Guy Raz asks S&P Global Platts about the Future of Energy

Voluntary carbon markets have seen significant growth in recent years and are expected to surge in the years ahead. But they have traditionally been seen as opaque, complex and niche. That is rapidly changing as a large range of companies start to engage with them.

In the latest Platts Future Energy podcast, Jonty Rushforth is joined by Paula Vanlaningham and Jeff Berman to discuss the ‘beauty’ of carbon credit markets.

In response to industry interest, S&P Global Platts will launch a daily report: Carbon Markets Daily, from Feb. 14, 2022.

This daily report will cover the latest insights and analysis of market fundamentals, trends and factors driving carbon markets. It will also deliver a comprehensive array of price assessments and indices, providing greater transparency in the voluntary carbon credit markets.

The Carbon Markets Daily report will be published on Platts Dimensions Pro, and on Energy Transition Alert page 2000 and Carbon Markets Alert page 2000.

Please send all feedback, queries and comments to support@platts.com. For written comments, please provide a clear indication if comments are not intended for publication by Platts for public viewing.

Platts will consider all comments received and will make comments not marked as confidential available upon request.

LEF Conversations:
The future for voluntary carbon markets
with Beth Evans

Demand for carbon credits and rapidly reopening economies have seen a surge in the value of a basket of S&P Global Platts price assessments this year.

A deal in line with the UN’s ambition to keep 1.5 degrees Celsius global warming within reach will increase demand for a range of low-carbon resources from hydrogen to battery metals, bringing the cost of the energy transition into sharper focus.

Platts Analytics’ Reference Case assumes an unprecedented amount of clean energy adoption, but it still falls short of achieving a Two Degree target, illustrating how difficult the challenge of preventing climate change is.

Click for full-size infographic

China’s efforts to decarbonize its power sector have triggered intense debate about the role of its existing fossil fuel-based electricity system and the extent to which the system will have to be recalibrated.

There is general consensus that an electricity supply chain based predominantly on renewables will have to be fundamentally different from one based on fossil fuels, mainly to handle intermittency issues and introduce market-based mechanisms for both power and carbon trading.

The debate, however, is largely around securing a smooth energy transition, ensuring stable power supply and the pace and criteria for decommissioning coal-fired plants.

The recent energy crisis exacerbated concerns around indiscriminate phasing down of coal, the economic impact of high energy prices and volatility if electricity prices are deregulated in a market-based system.

Chinese policy makers and top power utilities have adjusted their stance on coal-fired power generation after the crisis and called for a more realistic assessment of the energy transition instead of impulsive plant closures that endanger energy security.

The reassessment includes making room for gas in the energy transition as a bridging fuel with half the emissions footprint, as well as keeping coal plants as back-up power sources instead of complete decommissioning, until technologies and costs to solve the intermittency of renewables meet a certain threshold.

Chen Zongfa, Deputy General Counsel with China Huadian Corp., one of China’s largest state-owned generation utilities, said a previous estimate of coal-fired power peaking within 1,200 GW had been raised to 1,250 to 1,300 GW.

“Like it or not, we still cannot get rid of coal-fired power in a relatively long period, because we need it as the ‘ballast’ that ensures energy security,” said Xu Xiaodong, senior consultant with government-backed think tank China Electric Power Planning & Engineering Institute.

Meanwhile, China’s carbon market is gathering steam and could cover two or three more sectors as early as 2022, in addition to the power sector. The implies a faster-than-expected rollout of China’s carbon market for the eight sectors identified including refining and petrochemicals, chemicals, building materials, steel, nonferrous metals, aviation and paper.

China’s largest industrial groups, energy companies and financial institutions are rapidly building internal systems for the measurement and reporting of greenhouse gas emissions, and developing capabilities for trading carbon credits.

Several of China’s largest oil companies, manufacturing companies and power utilities had announced net-zero plans ahead of Beijing’s official announcement of carbon neutrality target by 2060. Before the launch of the national carbon market in 2021, Chinese exchanges were already running pilot programs to test carbon trading.

Companies in China’s most emission-intensive sectors are laying out their climate and carbon strategies due to pull and push factors that include domestic climate policy, and demands from international customers for proof of green electricity usage.

China’s carbon market will see a few major trends – tighter supply of allowances, the introduction of institutional market participants, and rapid growth in the voluntary emission reduction market called Chinese Certified Emissions Reductions, possibly faster than the compliance market, which is driven by regulatory policies.

Key targets in China’s 2030 carbon peaking action plan

The decarbonization process clearly wont be limited to the power sector, with the refining and petrochemical sector expected to be covered as early as 2022-2023, in a move that will bring China’s national oil companies — which are some of the world’s largest oil and gas producers, importers, refiners and distributors — into the carbon fold, and cover a large segment of the petroleum supply chain.

The action plan to peak carbon emissions before 2030 announced by the State Council, the country’s top executive body, on Oct. 26, outlined measures for major sectors on the path towards carbon neutrality.

It includes formalization of curbs on coal consumption growth by 2030, capping oil refining capacity at around 20 million b/d by 2025, achieving peak oil consumption for land transportation by 2030 and including hard-to-abate industries like steel and metals for the first time

Meanwhile, China is rapidly building up its manufacturing capacity for hydrogen electrolyzers, which is expected to reach 1.5-2.5 GW in 2022, to cater to increasing orders from both domestic and overseas customers.

Several private sector companies are formulating plans to leverage China’s manufacturing expertise to lower the cost of equipment used in the hydrogen supply chain and produce electrolyzers, which crack the water molecule, at less than half of the cost of overseas manufacturers, the executives said.

Bringing down supply chain costs will help commercialize large-scale green hydrogen production and Chinese manufacturers are keen on replicating their dominance in global solar panel production in the race for hydrogen.

China’s Sinopec has started the construction of the world’s biggest solar-based green hydrogen plant, a 20,000 mt/year capacity project in Kuqa, Xinjiang Uyghur Autonomous Regions and is expected to commission the plant and start production in June 2023.

This will be one of Sinopec’s four green hydrogen projects that are in the pipeline. China has been boosting its hydrogen development plans and Beijing is expected to release it hydrogen industry development plan soon.

China’s hydrogen-powered fuel cell electric vehicles are expected to be cost-competitive by 2030 with conventional vehicles powered by gasoline or gasoil, in terms of both the purchasing price and the fuel cost.

Fuel distributor Sinopec Marketing expects that by 2025 green hydrogen will cost lower than Yuan 30/kg (approximately $4.69/kg) and hydrogen-powered trucks’ fuel cost will be competitive against gasoil-fueled ones. Current hydrogen fuel costs range around Yuan 40-70/kg (approximately $6-11/kg), which is still significantly higher compared with diesel and petroleum costs.

Chinese policymakers already consider the energy transition to be as important as its emergence from economic isolation and the opening up of the Chinese economy, and expect the green economy to drive the next industrial revolution.

China’s national carbon market will move into a phase of expansion and capacity building in 2022, which will widen the scope of the emissions trading scheme to cover more sectors, as well as develop carbon trading infrastructure and capabilities across provinces, companies and exchanges.

The development path is important to put a price on carbon for most of China’s energy intensive industries, and to strengthen the measurement and implementation mechanism for what is currently a very nascent carbon market.

The urgency of climate goals means that China may not have the decades needed for its carbon market to fully mature like the European ETS, that took many years to evolve after being launched in 2005.

The key factors to look out for will be the introduction of emissions measurement frameworks in new sectors, the re-launch of China’s domestic voluntary carbon market, new regulations to strengthen implementation and new carbon-related products in increasingly sophisticated Chinese exchanges.

The challenge will be to balance top-down policymaking from Beijing, with the need to create a liquid carbon marketplace and price discovery mechanisms, while navigating a complex structure of provincial governments and state-owned enterprises with their own priorities.

New Sectors

Building materials, non-ferrous metals, and oil refining could be the next industrial sectors to be enrolled in China’s national emission trading scheme. China’s environment ministry had identified eight more sectors to be enrolled by the end of 2025, in addition to the power sector that it currently covers, which also includes steel, chemicals, aviation, and paper.

“We now need to expand the carbon market’s coverage as fast as possible. There’s a plan in place to enroll the non-ferrous metal and building material sectors next year [in 2022],” Lai Xiaoming, chairman of the Shanghai Environment and Energy Exchange, or SEEE, said at the 2021 International Finance Forum on Dec. 5. SEEE hosts the online trading platform for China’s carbon market.

The refining and petrochemical sector is likely to be enrolled between 2022 and 2023, Zhang Gao, vice president of Hubei-based Carbon Emission Allowance Registration and Settlement Co, said at an event in November. The company hosts the national carbon market’s registration and settlement systems.

Power generation accounts for around 40% of China’s carbon emissions; 15.2% comes from steel, 13.16% from building materials, 8.16% from refining, petrochemical and chemicals, 1.17% from non-ferrous metals, 0.71% from aviation and 0.65% from paper, according to think tank SinoCarbon’s data.

Roman Kramarchuk, head of Future Energy Analytics at S&P Global Platts, said a large jump in China’s power demand alone means that by end-2022, covered emissions are expected to be over 10% higher than in 2019.

“China’s carbon trading program by its design isn’t really capping emissions and showing reductions,” Kramarchuk said, adding that details implemented in other sectors “would certainly drive the value of existing allowances.”

Carbon market evolution

China is expected to restart its market for China Certified Emission Reductions, which are domestically certified carbon credits that can be sold to voluntary buyers as well as companies enrolled in the compliance market to offset up to 5% of their surplus emissions.

The State Council announced on Nov. 26 that Beijing Green Exchange will host the national trading platform of CCERs and that the Beijing exchange will also be open to global investors, and upgraded to be China’s green financing hub.

The relaunch of China’s voluntary carbon credits, and the development of new carbon products at exchanges like China Beijing Environment Exchange, China Emissions Exchange Guangzhou and the SEEE, will be important developments to watch out for in 2022.

The wider objective is to pave the way for institutional investors to play a role in boosting market size and enhancing carbon market liquidity. China’s carbon market has so far been dominated by state-owned companies’ bulk transactions to meet emission targets with limited actual trading through listed transactions.

“China’s environment ministry, which manages China’s carbon markets, also realizes the power of institutional investors, and we have a plan to get them enrolled [in the national carbon market] as soon as possible,” SEEE’s Lai said.

“We hope auctions can be introduced in China’s carbon market, which encourages more participation and creates a stronger market signal that we are taking decarbonization more seriously,” Zhao Xiaolu, climate director at the US non-profit organization Environmental Defense Fund, said at a recent industry event.

Recently, SinoCarbon’s director of finance and international business Chen Zhibin said the central government has not come up with an emissions cap for China and that there are no annual targets for emission reduction quantities. Also, sector-level emission targets have yet to be proposed.

“To make the carbon market more powerful, carbon emission allowance allocation needs to be tightened to make other decarbonization policies more effective,” he said.

It remains to be seen how China’s carbon market will tackle these challenges, and global pressures from COP26 and cross-border carbon trading policies like CBAM, or Carbon Border Adjustment Mechanism, will influence how the market shapes up in 2022.

Russia plans to leverage its large natural gas reserves, existing infrastructure, and cooperation with foreign partners to take a major stake in the global hydrogen market.

Targeting 20% of market share by 2030, Russia is set to ramp up production over the next five years.

S&P Global Platts Analytics forecasts Russian hydrogen production at 3.4 million mt in ammonia and 2.7 million mt in refining in 2021. It expects these volumes to increase to 3.8 million mt and 3.1 million mt, respectively, by 2025.

Russia’s export plans include shipments of 2 million mt/year by 2035, and 15 million-50 million mt/year by 2050. The end-goal of 50 million mt/year would be equivalent to around 160 Bcm/year of natural gas.

“This would in essence replace all natural gas exports from Russia to Europe today with hydrogen,” Platts Analytics said.

In August, the Russian government approved a roadmap for hydrogen development, which is becoming an increasingly important government priority. At the Russian Energy Week in mid-October, President Vladimir Putin said that hydrogen and ammonia will become increasingly important in global energy markets.

“Russia has the scientific, resource, and logistics capabilities to take a significant share in these promising markets,” he said. Russian Prime Minister Mikhail Mishustin said in mid-October that Russia will spend over Rb9 billion, equivalent to around $127 million, to develop technology for the production, storage and transportation of hydrogen over the next three years.

Russia plans to produce hydrogen from nuclear and renewable sources, but with Russia’s vast gas reserves, analysts expect natural gas to play the biggest role in hydrogen production.

“Russia sees hydrogen as a partial substitute for hydrocarbons in terms of what it can offer to market,” Vladimir Drebentsov, chief advisor to the director general of the Russian Energy Agency (RosEnergo), said Oct. 26, during a Chatham House webinar on Russia’s approach to climate change.

During a government meeting on hydrogen in mid-October, Russian Deputy Prime Minister Alexander Novak said that hydrogen should be integrated into Russia’s energy and low-carbon development strategies, as once a global hydrogen market emerges, it will compete with hydrocarbons markets.

Price assessments

These plans are being developed at a time when production prices for blue hydrogen continue to be lower than green in Europe.

Production prices for hydrogen produced from gas with carbon capture and storage, including capital expenditures and carbon, averaged Eur2.932/ kg in January to October 2021, according to Platts assessments.

The cost assessment for hydrogen produced from renewables using electrolysis was higher at Eur6.904/kg during the same period.

“In Platts’ models, SMR with CCS generally uses a lower-cost input [natural gas] than electrolysis hydrogen [grid electricity], leading to lower production costs for blue hydrogen than green hydrogen,” Brian Murphy, Platts senior analyst, hydrogen and low carbon fuels, said.

Climate concerns

Russia is targeting Europe and Asia as key export markets. It plans to create at least three hydrogen clusters – in the northwest for European exports, the east for Asian supplies, and the Arctic for domestic consumption and potential exports.

Russia’s hydrogen export plans to some extent depend on how hydrogen demand develops among European customers for blue hydrogen, as they may prioritize green hydrogen in light of EU climate legislation.

“With its vast gas reserves, Russia has a large potential for blue hydrogen [with carbon capture, utilization and storage], but export potential for blue hydrogen will realistically depend on whether other countries treat it as sufficiently environmentally friendly,” said Elena Anankina, senior director (analytics), Ratings and Infrastructure, S&P Global Ratings.

Russia is investing in ways to reduce the carbon impact of blue hydrogen, including carbon capture and the use of pyrolysis in production, as well as shipping gas for hydrogen production to facilities with good access to power generated from renewables.

The Russian energy ministry argues that with carbon capture, up to 90% of emissions from gas-based hydrogen can be eliminated. Anankina added that there is some potential for low-carbon hydrogen projects in Russia, including in the Murmansk region, using wind and nuclear power.

Russian domestic consumption is less sensitive to concerns over carbon emissions, with projects including hydrogen buses and power generation using a hydrogen and methane mix.

Foreign cooperation

Hydrogen is also becoming a key element in talks on future cooperation with foreign partners, including partners in Asia, Western Europe, the Middle East and Australia.

Russia and Germany have signed a deal on potential cooperation on sustainable energy, including hydrogen.

Officials from western companies with long-standing involvement in the Russian energy sector have also expressed interest in joining hydrogen projects in Russia, including BP and TotalEnergies.

Meanwhile, Japan has announced that it will work with Russia’s Rosneft and Novatek on lower carbon projects, including hydrogen and ammonia, as well as CCS.

Russian officials have also held talks with their counterparts from the UAE and Saudi Arabia on hydrogen cooperation.

These plans will develop in the context of existing energy cooperation, with factors including climate legislation, sanctions, and the OPEC+ crude production agreement likely to affect the success and long-term viability of these projects.

A version of this piece appeared in the December edition of Insight Magazine. Download the full magazine here.

S&P Global Platts has launched new daily carbon-neutral assessments of hydrogen in several key markets around the world, from Dec. 9.

The assessments build upon cost-based prices for hydrogen in key production hubs around North America, Europe and the Asia-Pacific region. Platts CNH prices reflect the value of hydrogen as a molecule as it leaves the production facility.

The new prices reflect the market value of hydrogen in which emissions have been, in order of priority: avoided where possible through the use of low emissions generation, removed through the use of carbon capture and storage, and offset through the use of carbon credits or equivalent instruments

In addition to spot market activity, power purchase agreements and hydrogen offtake agreements may be considered for assessment purposes, but normalized for terms, periods and other factors.

In the absence of trading activity, Platts considers the cost of production factors, which will provide baseline inputs in the absence of market activity. These costs incorporate renewable power prices and carbon capture costs with any remaining accounted emissions offset using relevant carbon instruments. Platts accounts for carbon offset costs using Platts CRC removals-based carbon credits, which reflect the most competitive carbon credit assessments for projects that remove GHG emissions, as well as California Carbon Allowance and EU Emissions Allowance prices where relevant.

Platts publishes daily assessments in six locations, which have the greatest potential to become hydrogen hubs as global markets emerge: California and the US Gulf Coast (Texas and Louisiana) in the Americas, the Netherlands in Northwest Europe, Saudi Arabia in the Middle East, and Japan and Western Australia in the Asia-Pacific region.

Assessments are measured in $/kg, $/MMBtu, Eur/kg and Eur/MMBtu.

Specifications include: Minimum lot size of 20,000 kg, 99.99% purity, for prompt delivery in the calendar month following the trading date, ex-works. Trades for other terms, quantities and purity levels may be normalized to this basis for assessment purposes.

The prices are published on Platts Dimensions Pro and under the Market Data Category: HY.

The published prices are as following:

Carbon Neutral Hydrogen Ex Works Australia $/MMBtu HYAUD00

Carbon Neutral Hydrogen Ex Works Australia $/MMBtu MAvg HYAUD03

Carbon Neutral Hydrogen Ex Works Australia $/kg HYAUC00

Carbon Neutral Hydrogen Ex Works Australia $/kg MAvg HYAUC03

Carbon Neutral Hydrogen Ex Works California $/MMBtu HYCAB00

Carbon Neutral Hydrogen Ex Works California $/MMBtu MAvg HYCAB03

Carbon Neutral Hydrogen Ex Works California $/kg HYCAA00

Carbon Neutral Hydrogen Ex Works California $/kg MAvg HYCAA03

Carbon Neutral Hydrogen Ex Works Far East Asia $/MMBtu HYFED00

Carbon Neutral Hydrogen Ex Works Far East Asia $/MMBtu MAvg HYFED03

Carbon Neutral Hydrogen Ex Works Far East Asia $/kg HYFEC00

Carbon Neutral Hydrogen Ex Works Far East Asia $/kg MAvg HYFEC03

Carbon Neutral Hydrogen Ex Works Middle East $/MMBtu HYMEB00

Carbon Neutral Hydrogen Ex Works Middle East $/MMBtu MAvg HYMEB03

Carbon Neutral Hydrogen Ex Works Middle East $/kg HYMEA00

Carbon Neutral Hydrogen Ex Works Middle East $/kg MAvg HYMEA03

Carbon Neutral Hydrogen Ex Works North West Europe Eur/MMBtu HYNWB00

Carbon Neutral Hydrogen Ex Works North West Europe Eur/MMBtu MAvg HYNWB03

Carbon Neutral Hydrogen Ex Works North West Europe Eur/kg HYNWA00

Carbon Neutral Hydrogen Ex Works North West Europe Eur/kg MAvg HYNWA03

Carbon Neutral Hydrogen Ex Works US Gulf Coast $/MMBtu HYUSB00

Carbon Neutral Hydrogen Ex Works US Gulf Coast $/MMBtu MAvg HYUSB03

Carbon Neutral Hydrogen Ex Works US Gulf Coast $/kg HYUSA00

Carbon Neutral Hydrogen Ex Works US Gulf Coast $/kg MAvg HYUSA03

Please send all questions and comments to hydrogenassessments@spglobal.com and pricegroup@spglobal.com. For written comments, please provide a clear indication if comments are not intended for publication by Platts for public viewing. Platts will consider all comments received and will make comments not marked as confidential available upon request.

Japan’s cargo ship Suiso Frontier is set to arrive at Australian state Victoria Jan. 20 and is expected to sail back with the world’s first liquified hydrogen in the week starting Jan. 23, a spokesperson of the hydrogen project Hydrogen Energy Supply Chain Project said, in what would be a significant development for transporting hydrogen for commercial use.

A source close to the HESC project also said that the Suiso Frontier is arriving at Hastings Jan. 20. The Suiso Frontier, which had been estimated to arrive Hastings Jan. 19, was moored in South Australia and Victoria at 0627 GMT Jan. 20, according to Platts cFlow trade-flow analytics software.

Suiso Frontier left the liquefied hydrogen loading terminal Hy touch Kobe on Dec. 24 destined for port of Hastings in Victoria. After various field tests, it will return to Kobe loaded with liquefied hydrogen generated from brown coal in the middle of February 2022, according to a statement from Hydrogen Energy Supply-chain Technology Research Association, or HySTRA, in December.

HySTRA, whose members are Electric Power Development or J-POWER, Shell Japan, Iwatani, Kawasaki Heavy Industries, or KHI, Marubeni, ENEOS and Kawasaki Kisen Kaisha, is the Japan-funded portion of the HESC pilot phase.

The Australia-funded portion of the HESC project is coordinated by Hydrogen Engineering Australia, or HEA, a consortium comprised of KHI, J-POWER, Iwatani, Marubeni, AGL and Sumitomo, with HEA being a 100% subsidiary of KHI. The Australian and Victorian Governments are providing funds to the Australian portion.

The HESC project aims to produce and transport clean liquid hydrogen from Australia’s Latrobe Valley and the key objective of the pilot project is to demonstrate an end-to-end supply chain with Japan, that would cover a one-way distance of 9,000 km. It involves brown coal gasification and hydrogen refining in the Latrobe Valley and hydrogen liquefaction and storage of liquefied hydrogen at the port of Hastings.

The 8,000 gross tonnes Suiso Frontier, the world’s first liquefied hydrogen carrier with a cargo loading capacity of 1,250 cu m, is using one of the two storage tanks for carrying some 75 mt of liquefied hydrogen for this transport, a source told S&P Global Platts in December.

Suiso Frontier has been built by KHI.

Platts assessed Victoria hydrogen produced via lignite gasification, with CCS, including CAPEX at $2.58/kg Jan. 19, up 3.2% from Dec. 20.

Japan hydrogen produced via SMR without CCS, including capex was assessed at $4.12/kg Jan. 19, down 42.7% from Dec. 20.

At the recent S&P Global Platts Hydrogen Infrastructure event, EU Commissioner for Energy Kadri Simson discussed “The Role of Policy in Defining a Future for Hydrogen in Europe”.

A strong project pipeline largely driven by capacity additions in China, Europe, and the US will likely see global annual wind generation move from about 1,500 TWh in 2020 to over 3,000 TWh within the next decade, surpassing nuclear by 2028 to become the second largest non-emitting source of generation after hydro.

Wind generation currently accounts for 6% of the global mix but with ever more ambitious climate pledges being announced and floating offshore wind potentially able to unlock additional markets, generation is expected to increase to 11% of the global mix by 2030. Conversely, the mixed attitude towards nuclear is hampering growth, which is expected to lead to its share falling from 10% today to 9% by the end of the decade.

In the near-term, the majority of wind capacity growth will be onshore. In China, the largest market, recent onshore installation rates have shown resilience to the pressures of rising materials costs with robust additions continuing following the expiry of the feed-in tariff at the end of 2020. We expect strong growth to continue going forward in China, although a key risk post-2021 will be the level of provincial financial support available. In contrast, European onshore capacity growth is expected to slow through to 2026 reflecting permitting challenges and local opposition to developments, but the repowering of existing projects could potentially add additional capacity in the future.

Over the longer term the global offshore wind sector is expected to grow substantially. Annual installations could reach more than 15 GW by 2026 and cumulative installed capacity is estimated to surpass 100 GW in the same year. Europe and China are expected to remain the major markets for new offshore additions, although from 2024 other countries such as South Korea and the US will begin to enter the market. Most of the near-term upcoming offshore projects will have fixed foundations, although the development of floating technology will help open additional markets with deeper offshore coastal areas, such as Japan.

However, in markets where renewables are expected to play a major role in the future energy mix, such as Europe, plants that rely on markets for their revenues may see a risk of revenue erosion over the longer term. As renewable energies further penetrate supply, they could begin to establish price-setting roles that could undermine power prices. Platts Analytics forecast that as renewable build out continues, power prices will begin to fall across major Western European markets, however we expect to see less revenue erosion risk for wind compared to other competing technologies such as solar PV. Platts Analytics expects that wind capture prices will remain generally close to 100% of baseload prices for the largest Western European markets through to 2030. These capture prices are likely to be buoyed by any increases in wind-powered green hydrogen production and any future electrification of heating, which will weight power demand to winter when wind load factors are higher.

LAUNCH REPORT

Wind and solar capacity additions in 2021 hit close to the all-time high record set in 2020 and accounted for the vast majority of global power generation investments. Solar in particular continued to outshine other low-carbon sources with just over 115 GW of new installed capacity worldwide in 2021 compared to 100 GW of wind. Although slightly lower than the previous year due to softer than expected additions in China, Western Europe and Japan, solar PV is forecasted to widen the lead over wind and other low-carbon technologies in the next five years, surpassing the landmark 1 TW global total installed capacity between 2022 and 2023. Government support through auction mechanisms and a continued decline in costs despite short term shocks is likely to carry this trend through to the end of the decade. Much of this new capacity will come from a handful of key markets, namely China, India, Europe and the US.

China remains the largest market globally, both in terms of installed capacity and annual additions. Although installations slowed in 2021 following a record 2020, they have shown resilience to rising materials costs, which makes us confident China’s additions will remain in the 40-50 GW/year over the next 5 years. Distributed generation in particular is rapidly becoming the rising star of Chinese solar, with land becoming more limited and questions arising about the longevity of subsidies for rooftop systems.

In India, following a significant slowdown attributed to the COVID-19 pandemic, the sector has bounced back to just over 7 GW of additions by the end of 2021, further set to increase to about 10 GW per year from 2022 onwards. Rising indigenous production and oversubscribed solar auctions indicate a large potential pipeline of projects, particularly as part of hybrid or 24/7 auctions.

EU10 solar PV additions are set to continue to dominate renewable capacity growth, averaging about 20 GW of yearly buildup out to 2030 and surpassing total installed wind capacity as early as 2023. However, we expect annual solar additions to peak by 2030, driven largely by competitive auctions with price guarantees followed by slow withdrawal offixed tariffs. Despite the promising outlook, large revenue cannibalization risks are on the horizon for solar PV in Europe, even after a significant ramp up in battery capacity and flexibility options.

In the US, we assume solar PV additions will average roughly 30 GW/year, but the extension and restoration of tax credits as well as eligibility for storage will further shape additions in coming years. The fate of the Build Back Better bill and trade disputes over module imports in particular remain the main sources of uncertainty for the US solar industry.

Even with these bullish outlooks for key markets and annual solar additions expected to exceed 150 GW by 2026, Platts Analytics anticipates solar generation growth will meet only a quarter of global power demand growth over the upcoming decade. A recovery in industrial demand as well as a rise in electrification across multiple sectors is expected to push power demand growth over 670 GW by 2030. This means that even including other low-carbon additions like wind and hydro, about a quarter of additional generation will still have to come from new coal and natural gas. In the context of emission reduction targets and coal phaseout pledges such as those made in COP26, the low-carbon buildup may be lacking even at its current record pace to ensure net-zero emissions by mid-century.

The growth in renewable generation is the central plank in meeting Europe’s 2050 carbon net-zero targets, but as more wind and solar assets come on line and as more are exposed to merchant prices, the price cannibalization risk for these assets increases.

In the latest episode of the Platts Future Energy podcast, our experts take a closer look at both Platts Historical Renewable Capture price index and Platts Analytics’ new European wind and solar capture price forecasts. They discuss how these innovations will track the level of price cannibalization as it evolves in Europe’s largest power markets and what the outlook is for the relative profitability of merchant renewables in the coming years.

S&P Global Platts Renewable Capture Price indices provide the market with an independent and transparent view on how merchant renewable revenues are changing through time as the energy transition accelerates and wind and solar plants make up a greater share of the generation mix.