Power Sector

Abstract

The global shift towards low carbon energy faces the dual challenges of continually growing energy consumption and carbon emission reduction. The power system is transforming from fossil fuels to low-carbon non-fossil fuels as the main energy source of the power system, which will be instrumental to the goal of energy transition.

The global shift towards low carbon energy faces the dual challenges of continually growing energy consumption and carbon emission reduction [1]. The power system is transforming from fossil fuels to low-carbon non-fossil fuels as the main energy source of the power system, which will be instrumental to the goal of energy transition. In terms of future demand, the proportion of electric power is expected to grow in global energy consumption, with a 90% increase by 2040 from now, and one fifth of the growth will come from China [2]. On the supply side, the trend of clean electricity will continue with renewables and nuclear energy representing the mainstream of power generation, replacing fossil energy. The future of thermal power plants will, in large part, hinge on the cost and scale of application of carbon capture and storage (CCS); while for the power grid, the large share of intermittent solar and wind power will bring unprecedented challenges in stability and flexibility for the power system. From the standpoint of end users, on the other hand, the electrification rate will continue to rise in final energy consumption, replacing fossil fuels [1][2][3].

The power sector is the key of the decarbonization of China’s energy system. With the world’s largest power generation sector, China produced nearly one fourth of the world’s power in 2018 with its power sector consuming approximately 50% of the country’s coal, and carbon emissions from power generation and heating supply accounts for around 40% of energy-related carbon emissions in China. Various studies have indicated that the power sector needs to take the lead in carbon neutrality and even negative emission by the middle of the century. The core and biggest challenge in China’s power sector transition lies in its massive coal-fired power units, which made up 48% of the world’s total installed coal-fired capacity in 2018. These power units in service are technically advanced with a short service life of 12 years on average, employing nearly 4 million people, including those in the upstream coal industry. Coal power and coal-related industries are major contributors to local economy. For example, coal-related industries accounted for 17% of GDP of Shanxi province in 2018. It is foreseeable that the decarbonization of China’s power industry will have a far-reaching impact on the society, economy and technology and so on. Therefore, it is urgent to find the pathway that is technically feasible, safe and affordable under the temperature rise control targets of 2°C and 1.5℃ set by the Paris Agreement.

4.1 Power Demand Forecasting and Research Methods

Electric power consumption in China totaled 6.85 trillion kWh in 2018. From the supply side, 69.1% of this came from fossil fuels and 30.9% from non-fossil fuels, of which 26.7% was from renewables and 4.2% from nuclear power. On the consumption side, the share of electric power in end user energy consumption is on a constant rise in recent years, reaching 25.5% in 2018 with an average annual increase of 0.65% since 2015 [4]. By end-use consumption mix, the industrial sector remains the biggest electric power consumer, which, despite the fluctuations in recent years, comprised 70.4% in the total end user electric power consumption in 2017; a growing momentum is observed in the proportion of the building sector in end user power consumption in recent years, reaching 27.8% whereas the agricultural sector took up a mere 1.8%. In future, the level of electrification of end-use sectors is expected to significantly increase in China, with electric power gradually becoming the most important component in terminal energy mix.

4.1.1 End-Use Sectors’ Demand Forecast

Under China’s long-term deep decarbonization strategy, CO₂ emissions will peak around 2030, and energy consumption will gradually enter and remain at the plateau from 2035 to 2050 under different scenarios. During the plateau period, total energy consumption tends to stabilize, and economic and social development is gradually decoupled from energy and resource consumption. Meanwhile, end-use sectors, such as industrial, transport, and building, need to achieve deep decarbonization. While energy conservation and energy efficiency keep intensifying, electrification also accelerates to replace coal, petroleum, and other fossil energy sources of direct combustion and utilization. Hydrogen consumption or production using renewable and nuclear power will also help to increase the share of electricity in end-use energy consumption and the share of energy used for power generation in primary energy consumption, resulting in a faster growth rate of electrification than that of energy consumption.

According to the forecast on future power demand by various research institutes, the power consumption in 2050 will range between 11.7–14.4 trillion kWh [1][2][5,6,7,8,9,10,11,12] under the 2℃ scenario, and between 14.4–15.2 trillion kWh under the 1.5℃ scenario. In this study, a bottom-up method is applied in the power demand forecast, i.e. future power demand is calculated mainly based on the future predictions of end-user sectors such as industrial, building, transport, etc. Under all scenarios, end users will see a remarkable improvement in electrification with a growing trend of power consumption, of which the industrial sector will be the cornerstone in driving electrification. As is shown in Table 4.1, under the policy scenario, reinforced policy scenario, 2℃ scenario and 1.5℃ scenario, the power demand in 2050 will respectively reach 11.384 trillion kWh, 11.91 trillion kWh, 13.13 trillion kWh and 14.27 trillion kWh, an increase of 0.66 times, 0.74 times, 0.92 times and 1.08 times from the power supply in 2018.

Table 4.1 Future power demand under each scenario (unit: trillion kWh)

Under the 2℃ scenario, power demand will rise notably in all sectors, where the industrial sector is to become the main driver for power demand, with an increase of 3.21 trillion kWh from 2017 to 2050, which is followed by the building sector with a growth of 1.81 trillion kWh and the transport sector where electric power will replace part of fossil fuels as a major part of the energy mix. The transport power demand is expected to climb from close to zero to 0.79 trillion kWh; the power loss in the agriculture sector would see a 0.5 times increase (see Fig. 4.1). It should be noted, however, that industrial restructuring, energy conservation and efficiency improvement, among other factors on the demand side are taken into consideration in calculating the end user power demand. A significant growth in power demand is still expected under the 2℃ and the 1.5℃ scenarios as more ambitious actions will be taken for end user energy consumption electrification.

Fig. 4.1

Composition of power consumption increase by end users under the 2℃ scenario

Massive emission reduction and decarbonization of end users will imply tremendous changes and challenges for these sectors, for which improvement in energy efficiency and electrification will provide the most important solutions. Taking decarbonization in the industrial sector as an example, measures to achieve decarbonization in the whole production process include using zero-carbon energy to provide power and heating, altering technical processes, adopting CCS to tackle carbon emissions from fossil fuel combustion and production process, switching to alternative feedstocks, etc. The biggest obstacle in decarbonization in the building sector is heating and cooking as 100% electrification is already achieved in lighting, cooling and home appliances. For transport, it requires fully electrified road transport, but for aviation and shipping where zero carbon emission is not within reach, efforts must be done to enable electrification for short-distance travels and opt for new carbon-free materials to make long-distance travels possible [13]. This will depend on the cost reduction of existing technologies (such as CCS and hydrogen-fueled steelmaking) and the emergence of new technologies and processes (such as hydrogen power generation and vehicle to grid).

4.1.2 Scenario Setting and Research Methods

In scenario setting for the power sector, emission reduction pathways are defined based on two phases in line with the overarching guidelines of the project. The policy scenario and the reinforced policy scenario are structured for Phase I from 2020 to 2030, guided by the target of the first stage of China’s modernization drive, i.e. basic realization of modernization, fundamental improvement of ecological environment and overall fulfilment of the goal of building a beautiful China. In addition, the low-carbon policies shall be strengthened, the implementation program and action plan as pledged in the nationally determined contributions shall be carried out and reinforced, following the timetable of carbon emission peaking by 2030 and meeting the target of peak emission control. For Phase II from 2030 to 2050, emission reduction scenarios consistent with global temperature goals are studied and determined, targeting global emission reduction paths for 2°C or 1.5℃ as well as the goals of developing China into a great modern socialist country and building a beautiful China. The four scenarios are conceived as follows:

• 1. The policy scenario: extension of the current policy trend of the power sector based on China’s nationally determined contributions (NDCs) submitted in 2015. By 2030, the share of non-fossil energy shall exceed 20% in total energy supply (equivalent to 42% of non-fossil energy in total power supply).

• 2. The reinforced policy scenario: enforced emission reduction based on China’s NDCs submitted in 2015. By 2030, power produced from non-fossil energy shall surpass 50% of total power generation; by 2050, non-fossil energy as a percentage of total energy supply shall exceed 50% (equivalent to 80% of non-fossil energy in total power supply).

• 3. The 2℃ scenario: emission scenario consistent with the global target of 2℃ by 2050, followed by net zero emission between 2065 and 2070.

• 4. The 1.5℃ scenario: emission scenario aligned with the global target of 1.5℃ by 2050, when negative emission is supposed in the power sector.

In this paper, a mathematical model, named the Long-term Multi-regional Load-dispatch Grid-based (LoMLoG) model has been developed for a quantitative analysis of the power sector under various scenarios. The LoMLoG model is to determine the least-cost development pathway of power sector with the constraints of meeting future power demand and realizing low-carbon targets. The objective function of this model is minimizing the total system cost in the planning horizon (2018–2050 in this paper), which is composed of capital cost, operation and maintenance cost, fuel cost and power transmission cost.

LoMLoG model features its high spatial–temporal resolution and technical details. China is divided into 17 regions based on resource endowment and grid structure. Existing and proposed interregional power transmission lines are set as fixed parameters whilst the incremental transmission capacity in the future are set as variables to be optimized along with power generation capacity. The balance of power generation and demand is based on different regions instead of a single country. In the real power system, the fluctuation of power load requires load dispatch at every moment. Hourly power balance is reflected in the model in order to describe the seasonal and daily variability of power demand and renewable energy availability. Each year is divided into 4 seasons (spring, summer, autumn, winter) and a representative day is selected in each season. Therefore, each year has 96 time slices in total. As a result, this model is able to simulate daily and seasonal balance of power system, with considering the temporal fluctuation of renewable generations.

4.2 Low-Carbon Pathways for the Power Sector

Power transformation pathways in each country are closely linked to its resources endowment, power source mix, economic development, and other factors. Regarding technological pathways, a consensus of various studies points to the necessity to vigorously tap into non-fossil power and develop technologies to enhance grid stability and flexibility. But these studies vary in the level of development for different non-fossil power sources. Among the available studies, a maximum of 630 GW [9], 540 GW and 510 GW [7] are forecasted for hydropower, nuclear power and intermittent renewable energy (wind and solar) respectively by 2050.

4.2.1 Installed Capacity and Power Generation of Different Emission Reduction Pathways

In this study, the nuclear power is supposed to maintain a steady growth to reach approximately 327 GW by 2050. For gas-fired power, despite its lack of price competitiveness, a size of 200 GW is set for 2050 considering its role in system balance and grid stability. According to the review of China hydropower survey in 2003, the theoretical reserves of water resources of all river basins are 694 GW, of which 542 GW are technically exploitable and 402 GW are economically exploitable. Therefore, the hydropower capacity by 2050 is set at 410 GW in this study. Raw materials of biomass industry in China mainly consists of agricultural and forestry residues, organic waste and energy crop/plants, with total available resources reaching nearly 600 million tce by 2050. Biomass liquid fuel technologies will be commercialized after 2030, biomass power generation will stabilize at around 106 million tce around 2030 [14], which is the basis for power generation from biomass and BECCS in this study. The installation and power generation from other sources are selected by the LoMLoG model for minimal social cost. As the cost of intermittent renewables will continue to fall in various forecasts, renewables will be the preferred option in models aiming at minimal cost.

Power installation in the future will be dominated by non-fossil energy, the share of intermittent energy (wind and solar) will see a remarkable increase, and coal-fired CCS and BECCS will be applied under the 2℃ and the 1.5℃ scenarios. As is illustrated in Table 4.2, total installed capacity of the power system will hit 3619 GW, 4291 GW, 5686 GW and 6284 GW respectively under the policy scenario, the reinforced policy scenario, the 2℃ scenario and the 1.5℃ scenario. The weight of non-fossil energy and intermittent renewables in the installed capacity is set to steadily rise under all four scenarios, where the proportion of non-fossil energy will respectively stand at 73.1%, 81.8%, 93.1% and 93.9% and that of intermittent renewables is forecasted to reach 54.1%, 64.5%, 79.4% and 81.3% by 2050. Coal-fired power with CCS and BECCS would reach an installed capacity of 68 GW and 32 GW respectively under the 2℃ scenario, and would expand to 149 GW and 48 GW under the 1.5℃ scenario.

Table 4.2 Generation fleet in 2050 under different scenarios (unit: GW)

Changes in power generation mix suggest that newly emerged demand is mainly met by power from non-fossil sources, which, in the long-term, will further replace coal-fired power stock to meet low-carbon emission goals. As is illustrated in Table 4.3, with other energy sources increasingly replaced by electric power for end users, total power demand in 2050 will reach 11.38 trillion kWh, 11.91 trillion kWh, 13.1 trillion kWh and 14.27 trillion kWh respectively under the policy scenario, reinforced policy scenario, the 2℃ scenario and the 1.5℃ scenario, while power generated from non-fossil energy will comprise 65.0%, 74.8%, 90.5% and 91.1% respectively. Increase in the share of intermittent renewable energy will also be seen in 2050 under the policy scenario, the reinforced policy scenario, the 2℃ scenario and the 1.5℃ scenario, reaching 35.1%, 42.3%, 59.6% and 62.1% of total power generation. Under the 2℃ and the 1.5℃ scenarios, the share of intermittent renewable energy is predicted to surge to around 60% by 2050, presenting a greater challenge for system balance and grid flexibility. Compared to the 2℃ scenario, power generation from coal-fired CCS and BECCS will soar under the 1.5℃ scenario.

Table 4.3 Generation by technology in 2050 under different scenarios (unit: trillion kWh)

Under the reinforced policy scenario, non-fossil fuels will take up 25% of primary energy consumption by 2030, while 50% of total power generation will come from non-fossil energy, whose proportion in primary energy consumption will hit 50% in 2050. As is shown in Tables 4.4 and 4.5, the installed capacity and power generation of coal-fired power will continue to shrink, with a drop of nearly 50% in 2050 as compared to 2020. The installed capacity of natural gas power will reach 200 GW by 2050. But its share in total power production is insignificant due to its primary role in peak regulation. Speedy growth and ambitious scale-up are needed for nuclear, wind and solar power, with the three combined taking up 72.1% of total installed capacity and 62.3% of total power generation by 2050.

Table 4.4 Installed capacity in selected years under the reinforced policy scenario (unit: GW)

Table 4.5 Power generation in selected years under the reinforced policy scenario (unit: trillion kWh)

Under 2℃ scenario where net zero emission is to be achieved around 2050 in the power sector, the emission reduction pathway before 2030 is mostly the same as that under the reinforced policy scenario, while more ambitious actions are essential after 2030. In addition, CCS and BECCS are vital to the 2℃ scenario. Compared to the reinforced policy scenario, coal-fired power will see a steep reduction under 2℃ scenario, with an installed capacity of merely 123 GW in 2050, apart from 68 GW of coal-fired CCS and 32 GW of coal-fired BECCS in the installed capacity (see Table 4.6). Moreover, the 2℃ scenario calls for redoubled efforts in wind and solar power, whose installed capacity would overtake that of the reinforced policy scenario by 67% and 60% respectively, and the power generation would growth by 59% and 50% (see Tables 4.6 and 4.7).

Table 4.6 Installed capacity in selected years under the 2℃ scenario (in GW)

Table 4.7 Power generation in selected years under the 2℃ scenario (in PWh)

4.2.2 Application of CCS and BECCS Technologies

The future capacity of coal-fired and gas-fired units to be retained in China depends, in large measure, on CCS and its combination with bio-energy, i.e. BECCS technologies. Capturing 90% of carbon emissions, coal-fired power plants with CCS will make it a relatively low-carbon power generation technology. BECCS is a negative emission technology that can offset the residual emissions from the power sector. The penetration of CCS depends on its cost reduction in the future, whereas both cost reduction and biomass resources availability are indispensable factors for the scale-up of BECCS. Some studies argue that 400–700 GW of coal-fired power should be reserved by 2050 for basic load, peak load regulation and heating purposes, yet the existing units should be retrofitted for higher flexibility and combined heat and power generation (CHP). Our results are basically consistent with these studies if gas-fired generator sets are included.

CCS and BECCS technologies will play important roles in the 2℃ and the 1.5℃ scenarios. Under the 2℃ scenario, CCS is expected to scale up in coal-fired power plants by 2035 and hit an installed capacity of 68 GW by 2050 with 320 million tonnes of CO₂ captured; BECCS, on the other hand, will be used in large scale by 2040 and reach a capacity of 32 GW by 2050 with 190 million tonnes of CO₂ captured. Under the 1.5℃ scenario, the scale-up of CCS is moved up to 2030, with a capacity of 149 GW by 2050 and 600 million tonnes of CO₂ captured in the same year, and an aggregate capture of 4.13 gigatonnes of CO₂ from 2040 to 2050. BECCS’ deployment will soar from 2040 onward, reaching 48 GW by 2050 with 280 million tonnes of CO₂ captured (see Fig. 4.2).

Fig. 4.2

Installed capacity and carbon storage capacity of CCS and BECCS

4.2.3 Carbon Emission Trajectories of the Power Sector Under Different Scenarios

The carbon emission trajectories of the power sector under the four scenarios are illustrated in Fig. 4.3. Under the policy scenario, carbon emissions from the power sector continue to rise slowly until it peaks in 2025 at 4.25 billion tons CO₂ and then downward to 3.29 billion tons in 2050. Under the reinforced policy scenario, the emissions prior to 2030 stay on the same trajectory with policy scenario but fall rapidly after 2030 and to 2.09 gigatonnes in 2050. In this study, the target of “non-fossil energy comprising 20% of primary energy consumption by 2030” in the 2015 version NDCs is integrated into the policy scenario, and the target of “non-fossil energy representing 50% of primary energy consumption by 2050” is incorporated into the reinforced policy scenario, which is also characterized by a scale-up of renewables before 2030 and the rise of non-fossil energy to 25% of primary energy consumption by 2030. The carbon trajectories of both scenarios point to a failure in attaining the 2℃ goal, i.e. China’s current mid- to long-term energy and power policies and targets fall short of the 2℃ target set in the Paris Agreement.

Fig. 4.3

CO₂ emission trajectory of the power sector under each scenario (including CCS)

In this study, strengthened efforts in emission reduction are seen in the 2℃ and the 1.5℃ scenarios compared to the policy and reinforced policy scenarios prior to 2030, and the efforts are sped up after 2030 for the sake of the 2℃ and the 1.5℃ targets. Under the 2℃ scenario, carbon emissions from the power sector hit the peak in 2023 at 4.21 billion tons and take a nosedive after 2030, falling to merely 320 million tonnes by 2050. Under the 1.5℃ scenario, the power sector sees its emissions peak at 4.21 billion tons in 2023, followed by a steep drop after 2030, reaching a negative emission of 160 million tonnes by 2050 with the aid of BECCS. As is illustrated in the above figure, the carbon trajectory features a sharp fall after 2030 under the 1.5℃ scenario, which presents daunting challenges in the short term to the industry, technology, market and policy, and puts enormous pressure on emission reduction in later phase with the massive retirement of coal-fired power units after 2030.

4.2.4 Demand for Emission Reduction Technologies Under Different Scenarios

Among carbon emission technologies under the four scenarios, nuclear, renewables, CCS and BECCS hold the key to deep emission reduction in the power sector. Relative to the policy scenario, the reinforced policy scenario witnesses the contribution of hydro, nuclear and renewables to emission reduction, to which wind and nuclear power are the biggest contributors. Compared to the policy scenario, the 2℃ scenario sees hydro, nuclear, renewables, CCS and BECCS aiding with emission reduction, coupled with intensified efforts after 2030, and wind and solar power are the biggest contributors. Under the 1.5℃ scenario, though no extra emission reduction technologies are adopted, the penetration of existing technologies and emission reduction efforts increase significantly (see Fig. 4.4).

Fig. 4.4

Carbon emission reduction by different technologies

Table 4.8 shows the technology demand of different emission reduction trajectories in two timeframes (2020–2030, 2030–2050). The difference in the growth of installed capacity is observed between 2020 and 2030 due to cost changes of technologies and different schedules for deep emission reduction. Between 2030 and 2050, deep emission reduction emerges in all pathways, where key emission reduction technologies (wind, solar, energy storage and cross-regional power transmission) all scale up to a similar high level. To be specific, the scale of wind and solar power installation is equally considerable, but due to variance in technological pathways and schedule of deep emission reduction, the size of power installation differs greatly between 2020 and 2030. Due to restrictions of cost and raw material utilization, impede biomass power generation can’t play the major role for emission reduction.

Table 4.8 Technology demand under different scenarios

4.3 Crucial Problems and Solutions for the Low-Carbon Transition of the Power Sector

4.3.1 Operation Security of the Power Grid

China is about to enter a phase that features high penetration of renewables with large-scale clustered integration and high-penetrated distributed integration. In that phase, it will provoke drastic changes for the power system. With the integration of high penetrated renewables, highly uncertain and volatile wind and solar power will be evolved from the supplementary to the primary power sources, and the operation and planning mechanism of power generation systems will be fundamentally changed. The coaction of high volatility in the generation side and the massive distributed sources in the demand side will then fundamentally change the operation and planning mechanism of power transmission and distribution systems. Besides, with the widely application of power electronic interfaces in renewable generation technologies, transmission facilities and load devices, the whole power system is changing towards a power electronics dominated trend. The features of low inertia, weak immunity, and multi-timescale response in power electronic devices will lead to a fundamental change in the stability mechanism and control methods of power electronics dominated power systems. Therefore, there are two key scientific difficulties required to be addressed: (1) the scarcity of power system flexibility and the structure evolution of power transmission and distribution networks due to the strong uncertainties from both generation and demand sides; (2) multi-timescale coupled stabilization mechanism and optimal operation of power electronics dominated power systems.

To tackle these challenges raised by the renewables integration, the combination of multiple technologies with varying costs is necessary for the power system (as shown in Fig. 4.5). When the share of renewable generation is not high (<30%), lower cost technologies, such as improved prediction of renewable generation, flexibility retrofit of thermal power plants, and advanced flexible scheduling, can be utilized to address the problems including generation ramping, peak-load regulation and power reserve. More expensive technologies, including flexible generation, pumped storage, cross-regional transmission, renewable energy curtailment, and biomass power generation, can be adopted as auxiliary approaches. When the share of renewable generation is over 30%, renewables’ uncertainty and volatility will make a significant impact on the power system planning and operation, complicating the power system operation behaviors. In that case, multiple energy system integration is recommended to leverage gas storage, heat storage, cold storage, and other low-cost storage devices for offsetting the fluctuation of renewable generation. Other advanced technologies such as demand response, CSP (concentrating solar power) and emerging energy storage solutions (compressed air energy storage, flow battery and super-capacitor) are also optional. But these technologies are still in the demonstration stage and far from commercial scaled application, and hence are relatively expensive. When the share of renewable generation is over 50%, these above technologies will not be enough, due to new challenges including low inertia and seasonal supply–demand mismatch. In such a case, virtual synchronous generation (VSG) may need to be deployed to increase system synchronous inertia and thus strengthen the system stability. Seasonal supply–demand mismatch problem can be tackled either by seasonal energy storage (such as heat or cold storage) or more expensive solutions such as energy routers or power-to-gas devices (Fig. 4.5).

Fig. 4.5

Challenges and solutions for high penetration of intermittent renewable energy (Note CAES—compressed air energy storage; CSP—concentrating solar power; HVDC—high voltage direct current; HVAC—high voltage alternating current)

With the growing share of renewable generation, more flexible resources are needed to satisfy the peak-load regulating capacity requirement in the power system. The role of coal-fired power units is gradually shifted from satisfying basic load demand to providing flexibility and peak regulation services from 2030, while the corresponding installed capacity is also reducing. The intermittent renewable energy integration is supported by the flexibility retrofit of thermal power plants and the power gird interconnection before 2030. After then, the carbon emission reduction will accelerate, the penetration of renewables will further increase, and the generation capacity of flexible coal-fired power units will also reduce. Large-scale energy storage is necessary to accommodate renewable energy, especially in Inner Mongolia, Xinjiang, Shandong, and northwest China.

The cross-regional power grid interconnection can provide flexibility for renewable energy integration and enhance the optimization of resource allocation. The cross-regional power grid interconnection should be further strengthened and reaches 1.8–2.7 times of current cross-regional transmission capacity level by 2030 under different scenarios. After 2030, due to the limited availability of exploitable renewable energy resources in eastern and central China, northwestern China shall become a key area in renewable energy development to meet the demand for sustained emission reduction. Meanwhile, supporting facilities such as long-distance power transmission lines should be built to reach 3.5–6.2 times of current cross-regional transmission capacity level by 2050 under different scenarios (see Fig. 4.6). The research results show that the cross-regional transmission capacity requirement in 2050 respectively are 788 GW (policy scenario), 903 GW (reinforced policy scenario), 1212 GW (2℃ scenario), and 1387 GW respectively (1.5℃ scenario).

Energy storage could be categorized into short-term daily energy storage and long-term seasonal energy storage. Daily energy storage aims to mitigate renewables’ volatility and address the daily power mismatch between renewable generation and load demand, while the seasonal energy storage enables seasonal energy transfer to address the monthly energy mismatch. In terms of energy storage requirement, the total capacity of 574 GWh, 677 GWh, 1168 GWh, and 1334 GWh will be needed respectively under policy scenario, reinforced policy scenario, 2℃ scenario, and 1.5℃ scenario. The energy storage capacity requirement in 2050 under 2 and 1.5℃ scenarios are expected to be 2 times and 2.3 times of that under policy scenario (see Fig. 4.7).

Fig. 4.6

Total capacity of inter-regional power distribution

Fig. 4.7

Energy storage capacity demand

4.3.2 Retirement of Coal-Fired Power Units

A country’s choice for transition pathway is closely related to its resources endowment, power source mix and economic development level, etc. Duplicating the experience of developed countries in the retirement of coal-fired units would not be a practical option for China. Despite the consensus on the necessity of decarbonization in current studies, opinions are highly different on the capacity of coal-fired power that can be retained in the future. Some studies conclude that China is able to reach the Paris climate targets with lower economic cost, phasing out coal-fired power completely between 2050 and 2055 [13][15]; while others argue that 400–700 GW of coal power will be necessary in 2050 for basic load, peak load regulation and heating, on condition that existing units are retrofitted in terms of flexibility and CHP [6]. The retained capacity of coal power allowed for China will, in large measure, hinge on the potential and progress of CCS and BECCS, where research is severely insufficient [16].

The stranding of coal power assets is a matter of wide concern among various stakeholders. In this research, the cost of stranded coal-fired power assets is defined as the residual value of fixed assets in case of early retirement before reaching the expected service life. Besides, early retirement refers to the fact of being put out of economic service in the conventional sense, with some units still capable of offering valuable services such as complementing the power load shortage at certain time slot as the backup. The cost of stranded coal-fired power assets varies significantly under different scenarios—707.9 billion RMB for the 1.5℃ scenario, 60.9 billion for the 2℃ scenario, 3.1 billion in the policy scenario and 3.2 billion in the reinforced policy scenario. Figure 4.8 illustrates the interannual variation of stranded coal power assets under various scenarios. On the whole, under the 1.5℃ scenario, most of the stranded cost is incurred between 2031 and 2046, with a peak between 2038 and 2044 in particular. Under the 2℃ scenario, the peak of stranding arrives between 2046 and 2048.

Fig. 4.8

Year-to-year stranded cost of coal power assets from 2018 to 2050

4.4 Conclusions and Policy Recommendations

This study shows that for the power sector, the emission reduction pathway based on the NDC of 2015 and related reinforced measures fall short of the 2°C and 1.5℃ targets. To accomplish the emission reduction goals set in Paris Agreement, actions should be ramped up in the power sector to secure an earlier emission peak with faster and more ambition. Major measures include scaling up the development of non-fossil and renewable energy, accelerating the phasing-out of coal-fired power plants and massive deployment of CCS technologies. In the transition of the power sector, appropriate solutions must be explored for safe operation of power grid, retirement of coal-fired power fleet, investment as well as the research and deployment of CCS and BECCS technologies.

• 1. Development of non-fossil energy represents the ultimate approach for decarbonization of China’s power sector, so measures must be taken to ensure the scale and pace of such development.

  It’s imperative to study the proper policy measures to boost renewable energy development, both in terms of the scale and speed. This Study found that China’s power sector shall rely on non-fossil energy for its decarbonization, and on intermittent renewables for deep decarbonization in the long run. Under the 1.5℃ scenario in particular, the development of various renewables has almost hit the ceiling of economically available resources with environment and ecological preservation taken into full account. Under the 2℃ scenario, the annual installed capacity of wind power should stay above 45 GW between 2020 and 2030, and above 83 GW between 2030 and 2050; while for solar power, at least 40 GW between 2020 and 2030 and 79 GW between 2030 and 2050.

• 2. The 14th Five-Year Plan must keep a tight rein on addition of coal-fired power units and make full use of the stock

  Some suspended or postponed coal-fired power projects have been re-approved in an effort to spur domestic demand and stabilize growth in the wake of COVID-19 and the subsequent economic downturn, resulting in a rebound of coal consumption. To reverse the situation, it is suggested that the number of new coal-fired power projects should be strictly controlled during the 14th Five-Year plan period and that the overwhelming majority of incremental power demand be met by renewable energy. More support should be provided for renewable energy in new infrastructure construction and remove the barriers and challenges in this connection. While avoiding increase in coal power capacity in principle, efforts should be made to enable a functional shift of coal-fired power and fully usage of existing coal-fired power. Major steps should be taken to enhance the flexibility retrofit of existing power units prior to 2030, after which the role of coal-fired power should shift from basic load provision to peak load regulation service. The 2 and 1.5℃ scenarios require a transformation of coal-fired installations into peak-shaving units with prolonged shutdown for some to act as standby units. A large amount of social resources and investment cannot be recovered due to the sharp decline in the utilization rate of coal-fired power units. Therefore, it is necessary to establish a capacity cost recovery mechanism to properly handle the problems arising from the transformation of coal power units.

• 3. Spare no effort to develop and deploy energy storage technologies, strengthen inter-regional power transmission channels, and advance power market reforms

  With high penetration of intermittent renewable power, higher flexibility is required to meet the need of hourly peak load regulation. The year 2030 will be a watershed, before which peak regulation depends on flexibility retrofit of coal-fired units and power grids interconnection and mutual support; whereas after this point, new construction of energy storage units is required to accommodate the surge in renewable power, especially in Inner Mongolia, Xinjiang, Shandong and northwest provinces. Therefore, it’s important to proactively develop, demonstrate and utilize energy storage technologies, develop green financing tools to support the massive construction of inter-regional power transmission lines. Deep decarbonization of the power sector in future hinges, from a policy standpoint, on the power market mechanism, hence the need to advance power market reforms and minimize total social cost via market levers.

• 4. Formulate roadmaps for the R&D, demonstration and application of grid technologies to secure a high penetration of intermittent renewable energy

  Compared to conventional flexible power sources such as coal-fired power, the volatility and seasonality of intermittent renewable energy can seriously affect the safety operation of grid. As the penetration of wind and solar power grows, the grid is increasingly featured by the randomization of power and energy balance, diversification of operation modes, scarcity of flexible resources, and complication of stabilization mechanism, etc. As challenges mount, it’s essential to employ an array of technologies to ensure the normal working order of the grid.

  When the share of renewable generation is less than 50%, extra flexibility resources would be required to offset the volatility and uncertainty of renewable generation for the timescale from minute to hour. This is mainly achieved through increasing frequency regulation capacity, peak-load regulation capacity and power reserve capacity. Major technical solutions include flexibility retrofit of coal-fired power plants, demand response management, multiple energy system integration, cross-regional power transmission, concentrating solar power and electrical energy storage. None of these solutions can address the renewable energy integration problem by itself alone. A reasonable and economic combination is necessary, and the optimal technology portfolio depends on the generation and transmission structure of power systems, as well as the maturity and economics of each technology.

  When the share of renewable generation is more than 50% (up to 60% under the 2 and 1.5℃ scenarios in this study), novel renewable energy integration challenges will arise, including low synchronous inertia, frequency stability issue, more periods with renewable generation higher than load demand, and the seasonal energy imbalance between renewable supply and load demand. The power system security operation requires to strengthen the system synchronous inertia, tackle the surplus renewables and the seasonal energy imbalance. The former can be addressed by equipping virtual synchronization in renewable power plants, while the latter calls for seasonal energy storage. Both technologies are currently under the development or the demonstration phase. Strengthened R&D and investment are supposed to promote technology maturity, cost reduction and large scale application through the supports from technology, policy, and markets.

  Compared to conventional flexible thermal power plants, the strong volatility and uncertainty and seasonal mismatch feature of intermittent renewable energy bring significant impacts on power system secure and economic operation. As the penetration of wind and solar power grows, the power grid is increasingly featured by the randomization of power and energy balance, diversification of operation modes, scarcity of flexible resources, and complication of stabilization mechanism, etc. It is essential to employ an array of technologies to ensure the secure and economic operation of power grids.

• 5. CCS should be highlighted as a technology of vital importance for more R&D and demonstration. It’s particularly important to advance geological exploration for potential underground CO₂ reservoirs.

  Based on current understanding of renewable resources in China, this study shows that the zero carbon transformation would be impossible for the power sector without large-scale application of CCS and BECCS technologies, unless revolutionary technological breakthroughs take place. Therefore, CCS should be highlighted as an important technology, and the research and demonstration of the technology should be accelerated to achieve breakthroughs in capture technology, lay a solid foundation for the whole process technology integration and large-scale demonstration, strengthen the policy research on CCS industrialization, and strengthen international cooperation and technology transfer.