remainder of the year amidst lower injection needs and a continued decline in European gas consumption.
–While the share of OECD Europe’s gas demand met by Russian piped gas fell to well below 10% in the 2022⁄23 heating season, LNG effectively became a baseload supply for Europe, meeting over one-third of the region’s gas demand over the winter. Russian piped gas exports to OECD Europe fell by an estimated 70% (or 50 bcm) YoY during the 2022⁄23 heating season.
–LNG imports rose by over 25% (or 20 bcm) YoY to reach a record 94 bcm during the 2022⁄23 heating season. LNG flows from the United States increased by 30% (or almost 10 bcm) YoY to account for over 45% of incremental LNG supply into Europe. This further reinforced the position of the United States as Europe’s largest supplier, accounting for over 40% of the region’s total LNG imports and meeting almost 15% of its gas demand.
–Assuming that Russian flows to the European Union continue at their 1Q23 levels, Russian piped gas deliveries to OECD Europe would drop by 45% (or over 35 bcm) in 2023 compared with 2022.
US natural gas output maintains its growth, driven by Permian oil-driven production
–US dry gas production increased by an estimated 4% YoY during October 2022 to March 2023, reaching an average daily level of 100 billion cubic feet (bcf) in the first quarter of 2023 (or a 5.7% YoY increase). Oil driven shale plays increased by close to 8% YoY during October to January. By comparison, natural gas output from gas-driven shale plays was close to stable with a meagre 1.1% YoY increase during October to January.
–Output from the Permian Basin, the largest oil-driven shale play, grew by close to 11% YoY over the same period. This has been supported by strong drilling activity, with an average of close to 430 new wells drilled per month in the Permian during October to January, or a 33% YoY increase, whereas completion rates increased by only 4% YoY over the same period, to a monthly average of 435 wells. January 2023 marked the highest level of drilling activity in the Permian since March 2020, with 437 new wells drilled.
–Total US natural gas production increased by 3.7% in 2022, but this is expected to slow in 2023 due to a combination of continued conservative upstream spending, cost inflation, limited export outlets and an expected decline in domestic demand. This forecast expects US dry gas output to increase by about 2% in 2023, principally supported by associated gas production.
The steep decline in natural gas demand depressed storage withdrawals in Europe and the United States over the 2022⁄23 winter season
–The European Union’s net storage withdrawals stood 38% (or 20 bcm) below their five-year average during the 2022⁄23 heating season and totaled 32 bcm; altogether, net storage withdrawals met around 15% of EU gas demand over the 2022⁄23 heating. These average values hide the critical role of gas storage in ensuring gas supply adequacy during peak days: storage met over 40% of EU gas demand during the coldest winter days in early December 2022 and late January 2023. EU storage sites closed the 2022⁄23 heating season 55% full and with inventory levels standing 67% (or 22 bcm) above their five-year average.
–In the US, storage sites were 80% full at the beginning of November, well aligned with their five-year average. Unseasonably mild weather conditions combined with a strong increase in domestic production reduced storage withdrawals. Net storage withdrawals stood almost 30% (or 15 bcm) below their five-year average during October 2022-March 2023, and met approximately 7% of US gas demand during this period. As a consequence of below average draw on storage, US storage sites closed the 2022⁄23 heating season 43% full, standing 20% (or 12 bcm) above their five-year average.
Gas prices moderated significantly during the 2022⁄23 winter attributable to unseasonably mild weather, lower gas demand and improving supply fundamentals
–In Europe, Title Transfer Facility (TTF) spot prices averaged $23/MMbtu during the 2022⁄23 heating season – almost 30% below the levels experienced in the previous winter. Gas prices on the TTF declined by almost 70% between mid-December 2022 and the end of March 2023.
–In the United States, Henry Hub prices averaged $4/MMbtu in the 2022⁄23 heating season, almost 15% below the levels experienced during the previous winter.
–Forward curves as of the end of April 2023 indicate that TTF is set to average $15/MMbtu in 2023, with Asian spot LNG averaging just below $15/MMbtu and Henry Hub averaging $2.6/MMbtu. The price spread between TTF and Asian spot LNG is expected to tighten significantly in 2023.
Natural gas consumption for electricity in the US during the summer of 2023 is forecasted to average 38 bcf, second most on record behind the 39 bcf/d recorded last year
–High demand will be driven by a decline in coal-fired electricity generation, relatively low natural gas prices, and more overall electricity generation due to warmer-than-normal temperatures.
At the end of April, US natural gas storage inventories totaled 2,114 bcf, 19% more than the five-year average. The forecast for natural gas inventories is expected to increase by 1,648 bcf from the end of April to reach 3,762 bcf at the end of October, 4% more than the five-year average
–The Henry Hub natural gas spot price is forecasted to average $2.35/MMbtu in May and rise to around $3.00/MMbtu in July and August, when power demand peaks.
Energy Transition Overview
The International Renewable Energy Agency’s (IRENA) 1.5°C pathway positions electrification and efficiency as key drivers of the energy transition, enabled by renewables, hydrogen, and sustainable biomass
–This pathway, which requires a massive change in how societies produce and consume energy, would result in a cut of nearly 37 gigatons (Gt) of annual CO2 emissions by 2050.11 Current energy demand forecast do not include substantial additional power needs to support AI.
–Renewables-based electricity is now the cheapest power option in most regions. The global weighted-average levelized cost of electricity from newly commissioned utility-scale solar photovoltaic (PV) projects fell by 85% between 2010 and 2020. The corresponding cost reductions for concentrated solar power (CSP) were 68%; onshore wind, 56%; and offshore wind, 48%.
–Decarbonization of end uses is the next frontier, with many solutions provided through electrification, green hydrogen and the direct use of renewables. Despite good global progress in deployment of renewables in the power sector, the end use sectors have lagged, with industrial processes and domestic heating still heavily reliant on fossil fuels. In the transport sector, oil continues to dominate. In these sectors, deeper penetration of renewables, expanded electrification and improvements in energy efficiency can play a crucial role in alleviating concerns about prices and security of supply.
To fulfil the 1.5°C Scenario the electricity sector will have to be thoroughly decarbonized by mid-century
–A portfolio of projects in generation and grid infrastructure will have to be set up in this decade to begin a pipeline for contracts over the ensuing decades to 2050. What is needed is an annual average of at least 800 GW of new renewable capacity additions each year through 2030, up from around 264 GW added in 2020. The installed generation capacity of renewable power will need to expand to 10,770 GW in 2030 and close to 27,800 GW by 2050, a four-fold and ten-fold increase by 2030 and 2050, respectively, over the 2020 level.
–Decarbonization of end uses is the next frontier, with many solutions provided through electrification, green hydrogen and the direct use of renewables. Despite good global progress in deployment of renewables in the power sector, the end use sectors have lagged, with industrial processes and domestic heating still heavily reliant on fossil gas. In the transport sector, oil continues to dominate. In these sectors, deeper penetration of renewables, expanded electrification and improvements in energy efficiency can play a crucial role in alleviating concerns about prices and security of supply.
–Again, solar PV and wind will lead the way. The installed capacity of solar PV power will exceed 5,200 GW by 2030; wind installations will pass 3,300 GW by 2030. Coal-fired generation will drop sharply over the decade, its share in total electricity generation falling from 37% in 2019 to 11% in 2030, before being phased out entirely by 2050. Natural gas will provide 16% of total electricity needs in 2030, compared with 24% in 2019. Nuclear-fueled generating capacity will hold steady at around 10% of total installed capacity.
All types of renewable power generation capacity must be scaled up in all regions to meet the 1.5°C target
–Asia, North America, and Europe will account for more than 80% of installations by 2030. Asia needs to scale up four times to reach more than 5,400 GW of renewable capacity by 2030, while North America and Europe will have to ramp up installations by around five-fold and three-fold, respectively. The scaling factors for the Middle East and Africa are even greater.
–Wind will be one of the largest generation sources by 2030, supplying 24% of total electricity needs. Asia will almost certainly dominate the global onshore market by 2030, with annual wind additions of 142 GW during this decade. North America and Europe also have considerable potential to promote capacity expansion. In this decade, the 1.5°C pathway to 2050 requires annual installations in these regions of more over 40 GW and 20 GW, respectively. Latin America will have to add 12 GW each year; Oceania/Pacific more than 2 GW; the Middle East and Africa, more than 8 GW.
–The installed capacity of solar PV is expected to increase seven-fold by 2030 (to nearly 5,200 GW) and twenty-fold by 2050 to exceed 14,000 GW. Over the past decade, Asia added 40 GW of solar PV each year – and nearly 80 GW in 2020. With annual additions of 210 GW expected through 2030, Asia will continue to dominate the market, with expansions concentrated in India and China. The region will account for roughly 50% of the globe’s installed solar PV capacity in 2030. Like Asia, Europe and North America doubled their solar PV installations in 2020 over the average levels in the previous decade. The two regions are expected to account for 19% and 14%, respectively, of global solar PV installations by 2030.
Global investment in energy transition technologies, including energy efficiency, reached a record high of $1.3 T in 2022; however, annual investments need to at least quadruple to remain on track to achieve the 1.5°C Scenario in IRENA’s World Energy Transitions Outlook 2023
–Investment in renewable energy was also unprecedented – at $0.5 T – but represented less than one third of the average investment needed each year. Investments are also not flowing at the pace or scale needed to accelerate progress towards universal energy access. Moreover, investments have become further concentrated in specific technologies and uses, and in a small number of countries/regions. More than 50% of the world’s population, mostly residing in developing and emerging countries, received only 15% of global investments in 2022. The disparity in renewable energy financing received by developed versus developing countries has increased significantly over the past six years. For example, the renewable energy investment per capita in Europe and North America (excluding Mexico) was almost 23 times higher than that in Sub-Saharan Africa in 2015. In 2021, investment per capita in Europe was 41 times that in Sub-Saharan Africa, and in North America it was 57 times more.
Achieving an energy transition in line with the 1.5°C Scenario requires the redirection of $1 T per year from fossil fuels to energy-transition-related technologies; but fossil fuel investments are still on the rise
–Investment in new oil and gas development is estimated to average $570 B annually until 2030.
–Fossil fuel companies based in emerging markets and developing economies have continued to attract substantial volumes of financing. Between 2016 and 2022, their outstanding debt rose by 400% for coal and 225% for oil and gas, despite the need to align investments with the goals outlined in the Paris Agreement. In Africa, capital expenditures for oil and gas exploration rose from $3.4 B in 2020 to $5.1 B in 2022. Fossil fuel subsidies continue, and in 2020, Europe was the region providing the most subsidies, which were expanded during the early 2022 natural gas price spike.
Although renewable energy investments are on the rise globally, they are increasingly focused in certain regions
–China leads in East Asia and Pacific region aided by a suite of policies including tax exemptions have driven investments in solar and wind, putting the country on track to meeting the targets set out in the 14th Five-Year Plan.
–North America excluding Mexico attracted the second-largest share of investment in 2022, mainly driven by the production tax credit in the United States. The 2022 Inflation Reduction Act (IRA) – encompassing new tax credits, $30 B in grants and loans for clean energy generation and storage, and $60 B in support of manufacturing of low-carbon components – is expected to attract $114 B investment by 2031.
–Europe’s growth in renewable investments is driven by its net-zero commitments and extensive policies such as those proposed in the Green Deal Industrial Plan for the Net-Zero Age, which looks to mobilize €225 B in loans from its existing Recovery and Resilience Facility, and an additional €20 B in grants.
Electricity generation from renewable sources is forecasted to rise from 22% in 2022 to 23% in 2023 and to 26% in 2024
–Lower operating costs support a dispatch advantage over fossil fuel-fired power plants.
–Coal use reduction driven by generating plant retirements (11 GW scheduled in 2023), low natural gas prices, and more renewable generation.
–The IRA and other government policies are sharply expanding efforts to decarbonize electric gas supply.
Nuclear power has avoided about 66 Gt of CO2 emissions over the past 50 years, concentrated in long-time market leaders
–Without nuclear power, power sector CO2 emissions in advanced economies would have been 20% higher over the past 50 years, led by the United States and European Union. Emerging market and developing economies have recently seen strong growth in nuclear power, led by China and India, helping to cut some 9 Gt of emissions to date.
–In 2021 nuclear power capacity declined by almost 3 GW globally, as newly completed reactors were not able to compensate for over 8 GW of retirements. Emerging market and developing economies accounted for all the new capacity while the majority of these permanent shutdowns were in Germany, the United Kingdom and the United States, which are all G7 members.
–To get on track with the Net Zero Scenario, global nuclear capacity would need to expand by about 10 GW per year to 2030. Prioritizing lifetime extensions in G7 members would bolster the low-emissions foundation in place and make the most of new nuclear capacity.
–The ambitions reflected in net zero targets have encouraged innovation in nuclear power technologies, such as small modular reactors (SMRs), which have a smaller size of under 300 MW per reactor, down to 10 MW. SMRs hold the promise of being more affordable, and easier and faster to build than conventional large reactors. Close to 70 designs are currently under development. SMRs can potentially be factory-built and transported to the final location, shortening project timelines and potentially reducing construction risk and financing costs. As power systems decarbonize and solar and wind shares increase, SMRs could become a keyway to meet rising flexibility needs in power generation. They can also be used for heat and hydrogen production.
1) EIA – Short-Term Energy Outlook – May 2023
2) Thomson Reuters
3) IEA – Oil Market Report – May 2023
4) IEA – Gas Market Report – Q2 2023
5) IEA – Oil 2023 – Analysis and Forecast to 2028 – June 2023
6) American Oil and Gas Reporter
7) EIA – Drilling Productivity Report – May 15, 2023
8) Reuters – Global refiners falter in efforts to keep up with demand
9) EIA – Petroleum & Other Liquids
10) IEA – Energy Prices – Monthly Oil Prices Excerpt
11) IRENA – World Energy Transitions Outlook 2022: 1.5oC Pathway
12) IRENA – International Renewable Energy Agency – Renewable Energy Finance 2023
13) IEA – Nuclear Electricity – September 2022