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Open Access 2019 | OriginalPaper | Buchkapitel

8. Energy Scenario Results

verfasst von : Sven Teske, Thomas Pregger, Tobias Naegler, Sonja Simon, Johannes Pagenkopf, Bent van den Adel, Özcan Deniz

Erschienen in: Achieving the Paris Climate Agreement Goals

Verlag: Springer International Publishing

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Abstract

Results for the 5.0 °C, 2.0 °C and 1.5 °C scenarios for ten world regions in regard to energy-related carbon-dioxide emissions, final-, primary-, transport- and heating demand and the deployment of various supply technologies to meet the demand. Furthermore, the electricity demand and generation scenarios are provided. The key results of a power sector analysis which simulates further electricity supply with high shares of solar- and wind power in one hour steps is provided. The ten world regions are divided into eight sub-regions and the expected development of loads, capacity-factors for various power plant types and storage demands are provided. This chapter contains more than 100 figures and tables.

This chapter provides a condensed description of the energy scenario results on a global scale, for each of the ten world regions. The descriptions include a presentation of the calculated energy demands for all sectors (power and heat/fuels for the following sectors: industry, residential and other, and transport) and of supply strategies for all the technologies considered, from 2015 to 2050. The results of the model-based analyses of hourly supply curves and required storage capacities are also discussed based on key indicators. Graphs, tables, and descriptions are provided in a standardized way to facilitate comparisons between scenarios and between regions.

The following global summary of the regional results is presented in the same structure as that used for individual regions. Consistent with the regional results, these tables do not include the demand and supply details for the bunker fuels used in international aviation and navigation. Section 8.2 outlines a global demand and supply scenario for renewable bunker fuels in the long term, including estimates of additional CO₂ emissions from fossil bunker fuels between 2015 and 2050.

8.1 Global: Long-Term Energy Pathways

8.1.1 Global: Projection of Overall Energy Intensity

Combining the assumptions for the power, heat, and fuel demands for all sectors produced the overall final energy intensity (per $ GDP) development shown in Fig. 8.1. Compared with the 5.0 °C case based on the Current Policies Scenario of the IEA, the alternative scenarios follow more stringent efficiency levels. The 1.5 °C Scenario represents an even faster implementation of efficiency measures than the 2.0 °C Scenario. The 1.5 °C Scenario involves the decelerated growth of energy services in all regions, to avoid any further strong increase in fossil fuel use after 2020. The global average intensity drops from 2.4 MJ/$GDP in 2015 to 1.25 MJ/$GDP in 2050 in the 5.0 °C case compared with 0.65 MJ/$GDP in the 2.0 °C Scenario and 0.59 MJ/$GDP in the 1.5 °C Scenario. The average final energy consumption decreases from 46.3 GJ/capita in 2015 to 28.4 GJ/capita in 2050 in the 2.0 °C Scenario and to below 26 GJ/capita in the 1.5 °C Scenario. In the 5.0 °C case, it increases to 55 GJ/capita.

8.1.2 Global: Final Energy Demand by Sector (Excluding Bunkers)

Combining the assumptions for population growth, GDP growth, and energy intensity produced the future development pathways for the global final energy demand shown in Fig. 8.2 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will increase by 57% from 342 EJ/year in 2015 to 537 EJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will decrease by 19% compared with the current consumption and reach 278 EJ/year by 2050, whereas the final energy demand in the 1.5 °C Scenario will reach 253 EJ, 26% below the 2015 demand. In the 1.5 °C Scenario, the final energy demand in 2050 is 9% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will increase from around 15,900 TWh/year in 2015 to 23,800 TWh/year (2.0 °C) or to 23,300 TWh/year (1.5 °C) by 2050. Compared with the 5.0 °C case (37,000 TWh/year in 2050), the efficiency measures in the 2.0 °C and 1.5 °C Scenarios will save 13,200 TWh/year and 13,700 TWh/year, respectively, by 2050.

Electrification will lead to a significant increase in the electricity demand by 2050. In the 2.0 °C Scenario, the electricity demand for heating will be about 12,600 TWh/year due to electric heaters and heat pumps, and in the transport sector there will be an increase of about 23,400 TWh/year due to increased electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 18,800 TWh/year The gross power demand will thus rise from 24,300 TWh/year in 2015 to 65,900 TWh/year in 2050 in the 2.0 °C Scenario, 34% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 65,300 TWh/year in 2050.

The efficiency gains in the heating sector could be even larger than in the electricity sector. In the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 85.7 EJ/year and 95.4 EJ/year, respectively, is avoided through efficiency gains by 2050 compared with the 5.0 °C Scenario (Figs. 8.3, 8.4, 8.5, and 8.6).

8.1.3 Global: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power coming from renewable sources. In the 2.0 °C Scenario, 100% of the electricity produced globally will come from renewable energy sources by 2050. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 83% of the total electricity generation. Renewable electricity’s share of the total production will be 62% by 2030 and 88% by 2040. The installed capacity of renewables will reach about 9500 GW by 2030 and 25,600 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario is assumed to be 73%. The 1.5 °C Scenario indicates a generation capacity from renewable energy of about 25,700 GW in 2050.

Table 8.1 shows the development of different renewable technologies in the world over time. Figure 8.7 provides an overview of the global power-generation structure. From 2020 onwards, the continuing growth of wind and photovoltaic (PV), up to 7850 GW and 12,300 GW, respectively, will be complemented by up to 2060 GW of solar thermal generation, and limited biomass, geothermal, and ocean energy in the 2.0 °C Scenario. Both the 2.0 °C Scenario and 1.5 °C Scenario will lead to a high proportion of variable power generation (PV, wind, and ocean) of 38% and 46%, respectively, by 2030 and 64% and 65%, respectively, by 2050.

Table 8.1

Global: development of renewable electricity-generation capacity in the scenarios

in GW	(°C)	2015	2025	2030	2040	2050
Hydro	5.0	1202	1420	1558	1757	1951
	2.0	1202	1386	1416	1473	1525
	1.5	1202	1385	1415	1471	1523
Biomass	5.0	112	165	195	235	290
	2.0	112	301	436	617	770
	1.5	112	350	498	656	798
Wind	5.0	413	880	1069	1395	1790
	2.0	413	1582	2901	5809	7851
	1.5	413	1912	3673	6645	7753
Geothermal	5.0	14	20	26	41	62
	2.0	14	49	125	348	557
	1.5	14	53	147	356	525
PV	5.0	225	785	1031	1422	2017
	2.0	225	2194	4158	8343	12,306
	1.5	225	2829	5133	10,017	12,684
CSP	5.0	4	13	20	39	64
	2.0	4	69	361	1346	2062
	1.5	4	92	474	1540	1990
Ocean	5.0	0	1	3	9	22
	2.0	0	22	82	307	512
	1.5	0	22	80	295	450
Total	5.0	1971	3285	3902	4899	6195
	2.0	1971	5604	9478	18,243	25,584
	1.5	1971	6644	11,420	20,980	25,723

8.1.4 Global: Future Costs of Electricity Generation

Figure 8.8 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated average electricity generation costs in 2015 (referring to full costs) were around 6 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2050, when they reach 10.6 ct/kWh. The generation costs will also increase in the 2.0 °C and 1.5 °C Scenarios until 2030, when they will reach 9 ct/kWh, and then drop to 7 ct/kWh by 2050. In both alternative scenarios, the generation costs will be around 3.5 ct/kWh lower than in the 5.0 °C Scenario by 2050. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, the growth in demand and increasing fossil fuel prices will cause the total electricity supply costs to increase from today’s $1560 billion/year to around $5500 billion/year in 2050. In both alternative scenarios, the total supply costs will be $5050 billion/year in 2050. Therefore, the long-term costs for electricity supply in both alternative scenarios are about 8% lower than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility.

Compared with these results, the generation costs (without including CO₂ emission costs) will increase in the 5.0 °C case to only 7.9 ct/kWh. The generation costs will increase in the 2.0 °C Scenario until 2030 to 7.7 ct/kWh and to a maximum of 8.1 ct/kWh in the 1.5 °C Scenario. Between 2030 and 2050, the costs will decrease to 7 ct/kWh. In the 2.0 °C Scenario, the generation costs will be, at maximum, 0.1 ct/kWh higher than in the 5.0 °C Scenario and this will occur in 2040. In the 1.5 °C Scenario, the generation costs will be, at maximum, 0.5 ct/kWh higher than in the 5.0 °C Scenario, again by around 2040. In 2050, the generation costs in the alternative scenarios will be 0.8–0.9 ct/kWh lower than in the 5.0 °C case. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will rise to about $4150 billion/year in 2050.

8.1.5 Global: Future Investments in the Power Sector

In the 2.0 °C Scenario, around $49,000 billion in investment will be required for power generation between 2015 and 2050—including for additional power plants to produce hydrogen and synthetic fuels and for the plant replacement costs at the end of their economic lifetimes. This value will be equivalent to approximately $1360 billion per year on average, and is $28,600 billion more than in the 5.0 °C case ($20,400 billion). An investment of around $51,000 billion for power generation will be required between 2015 and 2050 in the 1.5 °C Scenario. On average, this will be an investment of $1420 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will comprises around 40% of total cumulative investments, whereas approximately 60% will be invested in renewable power generation and co-generation (Fig. 8.9).

However, in the 2.0 °C (1.5 °C) Scenario, the world will shift almost 94% (95%) of its total energy investment to renewables and co-generation. By 2030, the fossil fuel share of the power sector investment will predominantly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $26,300 billion in 2050, equivalent to $730 billion per year. Therefore, the total fuel cost savings in the 2.0 °C Scenario will be equivalent to 90% of the additional energy investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $28,800 billion, or $800 billion per year.

8.1.6 Global: Energy Supply for Heating

The final energy demand for heating will increase in the 5.0 °C Scenario by 59%, from 151 EJ/year in 2015 to around 240 EJ/year in 2050. In the 2.0 °C Scenario, energy efficiency measures will help to reduce the energy demand for heating by 36% in 2050, relative to that in the 5.0 °C Scenario, and by 40% in the 1.5 °C Scenario. Today, renewables supply around 20% of the global final energy demand for heating. The main contribution is from biomass. Renewable energy will provide 42% of the world’s total heat demand in 2030 in the 2.0 °C Scenario and 56% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.10 shows the development of different technologies for heating worldwide over time, and Table 8.2 provides the resulting renewable heat supply for all scenarios. Until 2030, biomass will remain the main contributor. In the long-term, the growing use of solar, geothermal, and environmental heat will lead to a biomass share in total heating of 33% in the 2.0 °C Scenario and 30% in the 1.5 °C Scenario.

Table 8.2

Global: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	(°C)	2015	2025	2030	2040	2050
Biomass	5.0	25,470	27,643	28,878	31,568	34,564
	2.0	25,470	32,078	35,134	38,187	37,536
	1.5	25,470	33,493	36,927	36,385	30,151
Solar heating	5.0	1246	2091	2754	4353	6220
	2.0	1246	6485	12,720	23,329	27,312
	1.5	1246	7656	14,153	21,665	24,725
Geothermal heat and heat pumps	5.0	563	804	925	1293	1823
	2.0	563	4212	8956	21,115	33,123
	1.5	563	4615	10,288	20,031	29,123
Hydrogen	5.0	0	0	0	0	0
	2.0	0	193	508	5670	15,877
	1.5	0	180	1769	10,461	17,173
Total	5.0	27,278	30,538	32,557	37,214	42,608
	2.0	27,278	42,967	57,318	88,301	113,848
	1.5	27,278	45,944	63,137	88,542	101,172

Heat from renewable hydrogen will further reduce the dependence on fossil fuels in both scenarios. Hydrogen consumption in 2050 will be around 15,900 PJ/year in the 2.0 °C Scenario and 17,200 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of 4.2–4.5 between 2015 and 2050 and will have a final share of 26% in 2050 in the 2.0 °C Scenario and 30% in the 1.5 °C Scenario (Table 8.2).

8.1.7 Global: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 will amount to around $13,230 billion in the 2.0 °C Scenario (including investments for plant replacement after their economic lifetimes)—approximately $368 billion per year. The largest share of this investment is assumed to be for heat pumps (around $5700 billion), followed by solar collectors and geothermal heat use. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies. However, the lower heat demand (compared with the 2.0 °C Scenario) will result in a lower average annual investment of around $344 billion per year (Table 8.3, Fig. 8.11).

Table 8.3

Global: installed capacities for renewable heat generation in the scenarios

in GW	(°C)	2015	2025	2030	2040	2050
Biomass	5.0	10,215	10,180	9938	9423	8997
	2.0	10,215	10,202	9456	7875	5949
	1.5	10,215	10,418	9568	7073	4141
Geothermal	5.0	5	7	7	8	4
	2.0	5	85	181	492	656
	1.5	5	101	200	433	551
Solar heating	5.0	378	615	781	1175	1652
	2.0	378	1685	3198	5722	6575
	1.5	378	1993	3555	5286	5964
Heat pumps	5.0	89	126	144	199	270
	2.0	89	497	906	1821	2857
	1.5	89	514	967	1726	2430
Total^a	5.0	10,688	10,928	10,871	10,805	10,923
	2.0	10,688	12,469	13,741	15,910	16,036
	1.5	10,688	13,026	14,290	14,517	13,086

^a Excluding direct electric heating

8.1.8 Global: Transport

The energy demand in the transport sector will increase in the 5.0 °C Scenario by 50% by 2050, from around 97,200 PJ/year in 2015 to 145,700 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will reduce the energy demand by 66% (96,000 PJ/year) by 2050 compared with the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in the transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 74% (or 108,000 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.4, Fig. 8.12).

Table 8.4

Global: projection of transport energy demand by mode in the scenarios

in PJ/year	(°C)	2015	2025	2030	2040	2050
Rail	5.0	2705	2708	2814	3024	3199
	2.0	2705	2875	3149	3520	3960
	1.5	2705	2932	3119	3559	4087
Road	5.0	85,169	94,755	102,556	116,449	127,758
	2.0	85,169	79,975	68,660	48,650	40,089
	1.5	85,169	67,579	48,949	34,055	28,859
Domestic aviation	5.0	4719	6544	7745	9080	9176
	2.0	4719	4732	4239	3291	2640
	1.5	4719	4461	3612	2361	1845
Domestic navigation	5.0	2130	2304	2392	2537	2663
	2.0	2130	2303	2388	2512	2601
	1.5	2130	2301	2383	2506	2601
Total	5.0	94,723	106,310	115,506	131,091	142,796
	2.0	94,723	89,886	78,436	57,973	49,290
	1.5	94,723	77,274	58,063	42,482	37,392

By 2030, electricity will provide 12% (2700 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas in 2050, the share will be 47% (6500 TWh/year). In 2050, around 8430 PJ/year of hydrogen will be used in the transport sector, as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be about 5200 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 6850 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of around 12,000 PJ/year Therefore, by around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 5820 PJ/year in 2050. Because of the lower overall energy demand by transport, biofuel use will be reduced in the 1.5 °C Scenario to a maximum of 10,000 PJ/year The maximum synthetic fuel demand will amount to 6300 PJ/year.

8.1.9 Global: Development of CO₂ Emissions

In the 5.0 °C Scenario, the annual global energy-related CO₂ emissions will increase by 40%, from 31,180 Mt. in 2015 to more than 43,500 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause annual emissions to fall to 7070 Mt. in 2040 in the 2.0 °C Scenario and to 2650 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C Scenario, the cumulative CO₂ emissions from 2015 until 2050 will add up to 1388 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period 2015–2050 will be 587 Gt and 450 Gt, respectively.

Thus, the cumulative CO₂ emissions will decrease by 58% in the 2.0 °C Scenario and by 68% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario, the reduction will be greatest in ‘Power generation’, followed by the ‘Residential and other’ and ‘Transport’ sectors (Fig. 8.13).

8.1.10 Global: Primary Energy Consumption

The levels of primary energy consumption based on the assumptions discussed above in the three scenarios are shown in Fig. 8.14. In the 2.0 °C Scenario, the primary energy demand will decrease by 21%, from around 556 EJ/year in 2015 to 439 EJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 48% by 2050 in the 2.0 °C Scenario (5.0 °C: 837 EJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (412 EJ in 2050) due to the lower final energy demand and lower conversion losses.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 35% in 2030 and 92% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 92% in 2050 (this will includes non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out in both the 2.0 °C and 1.5 °C Scenarios. The cumulative primary energy consumption of natural gas in the 5.0 °C Scenario will be 5580 EJ, the cumulative coal consumption will be about 6360 EJ, and the crude oil consumption will be 6380 EJ. In the 2.0 °C Scenario, the cumulative gas demand will amount to 3140 EJ, the cumulative coal demand to 2340 EJ, and the cumulative oil demand to 2960 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 2710 EJ for natural gas, 1570 EJ for coal, and 2230 EJ for oil.

8.2 Global: Bunker Fuels

Bunker fuels for international aviation and navigation are separate categories in the energy statistics. Their use and related emissions are not usually directly allocated to the regional energy balances. However, they contribute significantly to global greenhouse gas (GHG) emissions and pose great challenges regarding their substitution with low-carbon alternatives. In 2015, the annual bunker fuels consumption was in the order of 16,000 PJ, of which 7400 PJ was for aviation and 8600 PJ for navigation. Between 2009 and 2015, bunker fuel consumption increased by 13%. The annual CO₂ emissions from bunker fuels accounted for 1.3 Gt in 2015, approximately 4% of global energy-related CO₂ emissions. In the 5.0 °C Scenario, the development of the final energy demand for bunker fuels is assumed to be that of the IEA World Energy Outlook 2017 Current Policies scenario. This will lead to a further increase of 120% in the demand for bunker fuels until 2050 compared with that in the base year, 2015. Because no substitution with ‘green’ fuels is assumed, CO₂ emissions will rise by the same order of magnitude.

Although the use of hydrogen and electricity in aviation is technically feasible (at least for regional transport) and synthetic gas use in navigation is an additional option under discussion, this analysis uses a conservative approach and assumes that bunker fuels are only replaced by biofuels or synthetic liquid fuels. Figure 8.15 shows the 5.0 °C and two alternative bunker scenarios, which are defined in consistency to the scenarios for each world region. For the 2.0 °C and 1.5 °C Scenarios, we assume the limited use of sustainable biomass potentials and the complementary central production of power-to-liquid synfuels. In the 2.0 °C Scenario, this production is assumed to take place in three world regions: Africa, the Middle East, and OECD Pacific (especially Australia), where synfuel generation for export is expected to be the most economic. The 1.5 °C Scenario requires even faster decarbonisation, and therefore follows a more ambitious low-energy pathway. This will lead to a faster build-up of the power-to-liquid infrastructure in all regions, which in the long term, will also be used for limited ‘regional’ bunker fuel production to maintain the utilization of the existing infrastructure. Therefore, the production of bunker fuels is assumed to occur in more regions, with lower exports from the supply regions mentioned above, in the 2.0 °C Scenario. Another assumption is that, consistent with the regional 1.5 °C Scenarios, the biomass consumption for energy supply will decrease in the long term, whereas power-to-liquid will continue to increase as the main option for international aviation and navigation. Finally, the expansion of the power-to-liquid infrastructure for the generation of bunker fuel will be closely associated with the assumed development of regional synthetic fuel demand and generation for transportation in each world region. Figure 8.15 also shows the resulting cumulative CO₂ emissions from bunker fuel consumption between 2015 and 2050, which amount to around 70 Gt in the 5.0 °C case, 30 Gt in the 2.0 °C Scenario, and 21 Gt in the 1.5 °C Scenario. Table 8.5 provides more-detailed data for the three bunker fuel scenarios.

Table 8.5

Global: projection of bunker fuel demands for aviation and navigation by fuel in the scenarios

World bunkers 5.0 °C scenario	Unit	2015	2020	2025	2030	2035	2040	2045	2050
Total final energy consumption	PJ/year	15,985	17,976	20,090	22,593	25,443	28,293	31,462	34,987
thereof aviation	PJ/year	7408	8385	9431	10,674	12,097	13,537	15,148	16,950
thereof navigation	PJ/year	8576	9591	10,658	11,919	13,346	14,756	16,314	18,037
fossil fuels	PJ/year	15,985	17,976	20,090	22,593	25,443	28,293	31,462	34,987
biofuels	PJ/year	0	0	0	0	0	0	0	0
synthetic liquid fuels	PJ/year	0	0	0	0	0	0	0	0
Primary energy demand
crude oil	PJ/year	17,663	19,754	21,956	24,558	27,506	30,423	33,650	37,220
CO₂ emissions	Mt/year	1296	1450	1611	1802	2018	2232	2468	2730
World bunkers 2.0 °C Scenario	unit	2015	2020	2025	2030	2035	2040	2045	2050
Total final energy consumption	PJ/year	15,985	17,538	16,836	15,274	15,053	14,826	14,483	14,014
thereof aviation	PJ/year	7408	8594	8418	7713	7602	7487	7314	7077
thereof navigation	PJ/year	8576	8944	8418	7561	7451	7339	7169	6937
fossil fuels	PJ/year	15,985	17,270	16,180	13,748	10,537	5189	3621	0
biofuels	PJ/year	0	268	657	1526	3146	5417	6381	7430
synthetic liquid fuels	PJ/year	0	0	0	0	1370	4220	4481	6584
Assumed regional structure of synthetic bunker production
Africa	PJ/year	0	0	0	0	846	2607	2768	4067
Middle East	PJ/year	0	0	0	0	183	564	598	879
OECD Pacific	PJ/year	0	0	0	0	341	1050	1115	1638
Primary energy demand
crude oil	PJ/year	17,663	18,978	17,683	14,943	11,391	5580	3872	0
biomass	PJ/year	0	400	952	2150	4369	7420	8623	9907
RES electricity demand for PtL	TWh/year	0	0	0	0	961	2880	3058	4375
CO₂ emissions	Mt/year	1296	1391	1296	1095	835	409	284	0
World bunkers 1.5 °C Scenario	unit	2015	2020	2025	2030	2035	2040	2045	2050
Total final energy consumption	PJ/year	15,985	17,538	15,995	13,747	12,795	12,602	12,311	11,912
thereof aviation	PJ/year	7408	8594	7997	6942	6462	6364	6217	6016
thereof navigation	PJ/year	8576	8944	7997	6805	6334	6238	6094	5896
fossil fuels	PJ/year	15,985	17,538	15,179	7836	2559	0	0	0
biofuels	PJ/year	0	0	816	4536	6398	6931	5540	4527
synthetic liquid fuels	PJ/year	0	0	0	1375	3839	5671	6771	7385
Assumed regional structure of synthetic bunker production
Africa	PJ/year	0	0	0	717	2002	2863	3093	2882
Middle East	PJ/year	0	0	0	155	433	619	669	873
OECD Pacific	PJ/year	0	0	0	289	836	1265	1622	1697
OECD North America	PJ/year	0	0	0	213	568	798	924	977
OECD Europe	PJ/year	0	0	0	0	0	126	262	557
Eurasia	PJ/year	0	0	0	0	0	0	200	400
Primary energy demand
crude oil	PJ/year	17,663	19,273	16,589	8517	2766	0	0	0
biomass	PJ/year	0	0	1182	6389	8885	9495	7486	6035
RES electricity demand for PtL	TWh/year	0	0	0	964	2693	3870	4621	4896
CO₂ emissions	Mt/year	1296	1413	1216	624	203	0	0	0

The production of synthetic fuels will cause significant additional electricity demand and a corresponding expansion of the renewable power generation capacities. In the case of liquid bunker fuels, these additional renewable power generation capacities will amount to 1100 GW in the 2.0 °C Scenario and more than 1200 GW in the 1.5 °C Scenario if a flexible utilization rate of 4000 full-load hours per year can be achieved. However, such a situation will require high amounts of electrolyser capacity and hydrogen storage to allow not only flexibility in the power system, but also high utilization rates of the downstream synthesis processes (e.g., via Fischer-Tropsch plants). Other options for renewable synthetic fuel production are solar thermal chemical processes, which directly use high-temperature solar heat.

8.3 Global: Utilization of Solar and Wind Potential

The economic potential, under space constraints, of utility solar PV, concentrated solar power (CSP), and onshore wind was analysed with the methodology described in Sect. 3.3 of Chap. 3.

The 2.0 °C Scenario utilizes only a fraction of the available economic potential of the assumed suitable land for utility-scale solar PV and concentrated solar power plants. This estimate does not include solar PV roof-top systems, which have significant additional potential. India (2.0 °C) will have the highest solar utilization rate of 8.5%, followed by Europe (2.0 °C) and the Middle East (2.0 °C), with 5.9% and 4.6%, respectively.

Onshore wind potential has been utilized to a larger extent than solar potential. In the 2.0 °C Scenario, space-constrained India will utilize more than half of onshore wind, followed by Europe with 20%. This wind potential excludes offshore wind, which has significant potential but the mapping for the offshore wind potential was beyond the scope of this analysis (Table 8.6).

Table 8.6

Economic potential within a space-constrained scenario and utilization rates for the 2.0 °C and 1.5 °C scenarios

Economic Potential within available space	SOLAR	Installed capacity by 2050				Utilization rate		WIND	Installed capacity by 2050		Utilization rate
	SOLAR	2.0 °C		1.5 °C		2.0 °C	1.5 °C	WIND	2.0 °C	1.5 °C	2.0 °C	1.5 °C
	Tech. space potential	PV	CSP	PV	CSP			Onshore wind
	[GW]	[GW]				[%]		[GW]	[GW]		[%]
OECD North America	445,954	1688	208	1816	236	0.4%	0.5%	86,846	847	833	1.0%	1.0%
Latin America	148,664	317	66	425	79	0.3%	0.3%	29,736	220	237	0.7%	0.8%
OECD Europe	14,364	793	54	918	57	5.9%	6.8%	2873	577	636	20.1%	22.1%
Middle East	24,451	881	252	742	216	4.6%	3.9%	470	455	434	96.8%	92.4%
Africa	914,180	767	247	930	257	0.1%	0.1%	190,711	485	509	0.3%	0.3%
Eurasia	Not available	658	22	657	34			Not available	564	544
Non-OECD-Asia	44,064	1065	274	1005	224	3.0%	2.8%	4740	515	506	10.9%	10.7%
India	1323	1257	209	1129	209	8.5%	7.7%	1974	1139	983	57.7%	49.8%
China	176,916	1756	762	1772	614	1.4%	1.3%	17,848	1180	1345	6.6%	7.5%
OECD Pacific	124,178	665	57	745	67	0.6%	0.7%	24,447	244	303	1.0%	1.2%

The 1.5 °C Scenario is based on the accelerated deployment of all renewables and the more ambitious implementation of efficiency measures. Therefore, the total installed capacity of solar and wind generators by 2050 is not necessarily larger than it is in the 2.0 °C Scenario, and the utilization rate is in the same order of magnitude. The increased deployment of renewable capacity in OECD Pacific (Australia), the Middle East, and OECD North America (USA) will be due to the production of synthetic bunker fuels from hydrogen to supply global transport energy for international shipping and aviation.

8.4 Global: Power Sector Analysis

The long-term global and regional energy results were used to conduct a detailed power sector analysis with the methodology described in Sect. 3.5 of Chap. 3. Both the 2.0 °C and 1.5 °C Scenarios rely on high shares of variable solar and wind generation. The aim of the power sector analysis was to gain insight into the power system stability for each region (subdivided into up to eight sub-regions) and to gauge the extent to which power grid interconnections, dispatch generation services, and storage technologies are required. The results presented in this chapter are projections calculated from publicly available data. Detailed load curves for some of the sub-regions and countries discussed in this chapter were not available and, in some cases, the relevant information is classified. Therefore, the outcomes of the [R]E 24/7 model are estimates and require further research with more detailed localized data, especially regarding the available power grid infrastructure. Furthermore, power sector projections for developing countries, especially in Africa and Asia, assume unilateral access to energy services for the residential sector by 2050, and they require transmission and distribution grids in regions where there are none at the time of writing. Further research—in cooperation with local utilities and government representatives—is required to develop a more detailed understanding of power infrastructure needs.

8.4.1 Global: Development of Power Plant Capacities

The size of the global market for renewable power plants will increase significantly under the 2.0 °C Scenario. The annual market for solar PV power must increase from close to 100 GW in 2017 (REN21-GSR 2018) by a factor of 4.5 to an average of 454 GW by 2030. The onshore wind market must expand to 172 GW by 2025, about three times higher than in 2017 (REN21-GSR 2018). The offshore wind market will continue to increase in importance within the renewable power sector. By 2050, offshore wind installations will increase to 32 GW annually—11 times higher than in 2017 (GWEC 2018). Concentrated solar power plants will play an important role in dispatchable solar electricity generation for the supply of bulk power, especially for industry, and will provide secured capacity to power systems. By 2030, the annual CSP market must increase to 78 GW, compared with 3 GW in 2020 and only 0.1 GW in 2017 (REN21-GSR2018) (Table 8.7).

Table 8.7

World: average annual change in the installed power plant capacity

Global power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	2	−107	−96	−119	−68	−12
Lignite	−25	−34	−16	−9	−3	−1
Gas	41	70	44	72	−199	−28
Hydrogen-gas	1	17	12	57	240	246
Oil/diesel	−18	−32	−29	−28	−6	−2
Nuclear	−15	−27	−23	−24	−7	−10
Biomass	24	40	26	29	25	21
Hydro	19	10	7	7	7	8
Wind (onshore)	121	307	273	333	242	158
Wind (offshore)	16	64	75	91	64	45
PV (roof top)	170	413	368	437	399	324
PV (utility scale)	57	138	123	146	133	108
Geothermal	5	16	22	24	28	23
Solar thermal power plants	9	57	93	109	102	85
Ocean energy	4	10	20	20	28	23
Renewable fuel based co-generation	13	31	27	31	25	20

In the 1.5 °C Scenario, the phase-out of coal and lignite power plants is accelerated and a total capacity of 618 GW—equivalent to approximately 515 power stations¹—must end operation by 2025. The replacement power must come from a variety of renewable power generators, both variable and dispatchable. The annual market for solar PV must be around 30% higher in 2050 than it was in 2025, as in the 2.0 °C Scenario. While the onshore wind market also has an accelerated trajectory under the 1.5 °C Scenario as well, the offshore wind market is assumed to be almost identical to that in the 2.0 °C pathway because of the longer lead times for these projects. The same is assumed for CSP plants, which are utility-scale projects and significantly higher deployment seems unlikely in the time remaining until 2025.

8.4.2 Global: Utilization of Power-Generation Capacities

On a global scale, in the 2.0 °C and 1.5 °C Scenarios, the shares of variable renewable power generation will increase from 4% in 2015 to 39% and 47%, respectively, by 2030, and to 64% and 60%, respectively, by 2050. The reason for the variations in the two cases is their different assumptions regarding efficiency measures, which may lead to lower overall demand in the 1.5 °C Scenario than in the 2.0 °C Scenario. During the same period, dispatchable renewables—CSP plants, biofuel generation, geothermal energy, and hydropower—will remain around 32% until 2030 on a global average and decrease slightly to 29% in the 2.0 °C Scenario (and to 27% in the 1.5 °C Scenario) by 2050. The shares of dispatchable conventional generation—mainly coal, oil, gas, and nuclear—will decline from a global average of 60% in 2015 to only 14% in 2040. By 2050, the remaining dispatchable conventional gas power plants will have been converted to operate with hydrogen and synthetic fuels, to avoid stranded investments and to achieve higher quantities of dispatch power capacity. Table 8.8 shows the increasing shares of variable renewable power generation—solar PV and wind power—under the 2.0 °C and 1.5 °C Scenarios over the entire modelling period. The main difference between the two scenarios is the time horizon until variable renewable power generation is implemented, with more rapid implementation in the 1.5 °C Scenario. Again, increased variable shares—mainly in the USA, the Middle East region, and Australia—will produce synthetic fuels for the export market, as fuel for both renewable power plants and the transport sector.

Table 8.8

Global: power system shares by technology group

Power generation structure in 10 world regions		2.0 °C			1.5 °C
World		Variable renewables	Dispatch renewables	Dispatch fossil	Variable renewables	Dispatch renewables	Dispatch fossil
OECD North America	2015	7%	35%	58%	7%	41%	52%
	2030	48%	30%	23%	59%	27%	15%
	2050	68%	19%	13%	68%	21%	11%
Latin America	2015	3%	63%	34%	3%	62%	35%
	2030	24%	51%	25%	36%	61%	3%
	2050	39%	45%	16%	40%	46%	13%
Europe	2015	15%	47%	38%	15%	47%	38%
	2030	44%	44%	12%	51%	39%	10%
	2050	67%	28%	4%	69%	27%	4%
Middle East	2015	0%	12%	88%	0%	13%	87%
	2030	51%	19%	31%	56%	18%	27%
	2050	81%	19%	0%	70%	16%	13%
Africa	2015	2%	26%	73%	2%	17%	81%
	2030	47%	21%	32%	52%	13%	35%
	2050	73%	27%	0%	64%	15%	21%
Eurasia	2015	1%	35%	63%	1%	35%	63%
	2030	36%	43%	21%	40%	46%	14%
	2050	69%	23%	7%	65%	25%	10%
Non-OECD Asia	2015	1%	35%	64%	1%	35%	64%
	2030	26%	35%	39%	36%	34%	30%
	2050	52%	28%	19%	55%	28%	17%
India	2015	4%	32%	64%	4%	32%	64%
	2030	45%	26%	29%	60%	21%	19%
	2050	72%	27%	1%	58%	26%	16%
China	2015	6%	35%	59%	6%	21%	73%
	2030	30%	24%	46%	39%	30%	31%
	2050	49%	47%	5%	49%	42%	9%
OECD Pacific	2015	4%	34%	61%	4%	34%	61%
	2030	40%	31%	30%	45%	29%	27%
	2050	71%	26%	2%	64%	22%	14%
Global average	2015	4%	35%	60%	4%	34%	62%
	2030	39%	32%	29%	47%	32%	21%
	2050	64%	29%	7%	60%	27%	13%

Note: Variable renewable generation shares in long term energy pathways and power sector analysis differ due to different calculation methods. The power sector analysis results are based on the sum of up to eight sub-regional simulations, while the long term energy pathway is based on the regional average generation excluding variations in solar and wind resources within that region

Table 8.9 provides an overview of the capacity factor developments by technology group for the 2.0 °C and 1.5 °C Scenarios. The operational hours shown are the result of [R]E 24/7 modelling under the ‘Dispatch case’, which assumes that the highest priority is given to the dispatch of power from variable sources, followed by dispatchable renewables. Conventional power generation will only provide power for electricity demand that cannot be met by renewables and storage technologies. Only imports via interconnections will be assigned a lower priority than conventional power. The reason that interconnections are placed last in the supply cascade is the high level of uncertainty about whether these interconnections can actually be implemented in time. Experience with power grid projects—especially transmission lines—indicates that planning and construction can take many years or fail entirely, leaving large-scale utility-based renewable power projects unbuilt.

Table 8.9

Global: capacity factors for variable and dispatchable power generation

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
World			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	49.5%	37%	37%	33%	31%	34%	30%	33%	31%
Limited dispatchable: fossil and nuclear	[%/yr]	58.7%	34%	34%	24%	16%	25%	10%	17%	9%
Limited dispatchable: renewable	[%/yr]	36.9%	45%	45%	42%	36%	58%	31%	39%	34%
Dispatchable: fossil	[%/yr]	42.9%	28%	28%	19%	15%	33%	15%	19%	19%
Dispatchable: renewable	[%/yr]	43.1%	56%	56%	54%	47%	42%	39%	51%	43%
Variable: renewable	[%/yr]	14.6%	14%	14%	28%	26%	28%	26%	29%	27%

On the global level, the average capacity factor across all power-generation technologies is around 45%. For this analysis, we created five different power plant categories based on their current usual operation times and areas of use:

Limited dispatchable fossil and nuclear power plants: coal, lignite, and nuclear power plants with limited ability to respond to changes in demand. These power plants are historically categorized as ‘baseload power plants’. Power systems dominated by renewable energy usually contain high proportions of variable generation, and therefore quick reaction times (to ramp up and down) are required. Limited dispatchable power plants cannot deliver these services and are therefore being phased-out.
Limited dispatchable renewable systems are CSP plants with integrated storage and co-generation systems with renewable fuels (including geothermal heat). They cannot respond quickly enough to adapt to minute-by-minute changes in demand, but can still be used as dispatch power plants for ‘day ahead’ planning.
Dispatchable fossil fuel power plants are gas power plants that have very quick reaction times and therefore provide valid power system services.
Dispatchable renewable power plants are hydropower plants (although they are dependent on the climatic conditions in the region where the plant is used), biogas power plants, and former gas power plants converted to hydrogen and/or synthetic fuel. This technology group is responsible for most of the required load-balancing services and is vital for the stability of the power system, as storage systems, interconnections, and, if possible, demand-side management.
Variable renewables are solar PV plants, onshore and offshore wind farms, and ocean energy generators. A sub-category of ocean energy plants—tidal energy plants—is very predictable.

Table 8.9 shows the development of the utilization of limited and fully dispatchable power generators—both fossil and renewable fuels—and variable power generation. In the 2.0 °C Scenario, conventional power generation in the baseload mode—currently with an annual operation time of around 6000 h per year or more—will decline sharply after 2030 and the annual operation time will be halved, whereas medium-load and dispatch power plants will predominate. The system share of dispatchable renewables will remain around 45%–50% throughout the entire modelling period.

8.4.3 Global: Development of Load, Generation, and Residual Load

Table 8.10 shows the development of the maximum and average loads for the 10 world regions, the average and maximum power generation in each region in megawatts, and the residual loads under both alternative scenarios. The residual load in this analysis is the load remaining after variable renewable power generation. Negative values indicate that the power generation from solar and wind exceeds the actual load and must be exported to other regions, stored, or curtailed. In each region, the average generation should be on the same level as the average load. The maximum loads and maximum generations shown do not usually occur at the same time, so surplus production of electricity can appear and this should be exported or stored as much as possible. In rare individual cases, solar or wind generation plants can also temporarily reduce their output to a lower load, or some plants can be shut down. Any reduced generation from solar and wind in response to low demand is defined as curtailment.

Table 8.10

Global: load, generation, and residual load development

Power generation structure in 10 world regions		2.0 °C				1.5 °C
World		Max demand [GW]	Max generation [GW]	Max residual load [GW]	Max load development (Base 2020) [GW]	Max demand [GW]	Max generation [GW]	Max residual load [GW]	Max load development (Base 2020) [GW]
OECD North America	2020	753	723	57	100%	755	989	58	100%
	2030	864	1159	145	115%	919	1532	194	122%
	2050	1356	2779	469	180%	1362	2900	496	180%
Latin America	2020	218	214	30	100%	218	274	18	100%
	2030	343	377	74	157%	312	418	25	143%
	2050	533	601	154	244%	550	696	122	252%
OECD Europe	2020	574	584	121	100%	574	583	125	100%
	2030	620	718	95	108%	639	936	104	111%
	2050	862	1530	417	150%	900	1727	448	157%
Middle East	2020	174	181	−29	100%	174	180	−26	100%
	2030	229	297	−20	132%	237	346	−13	136%
	2050	551	1164	−67	317%	522	1018	−161	300%
Africa	2020	164	125	47	100%	164	135	37	100%
	2030	280	261	101	171%	296	305	105	181%
	2050	875	1363	647	534%	915	1562	412	559%
Eurasia	2020	257	163	107	100%	257	171	106	100%
	2030	316	332	147	123%	330	416	139	129%
	2050	630	1338	271	245%	632	1296	275	246%
Non-OECD Asia	2020	248	135	122	100%	248	133	124	100%
	2030	415	389	256	167%	423	465	296	171%
	2050	935	1459	728	377%	841	1394	656	339%
India	2020	288	266	44	100%	288	249	61	100%
	2030	493	624	112	171%	491	861	148	170%
	2050	1225	1880	854	425%	1207	1865	558	419%
China	2020	957	935	74	100%	953	946	57	100%
	2030	1233	1249	173	129%	1219	1613	179	128%
	2050	1967	2724	1415	206%	1990	3203	−609	209%
OECD Pacific	2020	354	322	47	100%	354	318	47	100%
	2030	308	468	21	87%	318	544	36	90%
	2050	410	997	196	116%	471	1140	173	133%

Figure 8.16 illustrates the development of the maximum loads across all 10 world regions under the 2.0 °C and 1.5 °C Scenarios. The most significant increase appears in Africa, where the maximum load surges over the entire modelling period by 534% in response to favourable economic development and increased access to energy services by households. In OECD Pacific, efficiency measures will lead to a reduction in the maximum load to 87% of the base year value by 2030 and will increase to 116% by 2050 with the expansion of electric mobility and the increased electrification of the process heat supply in the industry sector. The 1.5 °C Scenario has slightly higher loads in response to the accelerated electrification of the industry, heating, and business sectors, except in three regions (the Middle East, India, and Non OECD Asia), where early action on efficiency measures will lead to an overall lower demand at the end of the modelling period, with the same GDP and population growth rates.

8.4.4 Global System-Relevant Technologies—Storage and Dispatch

The global results of introducing system-relevant technologies are shown in Table 8.8. The first part of this section documents the required power plant markets, the changes and configurations of power-generation systems, and the development of loads in response to high electrification rates in the industry, heating, and transport sectors. The next step in the analysis documents the storage and dispatch demands and possible technology utilization. It is important to note that the results presented here are not cost-optimized. The mixture of battery storage and pumped hydropower plants with hydrogen- and synthetic-fuel-based dispatch power plants presented here represents only one option of many.

Significant simplification is required for the computer simulations of large regions, to reduce the data volumes (and calculation times) or simply because there is not yet any data, because several regions still have no electricity infrastructure in place. Detailed modelling requires access to detailed data. Although the modelling tools used for this analysis could be used to develop significantly more-detailed regional analyses, this is beyond the scope of this research.

The basic concept for the management of power system generation is based on four principles:

Diversity;

Flexibility;

Inter-sectorial connectivity;

Resource efficiency.

Diversity

in the locally deployed renewable power-generation structure. For example, a combination of onshore and offshore wind with solar PV and CSP plants will reduce storage and dispatch demands.

Flexibility

involves a significant number of fast-reacting dispatch power plants operated with fuels produced from renewable electricity (hydrogen and synthetic fuels). The existing gas infrastructure can be further utilized to avoid stranded investments, and the actual fuel production can also be used—with some technical limitations—for load management, which again will reduce the need for storage technologies.

Inter-sectorial connectivity

involves the connection of the heating (including process heat) and transport sectors. Neither the transport sector nor the heating sector will undergo complete electrification. To supply industrial process heat, the capacity of co-generation plants—operated with bio-, geothermal, or hydrogen fuels—will be increased by a factor of 2.5 in the 1.5 °C Scenario. Co-generation heating systems with heat storage capacities and heat pumps operated with renewable electricity will lead to more flexibility in the management of both load and demand. However, an analysis of the full potential for these heating systems was not within the scope of this project, so they have not been included in the modelling. Further research with localized data is required.

Resource efficiency

In addition to energy and GHG modelling, a resource assessment of selected metals has been undertaken (see Chap. 11). A variety of technologies—especially storage technologies—can be used to reduce the pressure on resource requirements, namely for cobalt and lithium for batteries and electric mobility and the silver required for solar technologies. Therefore, the choice of storage technologies has taken the specific requirements for metals into account.

Table 8.11 shows the storage volumes (in GWh per year) required to avoid the curtailment of variable renewable power generation and the utilization of storage capacities for batteries and pumped hydro for charging with variable renewable electricity in the calculated scenarios. The total storage throughput, including the hydrogen production and the amount of hydrogen-based dispatch power plants, is also shown.

Table 8.11

Global: storage and dispatch

Storage and dispatch		2.0 °C					1.5 °C
World		Required to avoid curtailment	Utilization battery -charge-	Utilization PSH -charge-	Total (incl. H2)	Dispatch H2	Required to avoid curtailment	Utilization battery -charge-	Utilization PSH -charge-	Total (incl. H2)	Dispatch H2
World		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
OECD North America	2020	0	0	0	0	0	0	0	0	0	0
	2030	62,369	341	192	1065	11,181	243,235	243,235	475	2405	11,181
	2050	853,401	21,805	868	45,331	238,730	999,704	999,704	924	46,766	238,730
Latin America	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	34	1207	1207	99	318	34
	2050	1314	640	34	1347	127,226	30,526	30,526	621	12,875	127,226
OECD Europe	2020	0	0	0	0	0	0	0	0	0	0
	2030	6238	315	5265	11,161	60,223	38,504	38,504	20,566	42,827	60,223
	2050	212,060	30,546	58,368	177,632	814,585	301,234	301,234	72,812	215,641	814,585
Middle East	2020	0	0	0	0	0	0	0	0	0	0
	2030	18,088	2	943	1890	0	44,945	44,945	1469	2943	0
	2050	752,882	109	4636	9180	0	554,222	554,222	4371	8618	0
Africa	2020	0	0	0	0	0	0	0	0	0	0
	2030	4877	118	2244	4726	0	11,264	11,264	2672	5591	0
	2050	367,201	6514	8977	30,974	212,902	585,423	585,423	9282	31,210	212,902
Eurasia	2020	0	0	0	0	0	0	0	0	0	0
	2030	736	1	169	341	14,106	6031	6031	644	1295	14,106
	2050	296,490	948	8396	18,661	401,044	249,984	249,984	7258	16,303	401,044
Non-OECD Asia	2020	0	0	0	0	0	0	0	0	0	0
	2030	137	2	15	34	0	6848	6848	311	646	0
	2050	171,973	2478	2261	9465	386,454	228,160	228,160	2943	8789	386,454
India	2020	0	0	0	0	0	0	0	0	0	0
	2030	59,399	52	2983	6069	1759	182,561	182,561	8577	17,487	1759
	2050	372,809	2125	6715	17,678	28,113	437,884	437,884	6595	17,199	28,113
China	2020	0	0	0	0	0	0	0	0	0	0
	2030	1102	19	394	827	2582	45,217	45,217	7266	14,957	2582
	2050	102,042	57,483	2966	120,899	623,254	264,729	264,729	20,885	60,022	623,254
OECD Pacific	2020	16	0	0	0	0	16	16	0	0	0
	2030	84,079	623	4601	10,403	831	146,440	146,440	6688	14,855	831
	2050	654,287	70,404	14,815	170,431	81,215	760,962	760,962	14,865	169,093	81,215
Total global	2020	16	0	0	0	0	16	0	0	0	0
	2030	237,026	1474	16,808	36,517	90,716	726,252	2945	48,767	103,323	90,716
	2050	3,784,459	193,051	108,037	601,598	2,913,522	4,412,827	153,528	140,555	586,516	2,913,522

Pumped hydropower will remain the backbone of the storage concept until 2030, when batteries start to overtake pumped hydropower by volume. The model does not distinguish between different battery or pumped hydro technologies. Hydrogen-based dispatch will remain the largest contributor to systems services after 2030 until the end of the modelling period.

8.4.5 Global: Required Storage Capacities for the Stationary Power Sector

The world market for storage and dispatch technologies and services will increase significantly in the 2.0 °C Scenario. The annual market for new hydro pump storage plants will grow on average by 6 GW per year to a total capacity of 244 GW in 2030. During the same period, the total installed capacity for batteries will grow to 12 GW, requiring an annual market of 1 GW. Between 2030 and 2050, the energy service sector for storage and storage technologies must accelerate further. The battery market must grow by an annual installation rate of 22 GW, and as a result, it will overtake the global capacity of pumped hydro between 2040 and 2050. The conversion of the gas infrastructure from natural gas to hydrogen and synthetic fuels will start slowly between 2020 and 2030, with the conversion of power plants with an annual capacity of around 2 GW. However, after 2030, the transformation of the global gas industry to hydrogen will accelerate significantly, with a total of 197 GW of gas power plants and gas co-generation capacity converted each year. In parallel, the average capacity factor for gas and hydrogen plants will decrease from 29% (2578 h/year) in 2030 to 11% (975 h/year) by 2050, turning the gas sector from a supply-driven to a service-driven industry.

At around 2030, the 1.5 °C Scenario requires more storage throughput than does the 2.0 °C Scenario, but storage demands for the two scenarios will be equal at the end of the modelling period. It is assumed that this higher throughput can be managed with equally high installed capacities, leading to annual capacity factors for battery and hydro pump storage of around 5–6% by 2050 (Table 8.12).

Table 8.12

Required increases in storage capacities until 2050

		Global storage and H2-dispatch market volume under 2 scenarios
		Batteries		Storage technology share	Pumped hydro		Storage technology share	Hydrogen -production + dispatch
		[Through-put]	Cumulative capacity	Storage technology share	[Through-put]	Cumulative capacity	Storage technology share	[Through-put]	Cumulative capacity
		[GWh/year]	[GW]	[%]	[GWh/year]	[GW]	[%]	[GWh/year]	[GW]
2015		No data	2	1	No data	153	99		No data
2030	2.0 °C	1474	12	8	16,808	244	92	90,716	35
2030	1.5 °C	2945	13	6	48,767	255	94	351,496	137
2050	2.0 °C	193,051	347	64	108,037	267	36	2,913,522	2990
2050	1.5 °C	153,528	340	52	140,555	278	48	2,075,533	3423

Table 8.13 shows the average global investment costs for the battery and hydro pump storage capacities in the 2.0 °C and 1.5 °C Scenarios. Both pathways have equal storage capacities and cost projections, especially for batteries, but are highly uncertain in the years beyond 2025. Therefore, the costs are only estimates and require research.

Table 8.13

Estimated average global investment costs for batty and hydro pump storage

Estimated storage investment costs (In $ billion)	2015–2020	Average annual	2021–2030	Average annual	2031–2040	Average annual	2041–2050	Average annual	2015–2050	Average annual
Storage
Battery	4.8	0.967	44.5	4.4	148.1	14.8	655.8	65.6	853.3	24.4
Hydro pump storage	0	0	38.7	3.9	42.7	4.3	47.2	4.7	128.6	3.7
Total	4.8	0.967	83.2	8.3	190.8	19.1	703.0	70.3	981.9	28.1

8.5 OECD North America

8.5.1 OECD North America: Long-Term Energy Pathways

8.5.1.1 OECD North America: Final Energy Demand by Sector

Combining the assumptions for population growth, GDP growth, and energy intensity will result in the development pathways for OECD North America’s final energy demand shown in Fig. 8.17 under the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. Under the 5.0 °C Scenario, the total final energy demand will increase by 10% from the current 70,500 PJ/year to 77,800 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will decrease by 47% compared with current consumption and will reach 37,300 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will reach 33,700 PJ, 52% below the 2015 demand level. In the 1.5 °C Scenario, the final energy demand in 2050 will be 10% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will decrease from 4230 TWh/year in 2015 to 3340 TWh/year (2.0 °C) or 2950 TWh/year (1.5 °C) by 2050. Compared with the 5.0 °C case (6050 TWh/year in 2050), the efficiency measures in the 2.0 °C and 1.5 °C Scenarios will save a maximum of 2710 TWh/year and 3100 TWh/year, respectively.

Electrification will lead to a significant increase in the electricity demand by 2050. The 2.0 °C Scenario will require approximately 1400 TWh/year of electricity for electric heaters and heat pumps, and in the transport sector, it will require approximately 3300 TWh/year for electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 3000 TWh/year. Therefore, the gross power demand will rise from 5300 TWh/year in 2015 to 9500 TWh/year in 2050 in the 2.0 °C Scenario, 30% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 9400 TWh/year in 2050 for similar reasons.

The efficiency gains in the heating sector will be similar in magnitude to those in the electricity sector. Under the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 7000 PJ/year and 9400 PJ/year, respectively, will be avoided by 2050 through efficiency gains compared with the 5.0 °C Scenario.

8.5.1.2 OECD North America: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power from renewable sources. In the 2.0 °C Scenario, 100% of the electricity produced in OECD North America will come from renewable energy sources by 2050. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 85% of the total electricity generated. Renewable electricity’s share of the total production will be 68% by 2030 and 89% by 2040. The installed capacity of renewables will reach about 1880 GW by 2030 and 3810 GW by 2050. In the 1.5 °C Scenario, the share of renewable electricity generation in 2030 is assumed to be 84%. The 1.5 °C Scenario projects a generation capacity from renewable energy of about 3920 GW in 2050.

Table 8.14 shows the development of the installed capacities of different renewable technologies in OECD North America over time. Figure 8.18 provides an overview of the overall power-generation structure in OECD North America. From 2020 onwards, the continuing growth of wind and PV—to 1090 GW and 2130 GW, respectively—is complemented by up to 210 GW of solar thermal generation, as well as limited biomass, geothermal, and ocean energy, in the 2.0 °C Scenario. Both the 2.0 °C and 1.5 °C Scenarios will lead to a high proportion of variable power generation (PV, wind, and ocean) of 49% and 59%, respectively, by 2030, and 73% and 74%, respectively, by 2050.

Table 8.14

OECD North America: development of renewable electricity generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	194	202	207	216	217
	2.0 °C	194	199	202	206	206
	1.5 °C	194	199	202	203	203
Biomass	5.0 °C	22	25	27	30	35
	2.0 °C	22	27	32	42	52
	1.5 °C	22	35	39	43	45
Wind	5.0 °C	87	157	172	197	253
	2.0 °C	87	323	540	812	1092
	1.5 °C	87	358	656	924	1059
Geothermal	5.0 °C	5	5	6	9	12
	2.0 °C	5	6	9	23	37
	1.5 °C	5	5	8	25	37
PV	5.0 °C	29	133	162	220	358
	2.0 °C	29	534	991	1419	2129
	1.5 °C	29	659	1097	1783	2269
CSP	5.0 °C	2	2	3	4	12
	2.0 °C	2	22	87	168	209
	1.5 °C	2	39	148	257	236
Ocean	5.0 °C	0	0	1	2	4
	2.0 °C	0	3	15	59	85
	1.5 °C	0	2	13	52	66
Total	5.0 °C	338	523	577	678	891
	2.0 °C	338	1115	1878	2729	3810
	1.5 °C	338	1298	2163	3288	3916

8.5.1.3 OECD North America: Future Costs of Electricity Generation

Figure 8.19 shows the development of the electricity-generation and supply costs over time, including CO₂ emission costs, in all scenarios. The calculated electricity-generation costs in 2015 (referring to full costs) were around 4.9 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2050, when they reach 10.1 ct/kWh. The generation costs in the 2.0 °C Scenario will increase in a similar way until 2030, when they reach 8.3 ct/kWh, and then drop to 6.8 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 8.8 ct/kWh and then drop to 7.1 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs in 2050 are 3.3 ct/kWh lower than in the 5.0 °C case. In the 1.5 °C Scenario, the generation costs in 2050 are 3.1 ct/kWh lower than in the 5.0 °C case. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

Under the 5.0 °C case, the growth in demand and increasing fossil fuel prices will result in an increase in total electricity supply costs from today’s $270 billion/year to more than $760 billion/year in 2050. In both alternative scenarios, the total supply costs in 2050 will be around $690 billion/year The long-term costs for electricity supply in 2050 will be 8%–9% lower than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility.

Compared with these results, the generation costs when the CO₂ emission costs are not considered will increase in the 5.0 °C case to 7.5 ct/kWh. In the 2.0 °C Scenario, they will increase until 2030, when they reach 7.3 ct/kWh, and then drop to 6.8 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 8.4 ct/kWh in 2030, and then drop to 7.1 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs will be, at maximum, 1 ct/kWh higher than in the 5.0 °C case, and this will occur in 2030. In the 1.5 °C Scenario, compared with the 5.0 °C Scenario, the maximum difference in generation costs will be 2 ct/kWh in 2030. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will increase to $570 billion/year in 2050.

8.5.1.4 OECD North America: Future Investments in the Power Sector

An investment of around $7600 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including additional power plants for the production of hydrogen and synthetic fuels and investments in plant replacement after the end of their economic lifetimes. This value is equivalent to approximately $211 billion per year on average, which is $4400 billion more than in the 5.0 °C case ($3200 billion). In the 1.5 °C Scenario, an investment of around $8180 billion for power generation will be required between 2015 and 2050. On average, this is an investment of $227 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will be around 48% of the total cumulative investments, whereas approximately 52% will be invested in renewable power generation and co-generation (Fig. 8.20). However, under the 2.0 °C (1.5 °C) Scenario, OECD North America will shift almost 93% (93%) of its entire investment to renewables and co-generation. By 2030, the fossil fuel share of the power sector investment will mainly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $3240 billion in 2050, equivalent to $90 billion per year. Therefore, the total fuel cost savings will be equivalent to 70% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $3910 billion, or $109 billion per year.

8.5.1.5 OECD North America: Energy Supply for Heating

The final energy demand for heating will increases in the 5.0 °C Scenario by 32%, from 19,700 PJ/year in 2015 to 26,000 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 27% by 2050 in the 2.0 °C Scenario relative to the 5.0 °C case, and by 36% in the 1.5 °C Scenario. Today, renewables supply around 11% of OECD North America’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 38% of OECD North America’s total heat demand in 2030 in the 2.0 °C Scenario and 61% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.21 shows the development of different technologies for heating in OECD North America over time, and Table 8.15 provides the resulting renewable heat supply for all scenarios. Until 2030, biomass will remain the main contributor. The growing use of solar, geothermal, and environmental heat will lead, in the long term, to a biomass share of 25% under the 2.0 °C Scenario and 19% under the 1.5 °C Scenario. Heat from renewable hydrogen will further reduce the dependence on fossil fuels under both scenarios. Hydrogen consumption in 2050 will be around 3000 PJ/year in the 2.0 °C Scenario and 2700 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of 4.6–4.9 between 2015 and 2050 and will have a final energy share of 21% in 2050 in the 2.0 °C Scenario and 26% in the 1.5 °C Scenario.

Table 8.15

OECD North America: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	1868	2142	2334	2787	3279
	2.0 °C	1868	2758	3019	3493	3686
	1.5 °C	1868	2707	3149	3191	2378
Solar heating	5.0 °C	107	210	277	451	695
	2.0 °C	107	887	1772	2639	2962
	1.5 °C	107	1290	2169	2839	3128
Geothermal heat and heat pumps	5.0 °C	17	17	18	18	19
	2.0 °C	17	875	1378	3031	5257
	1.5 °C	17	1076	2185	3463	4152
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	144	276	1014	3045
	1.5 °C	0	22	677	2100	2666
Total	5.0 °C	1991	2369	2629	3256	3994
	2.0 °C	1991	4664	6445	10,176	14,949
	1.5 °C	1991	5095	8180	11,592	12,324

8.5.1.6 OECD North America: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 will amount to around $2580 billion in the 2.0 °C Scenario (including investments for plant replacement after their economic lifetimes) or approximately $72 billion per year. The largest share of investment in OECD North America is assumed to be for heat pumps (around $1300 billion), followed by solar collectors and biomass technologies. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies, resulting in a lower average annual investment of around $78 billion per year (Table 8.16, Fig. 8.22).

Table 8.16

OECD North America: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	292	315	330	366	411
	2.0 °C	292	381	387	355	272
	1.5 °C	292	360	384	334	179
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	17	30	44	52
	1.5 °C	0	34	57	82	109
Solar heating	5.0 °C	29	58	76	124	191
	2.0 °C	29	232	466	697	780
	1.5 °C	29	331	557	728	793
Heat pumps	5.0 °C	3	3	3	3	3
	2.0 °C	3	123	188	393	677
	1.5 °C	3	143	292	479	568
Total^a	5.0 °C	324	375	410	494	605
	2.0 °C	324	752	1071	1489	1781
	1.5 °C	324	868	1290	1622	1649

^a Excluding direct electric heating

8.5.1.7 OECD North America: Transport

Energy demand in the transport sector in OECD North America is expected to decrease by 8% in the 5.0 °C Scenario, from around 31,000 PJ/year in 2015 to 28,600 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 73% (20,970 PJ/year) in 2050 compared with the 5.0 °C case. Additional modal shifts, technology switches, and a reduction in transport demand will lead to even higher energy savings in the 1.5 °C Scenario, of 74% (or 21,100 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.17, Fig. 8.23).

Table 8.17

OECD North America: projection of the transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	674	628	609	570	529
	2.0 °C	674	660	655	523	516
	1.5 °C	674	743	730	773	806
Road	5.0 °C	26,686	25,691	24,838	24,222	23,414
	2.0 °C	26,686	21,257	15,933	7731	5124
	1.5 °C	26,686	18,612	11,973	6717	5251
Domestic aviation	5.0 °C	2421	2978	3274	3398	3186
	2.0 °C	2421	2309	2026	1530	1242
	1.5 °C	2421	2167	1689	1063	840
Domestic navigation	5.0 °C	461	482	493	514	535
	2.0 °C	461	481	489	489	473
	1.5 °C	461	479	484	483	473
Total	5.0 °C	30,241	29,779	29,214	28,704	27,664
	2.0 °C	30,241	24,707	19,104	10,273	7354
	1.5 °C	30,241	22,000	14,875	9036	7370

By 2030, electricity will provide 11% (620 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, and in 2050, the share will be 44% (930 TWh/year). In 2050, up to 2090 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 1030 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 2020 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of 2540 PJ/year Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 270 PJ/year in 2050. Because the reduction in fossil fuel for transport will be faster, biofuel use will increase in the 1.5 °C Scenario to a maximum of 5900 PJ/year. The demand for synthetic fuels will decrease to zero by 2050 in the 1.5 °C Scenario because of the lower overall energy demand by transport.

8.5.1.8 OECD North America: Development of CO₂ Emissions

In the 5.0 °C Scenario, OECD North America’s annual CO₂ emissions will decrease by 9% from 6170 Mt. in 2015 to 5612 Mt. in 2050. Stringent mitigation measures in both the alternative scenarios will lead to reductions in annual emissions to 930 Mt. in 2040 in the 2.0 °C Scenario and to 120 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 216 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 99 Gt and 72 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 54% in the 2.0 °C Scenario and by 67% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid decrease in the annual emissions will occur under both alternative scenarios. In the 2.0 °C Scenario, the reduction will be greatest in ‘Power generation’, followed by the ‘Transport’ and ‘Residential and other’ sectors (Fig. 8.24).

8.5.1.9 OECD North America: Primary Energy Consumption

Taking into account the assumptions discussed above, the levels of primary energy consumption under the three scenarios are shown in Fig. 8.25. In the 2.0 °C Scenario, the primary energy demand will decrease by 46%, from around 111,600 PJ/year in 2015 to 60,600 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 50% by 2050 in the 2.0 °C Scenario (5.0 °C: 121,000 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (56,600 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. As a result, renewable energy will have a primary energy share of 34% in 2030 and 91% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary share of more than 91% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out by 2040 under both the 2.0 °C and the 1.5 °C Scenarios. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 1290 EJ, the cumulative coal consumption to about 470 EJ, and the crude oil consumption to 1300 EJ. In contrast, in the 2.0 °C Scenario, the cumulative gas demand will amount to 730 EJ, the cumulative coal demand to 120 EJ, and the cumulative oil demand to 640 EJ. Even lower cumulative fossil fuel use will be achieved in the 1.5 °C Scenario: 480 EJ for natural gas, 80 EJ for coal, and 440 EJ for oil.

8.5.2 Regional Results: Power Sector Analysis

The key results for all 10 world regions and their sub-regions are presented in this section, with standardized tables to make them comparable for the reader. Regional differences and particularities are summarized. It is important to note that the electricity loads for the sub-regions—which are in several cases also countries—are calculated (see Chap. 3) and are not real measured values. When information was available, the model results are compared with published peak loads and adapted as far as possible. However, deviations of 10% or more for the base year are in the range of the probability. The interconnection capacities between sub-regions are simplified assumptions based on current practices in liberalized power markets, and include cross-border trade (e.g., between Canada and the USA) (C2ES 2017) or within the European Union (EU). The EU set a target of 10% interconnection capacity between their member states in 2002 (EU-EG 2017). The interconnection capacities for sub-regions that are not geographically connected are set to zero for the entire modelling period, even when there is current discussion about the implementation of new interconnections, such as for the ASEAN Power Grid (ASEAN-CE 2018).

8.5.3 OECD North America: Power Sector Analysis

The OECD North America region includes Canada, the USA, and Mexico, and therefore contains more than one large electricity market. Although the power sector is liberalized in all three countries, the state of implementation and the market rules in place vary significantly. Even within the USA, each state has different market rules and grid regulations. Therefore, the calculated scenarios assume the priority dispatch of all renewables and priority grid connections for new renewable power plants, and a streamlined process for required construction permits. The power sector analysis for all regions is based on technical, not political, considerations.

8.5.3.1 OECD North America: Development of Power Plant Capacities

The size of the renewable power market in OECD North America will increase significantly in the 2.0 °C Scenario. The annual market for solar PV must increase from 22.76 GW in 2020 by a factor of 5 to an average of 95 GW by 2030. The onshore wind market must expand to 35 GW by 2025, an increase from around 13 GW 5 years earlier. By 2050, offshore wind generation will increase to 9.7 GW annually, by a factor of 7 compared with the base year (2015). Concentrated solar power plants will play an important role in dispatchable solar electricity generation to supply bulk power, especially for industry and industrial process heat. The annual market in 2030 will increase to 16 GW, compared with 1.7 GW in 2020. The 1.5 °C Scenario accelerates both the phase-out of fossil-fuel-based power generation and the deployment of renewables—mainly solar PV and wind in the first decade—about 5–7 years faster than the 2.0 °C Scenario (Table 8.18).

Table 8.18

OECD North America: average annual change in installed power plant capacity

Power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	−7	−16	−6	−8	−4	0
Lignite	−14	−18	−7	0	0	0
Gas	6	9	12	1	−55	−4
Hydrogen-gas	1	10	4	24	55	39
Oil/diesel	−5	−7	−3	−4	−1	0
Nuclear	−4	−9	−10	−10	0	−1
Biomass	1	2	1	1	1	0
Hydro	−5	−3	0	0	0	2
Wind (onshore)	24	48	36	36	24	19
Wind (offshore)	2	19	11	19	10	3
PV (roof top)	39	94	64	68	61	55
PV (utility scale)	13	31	21	23	20	18
Geothermal	0	0	1	1	2	2
Solar thermal power plants	3	18	15	18	6	4
Ocean energy	1	2	4	4	4	3
Renewable fuel based co-generation	1	2	2	2	2	0

8.5.3.2 OECD North America: Utilization of Power-Generation Capacities

Table 8.19 shows the increasing shares of variable renewable power generation across all North American regions. Whereas Alaska and Canada are dominated by variable wind power generation, Mexico and the sunny mid-west of the USA have significant contributions from CSP. Solar PV is distributed evenly across the entire region. Onshore and offshore wind penetration is highest in rural areas, whereas solar roof-top power generation is highest in suburban regions where roof space and electricity demand from residential buildings correlate best. The south-west of the USA will have the highest share of variable renewables—mainly solar PV for residual homes and office buildings, connected to battery systems. There are no structural differences between the 2.0 °C and 1.5 °C Scenarios, except faster implementation in the latter. It is assumed that all regions will have an interconnection capacity of 20% of the regional average load, with which to exchange renewable and dispatch electricity to neighbouring regions.

Table 8.19

OECD North America and sub-regions: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
OECD North America		Variable RE	Dispatch RE	Dispatch fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch fossil	Inter-connection
USA Alaska	2015	4%	35%	61%	10%
	2030	29%	31%	40%	15%	36%	30%	34%	15%
	2050	42%	23%	35%	20%	42%	26%	32%	20%
Canada West	2015	6%	35%	59%	10%
	2030	43%	30%	27%	15%	53%	28%	19%	15%
	2050	63%	21%	16%	20%	63%	23%	14%	20%
Canada East	2015	7%	35%	59%	10%
	2030	45%	30%	25%	15%	56%	27%	16%	15%
	2050	66%	21%	13%	20%	66%	23%	11%	20%
USA North East	2015	7%	35%	58%	10%
	2030	47%	31%	22%	15%	58%	28%	14%	15%
	2050	69%	20%	11%	20%	69%	22%	9%	20%
USA North West	2015	4%	35%	61%	10%
	2030	36%	32%	32%	15%	47%	30%	23%	15%
	2050	59%	23%	18%	20%	59%	25%	16%	20%
USA South West	2015	7%	35%	58%	10%
	2030	53%	28%	19%	15%	64%	25%	11%	15%
	2050	73%	17%	10%	20%	73%	18%	8%	20%
USA South East	2015	8%	35%	58%	10%
	2030	53%	28%	19%	15%	63%	25%	12%	15%
	2050	71%	18%	11%	20%	71%	20%	9%	20%
Mexico	2015	5%	35%	61%	10%
	2030	37%	30%	32%	15%	46%	28%	26%	15%
	2050	56%	23%	22%	20%	55%	25%	19%	20%
OECD North America	2015	7%	35%	58%
	2030	48%	30%	23%		59%	27%	15%
	2050	68%	19%	13%		68%	21%	11%

Capacity factors for the five generation types and the resulting average utilization are shown in Table 8.20. Compared with the global average, North America will start with a capacity factor for limited dispatchable generation of about 10% over the global average. By 2050, the average capacity factor across all power-generation types will be 29% for both scenarios. A low average capacity factor requires flexible power plants and a power market framework that incentivizes them.

Table 8.20

OECD North America: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
OECD North America			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity Factor – average	[%/yr]	53.1%	35%	33%	29%	28%	34%	28%	29%	29%
Limited dispatchable: fossil and nuclear	[%/yr]	68.6%	40%	10%	28%	2%	20%	6%	10%	10%
Limited dispatchable: renewable	[%/yr]	45.9%	46%	57%	37%	39%	59%	36%	36%	35%
Dispatchable: fossil	[%/yr]	39.7%	23%	21%	11%	5%	30%	8%	12%	11%
Dispatchable: renewable	[%/yr]	44.0%	52%	68%	49%	52%	47%	44%	49%	45%
Variable: renewable	[%/yr]	18.9%	12%	12%	25%	26%	34%	27%	28%	28%

8.5.3.3 OECD North America: Development of Load, Generation, and Residual Load

Table 8.21 shows the development of the maximum load, generation, and resulting residual load (the load remaining after variable renewable generation). With increased shares of variable solar PV and wind power, the minimum residual load can become negative. If this happens, the surplus generation can either be exported to other regions, stored, or curtailed. The export of load to other regions requires transmission lines. If the theoretical utilization rate of transmission cables (= interconnection) exceeds 100%, the transport capacity must be increased. We assume that the entire load need not be exported, and that surplus generation capacities can be curtailed because interconnections are costly and require a certain level of utilization to make them economically viable. An analysis of the economic viability of new interconnections and their optimal transmission capacities is beyond the scope of this research project.

Table 8.21

OECD North America: load, generation, and residual load development

Power generation structure		2.0 °C				1.5 °C
OEC D North America		Max demand	Max generation	Max Residual Load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
OEC D North America		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
NA – USA Alaska	2020	1.4	1.4	0.0		1.4	18.8	0.1
	2030	1.5	1.5	0.1	0	1.6	13.5	0.3	12
	2050	2.4	11.8	0.5	9	2.4	11.5	0.5	9
NA – Canada West	2020	21.1	21.1	0.0		21.2	34.0	0.3
	2030	23.0	31.2	5.7	3	24.5	39.8	4.6	11
	2050	37.2	73.1	15.2	21	37.3	76.4	15.3	24
NA – Canada East	2020	53.0	53.0	0.0		53.1	117.3	0.8
	2030	58.0	88.0	14.6	15	61.6	117.5	15.3	40
	2050	94.3	213.7	41.2	78	94.6	223.0	41.0	87
NA – USA North East	2020	258.6	243.6	29.9		259.5	273.2	21.8
	2030	288.5	355.7	47.7	20	304.2	468.8	63.5	101
	2050	433.0	853.7	175.3	246	434.6	891.6	176.7	280
NA – USA North West	2020	25.6	25.6	0.0		25.7	81.1	2.2
	2030	28.5	30.6	5.9	0	30.1	40.8	6.0	5
	2050	42.5	74.3	16.0	16	42.7	77.7	16.1	19
NA – USA South West	2020	109.4	109.1	4.6		109.8	167.5	9.3
	2030	121.8	163.0	11.8	29	128.5	208.8	20.0	60
	2050	181.8	384.2	38.3	164	182.4	402.3	42.0	178
NA – USA South East	2020	217.7	217.7	0.4		217.4	232.1	15.3
	2030	255.8	372.6	38.0	79	270.9	490.7	64.7	155
	2050	393.3	890.9	102.6	395	394.5	927.6	122.3	411
Mexico	2020	66.6	51.3	22.3
	2030	87.2	116.1	21.3	8	97.6	151.9	19.8	35
	2050	171.9	277.1	80.5	25	173.3	289.7	81.9	34

In Alaska in the 2.0 °C Scenario, for example, generation and demand are balanced in 2020 and 2030, but peak generation is substantially higher than demand in 2050. In the 1.5 °C Scenario, a significant level of overproduction is achieved by 2030. In the two scenarios, the surplus peak generation is equally high. These results have been calculated under the assumption that surplus generation will be stored in a cascade of batteries and pumped-storage hydroelectricity (PSH) or used to produce hydrogen and/or synthetic fuels. Therefore, the maximal interconnection requirements shown in this chapter represent the maximum surplus generation capacity. To avoid curtailment, these overcapacities have mainly been used for hydrogen production. Therefore, Alaska could remain an energy exporter but switch from oil to wind-generated synthetic gas and/or hydrogen.

Table 8.22 provides an overview of the calculated storage and dispatch power requirements by sub-region. To store or export the entire electricity output during each production peak would require significant additional investment. Therefore, it is assumed that not all surplus solar and wind generation must be stored, and that up to 5% (in 2030) and 10% (in 2050) of the annual production can be curtailed without significant economic disadvantage. We assume that regions with favourable wind and solar potentials, and advantages regarding available space, will use their overcapacities to export electricity via transmission lines and/or to produce synthetic and/or hydrogen fuels.

Table 8.22

OECD North America: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
OECD North America		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total Storage demand (incl. H2)	Dispatch Hydrogen-based
OECD North America		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
USA Alaska	2020	0	0	0	0	0	0	0	0	0	0
	2030	11	0	0	0	136	68	1	1	2	136
	2050	328	38	1	39	542	407	41	1	42	542
Canada West	2020	0	0	0	0	0	0	0	0	0	0
	2030	1011	14	7	21	1957	4078	31	18	49	1957
	2050	14,665	1044	34	1078	7776	17,557	1100	38	1137	7776
Canada East	2020	0	0	0	0	0	0	0	0	0	0
	2030	3014	38	20	58	4482	13,352	82	53	135	4482
	2050	42,780	2545	91	2636	18,129	50,077	2623	97	2720	18,129
USA North East	2020	0	0	0	0	0	0	0	0	0	0
	2030	9092	148	73	221	17,290	50,047	404	239	643	17,290
	2050	212,448	13,990	509	14,499	60,398	252,243	14,457	546	15,004	60,398
USA North West	2020	0	0	0	0	0	0	0	0	0	0
	2030	90	4	1	5	2394	1854	26	13	39	2394
	2050	11,806	1013	33	1046	8707	14,933	1085	37	1122	8707
USA South West	2020	0	0	0	0	0	0	0	0	0	0
	2030	10,722	121	68	189	6370	47,636	238	172	410	6370
	2050	172,771	6661	301	6962	22,741	201,316	6894	316	7210	22,741
USA South East	2020	0	0	0	0	0	0	0	0	0	0
	2030	35,827	320	195	516	15,281	115,409	579	402	981	15,281
	2050	372,747	15,600	690	16,290	53,958	429,227	15,734	725	16,459	53,958
Mexico	2020	0	0	0	0	0	0	0	0	0	0
	2030	2604	37	18	55	7792	10,790	95	52	147	7792
	2050	25,855	2706	75	2781	32,716	33,945	2985	86	3071	32,716
OECD North America	2020	0	0	0	0	0	0	0	0	0	0
	2030	62,369	682	384	1065	55,702	243,235	1456	949	2405	55,702
	2050	853,401	43,597	1735	45,331	204,967	999,704	44,919	1846	46,766	204,967

The southern part of the USA will achieve a significant solar PV share by 2050 and storage demand will be highest in this region. Storage and dispatch demand will increase in all sub-regions between 2025 and 2035. Before 2025, storage demand will be zero in all regions.

8.6 Latin America

8.6.1 Latin America: Long-Term Energy Pathways

8.6.1.1 Latin America: Final Energy Demand by Sector

Combining the assumptions on population growth, GDP growth, and energy intensity will produce the future development pathways for Latin America’s final energy demand shown in Fig. 8.26 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. Under the 5.0 °C Scenario, the total final energy demand will increase by 70% from the current 19,200 PJ/year to 32,600 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will decrease by 11% compared with current consumption and will reach 17,000 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will fall to 15,800 PJ in 2050, 18% below the 2015 demand. In the 1.5 °C Scenario, the final energy demand in 2050 will be 7% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will increase from 740 TWh/year in 2015 to around 1560 TWh/year in 2050 in both alternative scenarios, around 300 TWh/year lower than in the 5.0 °C Scenario (1860 TWh/year in 2050).

Electrification will lead to a significant increase in the electricity demand by 2050. In the 2.0 °C Scenario, the electricity demand for heating will be about 600 TWh/year due to electric heaters and heat pumps, and in the transport sector an increase of approximately 1700 TWh/year will be caused by electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 600 TWh/year. The gross power demand will thus increase from 1300 TWh/year in 2015 to 3500 TWh/year in 2050 in the 2.0 °C Scenario, 25% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 3800 TWh/year in 2050.

Efficiency gains in the heating sector could be even larger than in the electricity sector. Under the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 4300 PJ/year will be avoided through efficiency gains in both scenarios by 2050 compared with the 5.0 °C Scenario.

8.6.1.2 Latin America: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power coming from renewable sources. By 2050, 100% of the electricity produced in Latin America will come from renewable energy sources in the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 63% of the total electricity generation. Renewable electricity’s share of the total production will be 87% by 2030 and 96% by 2040. The installed capacity of renewables will reach about 530 GW by 2030 and 1030 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario will be 91%. In the 1.5 °C Scenario, the generation capacity from renewable energy will be approximately 1210 GW in 2050.

Table 8.23 shows the development of different renewable technologies in Latin America over time. Figure 8.27 provides an overview of the overall power-generation structure in Latin America. From 2020 onwards, the continuing growth of wind and PV, up to 230 GW and 410 GW, respectively, will be complemented by up to 60 GW solar thermal generation, as well as limited biomass, geothermal, and ocean energy, in the 2.0 °C Scenario. Both the 2.0 °C and 1.5 °C Scenarios will lead to a high proportion of variable power generation (PV, wind, and ocean) of 31% and 39%, respectively, by 2030, and 52% and 57%, respectively, by 2050.

Table 8.23

Latin America: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	161	200	222	269	302
	2.0 °C	161	180	180	183	184
	1.5 °C	161	180	180	183	184
Biomass	5.0 °C	18	23	25	29	34
	2.0 °C	18	43	57	75	89
	1.5 °C	18	43	61	75	81
Wind	5.0 °C	11	31	38	50	66
	2.0 °C	11	56	95	199	234
	1.5 °C	11	67	134	272	285
Geothermal	5.0 °C	1	1	2	3	4
	2.0 °C	1	3	5	12	18
	1.5 °C	1	3	5	12	15
PV	5.0 °C	2	14	19	29	42
	2.0 °C	2	108	175	295	409
	1.5 °C	2	133	237	529	537
CSP	5.0 °C	0	1	1	2	3
	2.0 °C	0	4	20	51	63
	1.5 °C	0	4	20	76	78
Ocean	5.0 °C	0	0	0	0	4
	2.0 °C	0	1	2	20	37
	1.5 °C	0	1	2	20	30
Total	5.0 °C	193	270	306	382	456
	2.0 °C	193	395	534	834	1034
	1.5 °C	193	432	640	1167	1209

8.6.1.3 Latin America: Future Costs of Electricity Generation

Figure 8.28 shows the development of the electricity-generation and supply costs over time, including CO₂ emission costs, under all scenarios. The calculated electricity-generation costs in 2015 (referring to full costs) were around 4.5 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2050, when they reach 8.3 ct/kWh. The generation costs in the 2.0 °C Scenario will increase until 2030, when they reach 7 ct/kWh, and will then drop to 5.9 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 6.7 ct/kWh, and then drop to 5.6 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs in 2050 will be 2.4 ct/kWh lower than in the 5.0 °C case. In the 1.5 °C Scenario, the maximum difference in generation costs will be 2.6 ct/kWh in 2050. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, the growth in demand and increasing fossil fuel prices will result in an increase in total electricity supply costs from today’s $70 billion/year to more than $240 billion/year in 2050. In the 2.0 °C Scenario, the total supply costs will be $230 billion/year and in the 1.5 °C Scenario, they will be $240 billion/year in 2050. The long-term costs for electricity supply will be more than 5% lower in the 2.0 °C Scenario than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility. Further electrification and synthetic fuel generation in the 1.5 °C Scenario will result in total power generation costs that are similar to the 5.0 °C case.

Compared with these results, the generation costs when the CO₂ emission costs are not considered will increase in the 5.0 °C case to 7.1 ct/kWh. In the 2.0 °C Scenario, they will increase until 2030, when they will reach 6.6 ct/kWh, and then drop to 5.9 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 6.5 ct/kWh and then drop to 5.6 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs will be maximum, at 0.25 ct/kWh higher than in the 5.0 °C case, in 2030 (0.1 ct/kWh in the 1.5 °C Scenario). The generation costs in 2050 will again be lower in the alternative scenarios than in the 5.0 °C case: 1.2 ct/kWh in the 2.0 °C Scenario and 1.5 ct/kWh in the 1.5 °C Scenario. If CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will increase to about $210 billion/year in 2050.

8.6.1.4 Latin America: Future Investments in the Power Sector

An investment of about $1920 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario, including additional power plants for the production of hydrogen and synthetic fuels and investments in plant replacement after the ends of their economic lives. This value is equivalent to approximately $53 billion per year, on average, which is $880 billion more than in the 5.0 °C case ($1040 billion). An investment of around $2190 billion for power generation will be required between 2015 and 2050 in the 1.5 °C Scenario. On average, this will be an investment of $61 billion per year. Under the 5.0 °C Scenario, the investment in conventional power plants will be around 25% of the total cumulative investments, whereas approximately 75% will be invested in renewable power generation and co-generation (Fig. 8.29).

However, under the 2.0 °C (1.5 °C) Scenario, Latin America will shift almost 94% (95%) of its entire investment to renewables and co-generation. By 2030, the fossil fuel share of the power sector investment will predominantly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $820 billion in 2050, equivalent to $23 billion per year. Therefore, the total fuel cost savings will be equivalent to 90% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $900 billion, or $25 billion per year.

8.6.1.5 Latin America: Energy Supply for Heating

The final energy demand for heating will increase in the 5.0 °C Scenario by 72%, from 7800 PJ/year in 2015 to 13,300 PJ/year in 2050. In the 2.0 °C and 1.5 °C Scenarios, energy efficiency measures will help to reduce the energy demand for heating by 32% in 2050, relative to that in the 5.0 °C Scenario. Today, renewables supply around 42% of Latin America’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 68% of Latin America’s total heat demand in 2030 in the 2.0 °C Scenario and 75% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.30 shows the development of different technologies for heating in Latin America over time, and Table 8.24 provides the resulting renewable heat supply for all scenarios. Biomass will remain the main contributor. The growing use of solar, geothermal, and environmental heat will supplement mainly fossil fuels. This will lead in the long term to a biomass share of 65% under the 2.0 °C Scenario and 50% under the 1.5 °C Scenario.

Table 8.24

Latin America: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	2684	2760	2888	3335	3622
	2.0 °C	2684	3550	3895	4412	4654
	1.5 °C	2684	3632	4007	4023	2767
Solar heating	5.0 °C	32	64	88	146	227
	2.0 °C	32	394	712	1217	1418
	1.5 °C	32	394	783	1265	1445
Geothermal heat and heat pumps	5.0 °C	0	0	0	0	0
	2.0 °C	0	133	206	458	910
	1.5 °C	0	133	204	452	930
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	4	169	220
	1.5 °C	0	0	88	473	404
Total	5.0 °C	2715	2824	2976	3480	3849
	2.0 °C	2715	4077	4817	6255	7202
	1.5 °C	2715	4159	5082	6213	5546

Heat from renewable hydrogen will further reduce the dependence on fossil fuels in both scenarios. Hydrogen consumption in 2050 will be around 200 PJ/year in the 2.0 °C Scenario and 400 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of 2–4 between 2015 and 2050 and will attain a final energy share of 20% in 2050 in the 2.0 °C Scenario and 39% in the 1.5 °C Scenario.

8.6.1.6 Latin America: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 will amount to around $580 billion in the 2.0 °C Scenario (including investments in plant replacement after their economic lifetimes), or approximately $16 billion per year. The largest share of investment in Latin America is assumed to be for solar collectors (more than $200 billion), followed by biomass technologies and heat pumps. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies, but due to the lower heat demand, the average annual investment will again be around $16 billion per year (Fig. 8.31, Table 8.25).

Table 8.25

Latin America: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	549	531	536	552	542
	2.0 °C	549	730	742	657	603
	1.5 °C	549	770	752	513	179
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	2	4	12	16
	1.5 °C	0	2	4	12	17
Solar heating	5.0 °C	7	15	20	34	52
	2.0 °C	7	91	164	281	327
	1.5 °C	7	91	181	292	333
Heat pumps	5.0 °C	0	0	0	0	0
	2.0 °C	0	13	18	36	88
	1.5 °C	0	13	18	36	89
Total^a	5.0 °C	556	546	556	585	594
	2.0 °C	556	835	929	986	1034
	1.5 °C	556	876	955	853	619

^a Excluding direct electric heating

8.6.1.7 Latin America: Transport

Energy demand in the transport sector in Latin America is expected to increase by 63% under the 5.0 °C Scenario, from around 7100 PJ/year in 2015 to 11,700 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 69% (8090 PJ/year) by 2050 relative to the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in transport demand will lead to even greater energy savings in the 1.5 °C Scenario of 77% (or 9040 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.26, Fig. 8.32).

Table 8.26

Latin America: projection of transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	90	110	122	145	163
	2.0 °C	90	113	133	157	192
	1.5 °C	90	130	145	163	224
Road	5.0 °C	6662	7486	8102	9754	10,610
	2.0 °C	6662	6424	5799	4107	3112
	1.5 °C	6662	5196	3971	2744	2161
Domestic aviation	5.0 °C	211	348	453	593	638
	2.0 °C	211	228	213	175	139
	1.5 °C	211	218	196	137	104
Domestic navigation	5.0 °C	101	104	107	113	117
	2.0 °C	101	104	107	113	117
	1.5 °C	101	104	107	113	117
Total	5.0 °C	7064	8047	8783	10,605	11,529
	2.0 °C	7064	6868	6251	4551	3559
	1.5 °C	7064	5648	4419	3157	2605

By 2030, electricity will provide 6% (110 TWh/year) of the transport sector’s total energy demand under the 2.0 °C Scenario, whereas in 2050, the share will be 47% (470 TWh/year). In 2050, up to 480 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 390 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 430 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of 1340 PJ/year Around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum of 190 PJ/year by 2050. Due to the lower overall energy demand in transport, biofuel use will be reduced in the 1.5 °C Scenario to a maximum of 1030 PJ/year The maximum synthetic fuel demand will amount to 350 PJ/year.

8.6.1.8 Latin America: Development of CO₂ Emissions

In the 5.0 °C Scenario, Latin America’s annual CO₂ emissions will increase by 48%, from 1220 Mt. in 2015 to 1806 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause the annual emissions to fall to 240 Mt. in 2040 in the 2.0 °C Scenario and to 50 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 56 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 21 Gt and 17 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 63% in the 2.0 °C Scenario and by 70% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario, the reduction will be greatest in ‘Power generation’, followed by the ‘Residential and other’ and ‘Industry’ sectors (Fig. 8.33).

8.6.1.9 Latin America: Primary Energy Consumption

The levels of primary energy consumption under the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.34. In the 2.0 °C Scenario, the primary energy demand will decrease by 2%, from around 28,400 PJ/year in 2015 to 27,900 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 38% in 2050 in the 2.0 °C Scenario (5.0 °C: 45000 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (25,700 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 55% in 2030 and 94% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will also have a primary energy share of more than 94% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out by 2035 under both the 2.0 °C and the 1.5 °C Scenarios. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 290 EJ, the cumulative coal consumption to about 60 EJ, and the crude oil consumption to 460 EJ. In contrast, in the 2.0 °C Scenario, the cumulative gas demand will amount to 130 EJ, the cumulative coal demand to 20 EJ, and the cumulative oil demand to 200 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 110 EJ for natural gas, 10 EJ for coal, and 150 EJ for oil.

8.6.2 Latin America: Power Sector Analysis

The Latin American region is extremely diverse. It borders Mexico in the north and its southern tip is in the South Pacific. It also includes all the Caribbean islands and Central America. The power-generation situation is equally diverse, and the sub-regional breakdown tries to reflect this diversity to some extent. In the Caribbean, which contains 28 island nations and more than 7000 islands, the calculated storage demand will almost certainly be higher than the region’s average, because a regional power exchange grid between the islands seems impractical. To calculate the detailed storage demand, island-specific analyses would be required, as has recently been done for Barbados (Hohmeyer 2015). The mainland of South America has been subdivided into the large economic centres of Chile, Argentina, and Brazil, and Central America and the northern part of South America have been clustered into two parts.

8.6.2.1 Latin America: Development of Power Plant Capacities

The most important future renewable technologies for Latin America are solar PV and onshore wind, followed by CSP (which will be especially suited to the Atacama Desert in Chile) and offshore wind, mainly in the coastal areas of Brazil and Argentina. The annual market for solar PV must increase from 6.5 GW in 2020 by a factor of three to an average of 15.5 GW by 2030 under the 2.0 °C Scenario and to around 23 GW under the 1.5 °C Scenario. The onshore wind market in the 1.5 °C Scenario must increase to 15 GW by 2025, compared with the average annual onshore wind market of around 3 GW between 2014 and 2017 (GWEC 2018). By 2050, offshore wind will have increased to a moderate annual new installation capacity of around 2–3 GW from 2025 to 2050 in both scenarios. Concentrated solar power plants will be limited to the desert regions of South America, especially Chile. The market for biofuels for electricity generation will play an important role in all agricultural areas, including the Caribbean and Central America, where most geothermal resources are located (Table 8.27).

Table 8.27

Latin America: average annual change in installed power plant capacity

Latin Power Generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	0	−1	0	−1	−1	0
Lignite	0	0	0	0	0	0
Gas	4	2	1	6	−9	5
Hydrogen-gas	0	1	1	4	11	14
Oil/diesel	−1	−4	−4	−3	0	0
Nuclear	0	0	0	0	0	0
Biomass	3	5	3	4	4	3
Hydro	2	0	0	0	0	0
Wind (onshore)	5	11	11	17	6	3
Wind (offshore)	0	1	2	2	3	2
PV (roof top)	9	18	14	25	9	8
PV (utility scale)	3	6	5	8	3	3
Geothermal	0	1	1	1	1	1
Solar thermal power plants	0	2	4	5	2	3
Ocean energy	0	0	1	1	2	2
Renewable fuel based co-generation	1	2	2	2	2	1

8.6.2.2 Latin America: Utilization of Power-Generation Capacities

Table 8.28 shows that our modelling assumes that for the entire modelling period, there will be no interconnection capacity between the Caribbean, Central America, and South America, whereas the interconnection capacity in the rest of South America will increase to 15% by 2030 and to 20% by 2050. The shares of variable renewables are almost identical in the 2.0 °C and 1.5 °C Scenarios. The lowest rates of variable renewables are in central South America and Central America because the onshore wind potential is limited by average wind speeds that are lower than elsewhere. Compared with all the other world regions, Latin America has the highest share of dispatchable renewables, mainly attributable to existing hydropower plants.

Table 8.28

Latin America: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
Latin America		Variable RE	Dispatch RE	Dispatch fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch fossil	Inter-connection
Caribbean	2015	3%	63%	34%	0%
	2030	25%	62%	12%	0%	25%	62%	12%	0%
	2050	44%	53%	3%	0%	44%	53%	3%	0%
Central America	2015	2%	64%	35%	0%
	2030	21%	64%	14%	0%	21%	64%	14%	0%
	2050	40%	58%	2%	0%	40%	58%	2%	0%
North L. America	2015	2%	64%	34%	10%
	2030	20%	41%	39%	15%	20%	41%	39%	15%
	2050	30%	40%	30%	20%	30%	40%	30%	20%
Central L. America	2015	1%	64%	36%	10%
	2030	16%	52%	32%	15%	16%	52%	32%	15%
	2050	29%	49%	22%	20%	29%	49%	22%	20%
Brazil	2015	4%	63%	33%	10%
	2030	30%	54%	16%	15%	30%	54%	16%	15%
	2050	47%	44%	8%	20%	47%	44%	8%	20%
Uruguay	2015	2%	61%	37%	10%
	2030	21%	57%	22%	15%	21%	57%	22%	15%
	2050	37%	52%	11%	20%	37%	52%	11%	20%
Argentina	2015	2%	62%	36%	10%
	2030	19%	42%	38%	15%	19%	42%	38%	15%
	2050	31%	40%	29%	20%	31%	40%	29%	20%
Chile	2015	2%	64%	35%	10%
	2030	18%	45%	37%	15%	18%	45%	37%	15%
	2050	33%	47%	19%	20%	33%	47%	19%	20%
Latin America	2015	3%	63%	34%
	2030	24%	51%	25%		24%	51%	25%
	2050	39%	45%	16%		39%	45%	16%

Compared with other regions of the world, Latin America currently has a small fleet of coal and nuclear power plants, but they are operated with a high capacity factor (Table 8.29). The dispatch order for all world regions in all cases is assumed to be the same, to make the results comparable. Therefore, the capacity factors of these dispatch power plants (mainly gas) will increase at the expense of those for coal and nuclear power plants, which explains the rapid reduction in the capacity factor in 2020. Therefore, this effect is the result of the assumed dispatch order, rather than of an increase in variable power generation.

Table 8.29

Latin America: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
Latin America			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	48.9%	31%	25%	36%	21%	41%	18%	34%	24%
Limited dispatchable: fossil and nuclear	[%/yr]	73.4%	14%	3%	17%	0%	45%	0%	13%	4%
Limited dispatchable: renewable	[%/yr]	26.0%	53%	48%	46%	19%	56%	23%	47%	33%
Dispatchable: fossil	[%/yr]	53.2%	24%	11%	31%	2%	37%	6%	31%	11%
Dispatchable: renewable	[%/yr]	45.6%	37%	28%	46%	26%	43%	25%	46%	35%
Variable: renewable	[%/yr]	12.2%	12%	12%	21%	14%	31%	15%	22%	15%

8.6.2.3 Latin America: Development of Load, Generation and Residual Load

The sub-regions of Latin America are highly diverse in their geographic features and population densities, so the maximum loads in the different sub-regions vary widely. Table 8.30 shows that the sub-region with the smallest calculated maximum load is Uruguay, with only 2.3 GW, which seems realistic because the maximum load was 1.7 GW in 2012 according to IDB (2013). Brazil, Uruguay’s direct neighbour, has the largest load of close to 100 GW, which will increase by a factor of 2.5 to around 250 GW by 2050 under both scenarios. Brazil’s maximum generation will increase accordingly, without significant overproduction peaks. The calculated maximum increase in interconnection required is only 10 GW. In Argentina, peak generation matches peak demand because Argentina has one of the best wind resources in the world in Patagonia. Surplus wind power can either be exported after a significant increase in transmission capacity or, as assumed in our scenario, it can be used to produce synthetic and hydrogen fuels.

Table 8.30

Latin America: load, generation, and residual load development

Power generation structure		2.0 °C			1.5 °C
Latin America		Max demand	Max generation	Max residual load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
Latin America		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
Caribbean	2020	14.9	4.9	10.4		14.8	7.4	8.1
	2030	23.4	23.1	8.9	0	21.0	27.5	1.5	5
	2050	36.6	38.6	14.8	0	36.9	48.4	6.9	5
Central America	2020	13.1	13.0	3.3		13.1	20.0	0.5
	2030	20.7	23.6	7.8	0	18.8	31.8	1.4	12
	2050	33.3	42.6	14.3	0	33.2	47.3	7.2	7
North Latin America	2020	37.5	41.5	1.4		37.4	67.9	1.4
	2030	59.1	76.7	7.1	11	53.1	80.9	5.0	23
	2050	92.9	117.2	15.8	9	94.7	108.3	24.9	0
Central South America	2020	16.8	9.9	6.9		16.8	14.7	2.1
	2030	26.2	29.4	5.7	0	24.1	39.9	2.3	14
	2050	42.0	46.3	11.3	0	42.9	59.5	11.5	5
Brazil	2020	99.0	96.4	5.7		98.9	102.3	4.7
	2030	153.8	150.1	38.4	0	140.7	145.2	9.9	0
	2050	241.0	247.5	74.1	0	250.7	306.1	45.5	10
Uruguay	2020	2.3	2.9	0.4		2.3	4.4	0.1
	2030	3.4	4.0	1.1	0	3.1	5.3	0.2	2
	2050	4.9	6.6	1.7	0	5.1	7.8	1.0	2
Argentina	2020	25.5	26.2	1.0		25.5	35.7	1.0
	2030	40.1	176.4	3.1	133	36.6	176.4	3.6	136
	2050	56.4	71.8	14.0	2	59.4	82.7	18.2	5
Chile	2020	9.3	19.2	0.4
	2030	16.5	21.0	1.7	3	15.0	23.5	1.4	7
	2050	26.1	30.7	7.7	0	27.7	35.5	7.2	1

Table 8.31 provides an overview of the calculated storage and dispatch power requirements by sub-region. As indicated in the introduction to the Latin America results, the storage requirements for the Caribbean might be high because the region cannot exchange solar or wind electricity with other sub-regions. However, all other sub-regions contain either several countries or larger provinces, so they are more suited to the integration of variable electricity. Compared with other world regions, Latin America has one of the lowest storage capacities and one of the lowest needs for additional dispatch. This is because the region’s installed capacity of hydropower is high. However, this research does not include a water resource assessment for hydropower plants. Droughts may increase the demand for storage and/or hydrogen dispatch.

Table 8.31

Latin America: storage and dispatch service requirements in the 2.0 °C and 1.5 °C Scenarios

Storage and dispatch		2.0 °C					1.5 °C
Latin America		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
Latin America		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
Caribbean	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	6	81	6	11	17	0
	2050	100	46	3	49	15,282	1816	534	59	594	1808
Central America	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	5	57	5	8	13	0
	2050	34	47	2	49	15,010	1462	560	59	619	5843
North Latin America	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	0	3	1	1	1	0
	2050	0	0	0	0	7086	1047	633	57	690	0
Central L. America	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	3	82	9	14	23	0
	2050	36	41	1	42	16,031	2768	1032	104	1136	40
Brazil	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	19	774	83	138	221	0
	2050	475	666	27	693	63,131	18,024	6977	769	7746	1103
Uruguay	2020	77	0	0	0	0	511	0	0	0	0
	2030	0	0	0	0	0	20	1	2	3	0
	2050	42	20	2	22	1591	279	78	9	86	65
Argentina	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	0	177	14	23	37	0
	2050	617	446	32	478	315	4969	1727	180	1908	0
Chile	2020	2	0	0	0	0	2669	1	0	1	0
	2030	0	0	0	0	1	13	1	2	3	0
	2050	10	14	1	15	8781	162	91	7	97	58
Latin America	2020	79	0	0	0	0	3180	2	0	2	0
	2030	0	0	0	0	34	1207	121	197	318	1
	2050	1314	1279	68	1347	127,226	30,526	11,633	1243	12,875	8917

8.7 OECD Europe

8.7.1 OECD Europe: Long-Term Energy Pathways

8.7.1.1 OECD Europe: Final Energy Demand by Sector

Combining the assumptions on population growth, GDP growth, and energy intensity produces the future development pathways for OECD Europe’s final energy demand shown in Fig. 8.35 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will increase by 9%, from the current 46,000 PJ/year to 50,000 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will decrease by 39% compared with current consumption and will reach 28,000 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will reach 25,200 PJ, 45% below the 2015 demand. In the 1.5 °C Scenario, the final energy demand in 2050 will be 10% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will decrease from 2300 TWh/year in 2015 to 2040 TWh/year by 2050 in both alternative scenarios. Compared with the 5.0 °C case (3200 TWh/year in 2050), the efficiency measures implemented in the 2.0 °C and 1.5 °C Scenarios will save 1160 TWh/year in 2050.

Electrification will cause a significant increase in the electricity demand by 2050. In the 2.0 °C Scenario, the electricity demand for heating will increase to approximately 1300 TWh/year due to electric heaters and heat pumps, and in the transport sector, the demand will increase to approximately 2600 TWh/year in response to increased electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 1600 TWh/year The gross power demand will thus rise from 3600 TWh/year in 2015 to 6000 TWh/year by 2050 in the 2.0 °C Scenario, 28% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 6400 TWh/year by 2050.

Efficiency gains could be even larger in the heating sector than in the electricity sector. Under the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 6200 PJ/year and 8200 PJ/year, respectively, are avoided by efficiency gains by 2050 compared with the 5.0 °C Scenario.

8.7.1.2 OECD Europe: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power from renewable sources. By 2050, 100% of the electricity produced in OECD Europe will come from renewable energy sources in the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 75% of the total electricity generation. Renewable electricity’s share of the total production will be 68% by 2030 and 89% by 2040. The installed capacity of renewables will reach about 1200 GW by 2030 and 2270 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario is assumed to be 74%. The 1.5 °C Scenario will have a generation capacity from renewable energy of approximately 2480 GW in 2050.

Table 8.32 shows the development of different renewable technologies in OECD Europe over time. Figure 8.36 provides an overview of the overall power-generation structure in OECD Europe. From 2020 onwards, the continuing growth of wind and PV, up to 790 GW and 1000 GW, respectively, will be complemented by generation from biomass (ca. 110 GW) CSP and ocean energy (more than 50 GW each), in the 2.0 °C Scenario. Both the 2.0 °C and 1.5 °C Scenarios will lead to high proportions of variable power generation (PV, wind, and ocean) of 38% and 45%, respectively, by 2030 and 67% and 68%, respectively, by 2050.

Table 8.32

OECD Europe: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	207	224	231	238	248
	2.0 °C	207	218	219	221	225
	1.5 °C	207	218	219	221	225
Biomass	5.0 °C	40	51	56	60	65
	2.0 °C	40	78	105	115	113
	1.5 °C	40	84	111	113	113
Wind	5.0 °C	138	216	254	296	347
	2.0 °C	138	279	409	655	787
	1.5 °C	138	299	468	778	847
Geothermal	5.0 °C	2	3	3	3	4
	2.0 °C	2	6	11	27	39
	1.5 °C	2	6	11	27	39
PV	5.0 °C	95	137	157	172	191
	2.0 °C	95	264	422	745	996
	1.5 °C	95	364	598	1028	1151
CSP	5.0 °C	2	3	4	7	11
	2.0 °C	2	7	17	38	54
	1.5 °C	2	7	22	48	57
Ocean	5.0 °C	0	1	1	4	8
	2.0 °C	0	7	16	42	53
	1.5 °C	0	7	16	42	53
Total	5.0 °C	484	635	706	780	873
	2.0 °C	484	859	1198	1842	2267
	1.5 °C	484	985	1444	2256	2485

8.7.1.3 OECD Europe: Future Costs of Electricity Generation

Figure 8.37 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated electricity generation costs in 2015 (referring to full costs) were around 7 ct/kWh. In the 5.0 °C case, generation costs will increase until 2050, when they will reach 10.4 ct/kWh. The generation costs in both alternative scenarios will increase until 2030, when they will reach 10.3 ct/kWh, and they will drop by 2050 to 8.9 ct/kWh and 8.8 ct/kWh, respectively, 1.5–1.6 ct/kWh lower than in the 5.0 °C case. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, the growth in demand and increasing fossil fuel prices will result in an increase in total electricity supply costs from today’s $270 billion/year to more than $550 billion/year in 2050. In the 2.0 °C Scenario, the total supply costs will be $560 billion/year and in the 1.5 °C Scenario, they will be $590 billion/year The long-term costs for electricity supply will be more than 2% higher in the 2.0 °C Scenario than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility. Further electrification and synthetic fuel generation in the 1.5 °C Scenario will result in total power generation costs that are 8% higher than in the 5.0 °C case.

Compared with these results, the generation costs when the CO₂ emission costs are not considered will increase in the 5.0 °C Scenario to 8.8 ct/kWh by 2050. In the 2.0 °C Scenario, they will increase until 2030 when they reach 9.5 ct/kWh, and then drop to 8.9 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 9.7 ct/kWh, and then drop to 8.8 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs will reach a maximum of 1 ct/kWh higher than in the 5.0 °C case in 2030. In the 1.5 °C Scenario, the maximum difference in generation costs compared with the 5.0 °C Scenario will be 1.2 ct/kWh, which will occur in 2040. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will rise to about $470 billion/year in 2050.

8.7.1.4 OECD Europe: Future Investments in the Power Sector

An investment of around $4900 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including additional power plants for the production of hydrogen and synthetic fuels and investments to replace plants at the ends of their economic lives. This value is equivalent to approximately $136 billion per year on average, which is $2150 billion more than in the 5.0 °C case ($2750 billion). An investment of around $5340 billion for power generation will be required between 2015 and 2050 under the 1.5 °C Scenario. On average, this will be an investment of $148 billion per year. In the 5.0 °C Scenario, investment in conventional power plants will be around 26% of the total cumulative investments, whereas approximately 74% will be invested in renewable power generation and co-generation (Fig. 8.38).

However, in the 2.0 °C (1.5 °C) Scenario, OECD Europe will shift almost 96% (97%) of its entire investments to renewables and co-generation. By 2030, the fossil fuel share of the power sector investments will predominantly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $2340 billion in 2050, equivalent to $65 billion per year. Therefore, the total fuel cost savings will be equivalent to 110% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $2600 billion, or $72 billion per year.

8.7.1.5 OECD Europe: Energy Supply for Heating

The final energy demand for heating will increase in the 5.0 °C Scenario by 16%, from 20,600 PJ/year in 2015 to 24,000 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 26% in 2050 in the 2.0 °C Scenario relative to that in the 5.0 °C case, and by 34% in the 1.5 °C Scenario. Today, renewables supply around 19% of OECD Europe’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 44% of OECD Europe’s total heat demand in 2030 under the 2.0 °C Scenario and 53% under the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.39 shows the development of different technologies for heating in OECD Europe over time, and Table 8.33 provides the resulting renewable heat supply for all scenarios. Up to 2030, biomass will remain the main contributor. The growing use of solar, geothermal, and environmental heat will lead in the long term to a biomass share of 27% in the 2.0 °C Scenario and 28% in the 1.5 °C Scenario.

Table 8.33

OECD Europe: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	2681	3115	3343	3713	4153
	2.0 °C	2681	3109	3295	3483	3772
	1.5 °C	2681	3046	3096	3220	3433
Solar heating	5.0 °C	119	216	251	345	454
	2.0 °C	119	1043	1788	2904	3243
	1.5 °C	119	1013	1464	2182	2327
Geothermal heat and heat pumps	5.0 °C	203	291	336	479	717
	2.0 °C	203	968	1731	3572	5080
	1.5 °C	203	878	1430	2933	4147
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	1	788	1895
	1.5 °C	0	0	162	1595	2227
Total	5.0 °C	3003	3623	3931	4537	5325
	2.0 °C	3003	5121	6815	10,748	13,989
	1.5 °C	3003	4937	6152	9930	12,134

Heat from renewable hydrogen will further reduce the dependence on fossil fuels in both scenarios. Hydrogen consumption in 2050 will be around 1900 PJ/year in the 2.0 °C Scenario and 2200 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of 1.5–1.6 between 2015 and 2050, and will have a final energy share of 22% in 2050 in the 2.0 °C Scenario and 23% in the 1.5 °C Scenario.

8.7.1.6 OECD Europe: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 will amount to around $2410 billion in the 2.0 °C Scenario (including investments for plant replacement at the ends of their economic lifetimes), or approximately $67 billion per year. The largest share of investments in OECD Europe is assumed to be for heat pumps (around $1200 billion), followed by solar collectors ($1080 billion). The 1.5 °C Scenario assumes an even faster expansion of renewable technologies. However, the lower heat demand (compared with the 2.0 °C Scenario) will results in a lower average annual investment of around $51 billion per year (Fig. 8.40, Table 8.34).

Table 8.34

OECD Europe: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	434	467	486	507	519
	2.0 °C	434	407	339	293	289
	1.5 °C	434	381	276	256	242
Geothermal	5.0 °C	5	7	7	7	3
	2.0 °C	5	15	24	49	48
	1.5 °C	5	14	16	21	11
Solar heating	5.0 °C	36	65	76	104	137
	2.0 °C	36	298	510	790	885
	1.5 °C	36	291	423	624	685
Heat pumps	5.0 °C	29	40	46	62	84
	2.0 °C	29	134	228	417	566
	1.5 °C	29	121	183	336	444
Total^a	5.0 °C	504	579	615	681	744
	2.0 °C	504	855	1101	1548	1789
	1.5 °C	504	807	897	1237	1383

^a Excluding direct electric heating

8.7.1.7 OECD Europe: Transport

Energy demand in the transport sector in OECD Europe is expected to decrease by 3% in the 5.0 °C Scenario, from around 14,000 PJ/year in 2015 to 13,600 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 69% (9460 PJ/year) by 2050 compared with the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in the transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 76% (or 10,300 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.35, Fig. 8.41).

Table 8.35

OECD Europe: projection of the transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	323	334	335	337	344
	2.0 °C	323	362	409	509	643
	1.5 °C	323	383	458	453	400
Road	5.0 °C	13,087	12,699	12,633	12,529	12,464
	2.0 °C	13,087	10,163	7540	4196	3097
	1.5 °C	13,087	8197	4404	3215	2556
Domestic aviation	5.0 °C	300	397	448	485	474
	2.0 °C	300	294	254	182	142
	1.5 °C	300	273	198	105	82
Domestic navigation	5.0 °C	227	236	240	248	259
	2.0 °C	227	236	240	247	258
	1.5 °C	227	236	240	247	258
Total	5.0 °C	13,938	13,665	13,656	13,598	13,541
	2.0 °C	13,938	11,055	8443	5134	4140
	1.5 °C	13,938	9090	5300	4020	3296

By 2030, electricity will provide 18% (430 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas in 2050, the share will be 64% (740 TWh/year). In 2050, up to 840 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 580 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 730 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of 600 PJ/year Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 130 PJ/year in 2050. Biofuel use will be reduced in the 1.5 °C Scenario to a maximum of 590 PJ/year. The maximum synthetic fuel demand will reach 170 PJ/year.

8.7.1.8 OECD Europe: Development of CO₂ Emissions

In the 5.0 °C Scenario, OECD Europe’s annual CO₂ emissions will decrease by 15% from 3400 Mt. in 2015 to 2876 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause the annual emissions to fall to 570 Mt. in 2040 in the 2.0 °C Scenario and to 270 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 116 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 55 Gt and 44 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 53% in the 2.0 °C Scenario and by 62% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in the annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario, this reduction will be greatest in ‘Power generation’, followed by the ‘Transport’ and the ‘Residential and other’ sectors (Fig. 8.42).

8.7.1.9 OECD Europe: Primary Energy Consumption

The levels of primary energy consumption in the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.43. In the 2.0 °C Scenario, the primary energy demand will decrease by 44%, from around 71,200 PJ/year in 2015 to 40,100 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 43% by 2050 in the 2.0 °C Scenario (5.0 °C: 70,700 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (39,000 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. This will cause renewable energy to have primary energy shares of 39% in 2030 and 92% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 92% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out by 2040 under both the 2.0 °C and the 1.5 °C Scenarios. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 670 EJ, the cumulative coal consumption to about 300 EJm, and the crude oil consumption to 660 EJ. In contrast, in the 2.0 °C case, the cumulative gas demand will amount to 420 EJ, the cumulative coal demand to 100 EJ, and the cumulative oil demand to 320 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 340 EJ for natural gas, 70 EJ for coal, and 240 EJ for oil.

8.7.2 OECD Europe: Power Sector Analysis

The European power sector is liberalized across the EU and cross-border trade in electricity has a long tradition and is very well documented. The European Network of Transmission System Operators for Electricity (ENTSO-E) publishes detailed data about the annual cross-border trade (ENTSO-E 2018) and produces the Ten-Year-Network Development Plan (TYNDP), which aims to integrate 60% renewable electricity by 2040 (TYNDP 2016). While the extent to which the power sector is liberalised and open for competition for generation and supply varies significantly across the EU, at the time of the writing of this book all 28-member states had renewable electricity and energy efficiency targets and policies to implement them. However, the OECD Europe region covers not only the EU but also neighbouring countries such as Norway, Switzerland and Turkey, which are not members of the EU, but are connected to the EU grid and are also involved in the cross-border electricity trade. The region also includes Iceland, Malta, and a significant number of islands in the coastal waters of the European continent and the Mediterranean Sea. The storage demand for all the islands and island nations cannot be calculated with a regional approach, and doing so was beyond the scope of this research. Israel is also part of OECD Europe in the IEA world regions used for this analysis. However, because of its geographic position, and to reflect current and possible future interconnections with its neighbours, Israel has been taken out of the energy balance of OECD Europe and integrated into the Middle East region.

8.7.2.1 OECD Europe: Development of Power Plant Capacities

The annual market for solar PV must increase from 11 GW in 2020 by a factor of 2 to an average of 40 GW by 2030. The onshore wind market must expand to 18 GW by 2025 under the 2.0 °C Scenario. This is only a minor increase on the average European wind market of 10–14 GW between 2009 and 2016 and 16.8 GW in 2017. However, the 1.5 °C Scenario requires that the size of the onshore wind market double between 2020 and 2025. The offshore wind market for both scenarios is similar and must increase from 3 GW (GWEC 2018) in 2017 to around 10 GW per year throughout the entire modelling period until 2050. All European lignite power plants will have stopped operations by 2035, and the last hard coal power plant will have gone offline by 2040 under the 2.0 °C Scenario. The 1.5 °C pathway requires the phase-out 5 years earlier (Table 8.36).

Table 8.36

OECD Europe: average annual change in installed power plant capacity

OECD Europe power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	−5	−9	−8	−4	0	0
Lignite	−5	−6	−3	−2	0	0
Gas	2	1	0	−5	−22	−19
Hydrogen-gas	0	1	2	6	14	14
Oil/diesel	−7	−5	−1	−2	0	0
Nuclear	−6	−9	−6	−6	−2	−2
Biomass	5	7	4	3	1	1
Hydro	1	0	0	0	0	0
Wind (onshore)	13	28	22	32	13	10
Wind (offshore)	4	9	10	11	8	8
PV (roof top)	16	43	30	42	25	21
PV (utility scale)	5	14	10	14	8	7
Geothermal	0	1	2	2	2	2
Solar thermal power plants	1	2	2	4	2	2
Ocean energy	1	2	3	3	2	2
Renewable fuel based co-generation	3	6	4	4	1	1

8.7.2.2 OECD Europe: Utilization of Power-Generation Capacities

The UK, Ireland, and the Iberian Peninsula are the least interconnected sub-regions of OECD Europe, and they already have relatively high shares of variable renewables, as shown in Table 8.37.

Table 8.37

OECD Europe: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
OECD Europe		Variable RE	Dispatch RE	Dispatch fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch fossil	Inter-connection
Central	2015	12%	47%	41%	20%
	2030	38%	47%	15%	20%	45%	43%	12%	20%
	2050	62%	33%	5%	20%	64%	31%	5%	20%
UK & Islands	2015	25%	47%	28%	10%
	2030	63%	31%	6%	20%	71%	25%	5%	20%
	2050	84%	15%	2%	20%	85%	13%	2%	20%
Iberian Peninsula	2015	26%	47%	26%	10%
	2030	67%	30%	3%	20%	76%	22%	3%	20%
	2050	86%	13%	1%	20%	88%	12%	1%	20%
Balkans + Greece	2015	17%	47%	35%	10%
	2030	53%	42%	6%	20%	60%	35%	5%	20%
	2050	73%	24%	3%	20%	74%	23%	3%	20%
Baltic	2015	15%	47%	38%	10%
	2030	44%	45%	12%	20%	50%	40%	10%	20%
	2050	67%	29%	4%	20%	68%	28%	4%	20%
Nordic	2015	13%	47%	39%	10%
	2030	39%	46%	14%	20%	46%	43%	11%	20%
	2050	65%	31%	4%	20%	67%	29%	4%	20%
Turkey	2015	10%	47%	42%	5%
	2030	35%	48%	17%	5%	40%	44%	16%	5%
	2050	59%	35%	6%	5%	60%	34%	6%	5%
OECD Europe Central	2015	15%	47%	38%
	2030	44%	44%	12%		51%	39%	10%
	2050	67%	28%	4%		69%	27%	4%

Table 8.37 shows that the Nordic countries, especially Norway and Sweden, have very high shares of hydropower, including pumped hydropower. Therefore, an increased interconnection capacity with other sub-regions by 2030 will contribute to the integration of larger shares of wind and solar in other European regions. Across the EU, it is assumed that the average interconnection capacities will increase to 20% of the regional peak load.

Both alternative scenarios assume that limited dispatchable power generation—namely coal, lignite, and nuclear—will not have priority dispatch and will be last in the dispatch queue. Therefore, the average calculated capacity factor will decrease from 57.5% in 2015 to only 14% in 2020, as shown in Table 8.38.

Table 8.38

OECD Europe: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
World			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	45.2%	37%	37%	48%	44%	35%	36%	39%	38%
Limited dispatchable: fossil and nuclear	[%/yr]	57.5%	14%	14%	3%	2%	19%	1%	20%	9%
Limited dispatchable: renewable	[%/yr]	54.0%	60%	60%	52%	48%	60%	39%	41%	40%
Dispatchable: fossil	[%/yr]	32.0%	20%	20%	7%	7%	30%	10%	15%	16%
Dispatchable: renewable	[%/yr]	43.7%	67%	67%	67%	61%	39%	49%	52%	50%
Variable: renewable	[%/yr]	22.5%	22%	22%	40%	38%	29%	35%	36%	35%

Table 8.38 shows that by 2020, most of the installed coal and nuclear capacity will not be required to secure power supply. Instead, dispatchable renewable power plants will fill the gap and their capacity factors will increase.

8.7.2.3 OECD Europe: Development of Load, Generation, and Residual Load

The loads of the European sub-regions will not increase until 2030 in the two alternative scenarios, as shown in Table 8.39. The only exception is Turkey, which will have a constantly increasing load. This is attributed to Turkey’s assumed economic development and increasing per capita electricity demand, which is currently lower than in most EU countries (WB-DB 2018). The calculated load will increase in all sub-regions between 2030 and 2050 due to the increased deployment of electric mobility. Central Europe has a very high requirement for increased transmission interconnection—or storage, see Table 8.40—because of increases in variable generation, including offshore wind in the North Sea and Baltic Sea. Central Europe, the Iberian Peninsula, and the UK have the highest storage demands, as shown in Table 8.40. This corresponds to the calculated results for increased interconnections. To avoid curtailment, renewably produced hydrogen will be used to store surplus generation for dispatch when required. Finding the optimal mix of battery capacity, pumped hydro capacity, hydrogen production, and expansion of transmission capacity was beyond the scope of this analysis, and further research is required on this issue.

Table 8.39

OECD Europe: load, generation, and residual load development

Power generation structure		2.0 °C				1.5 °C
OECD Europe		Max demand	Max generation	Max residual load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
OECD Europe		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
Central	2020	328.9	322.3	73.6		328.9	322.3	77.8
	2030	350.7	397.4	44.5	2	360.3	520.4	47.4	113
	2050	491.9	842.8	243.1	108	511.2	954.3	259.0	184
UK & Islands	2020	66.1	73.5	33.2		66.1	73.4	33.1
	2030	71.6	87.6	21.0	0	73.7	112.9	23.4	16
	2050	98.0	187.9	51.5	38	102.2	210.7	55.1	53
Iberian Peninsula	2020	47.0	56.1	10.3		47.0	56.1	10.3
	2030	50.8	62.3	7.3	4	52.6	80.8	7.9	20
	2050	70.8	133.2	31.7	31	74.3	149.4	34.6	41
Balkans + Greece	2020	37.9	38.2	1.4		37.9	37.9	1.4
	2030	39.5	49.3	6.3	4	41.6	63.1	6.8	15
	2050	55.6	105.4	24.1	26	59.8	117.8	27.5	30
Baltic	2020	4.6	4.5	0.1		4.6	4.5	0.1
	2030	4.9	6.1	0.7	1	5.1	7.9	0.7	2
	2050	6.8	13.1	3.2	3	7.2	14.7	3.5	4
Nordic	2020	52.0	50.8	1.3		52.0	50.8	1.3
	2030	54.4	65.9	8.7	3	55.2	86.0	10.4	20
	2050	71.0	140.3	30.0	39	72.6	158.5	31.0	55
Turkey	2020	37.5	38.5	0.8		37.5	38.2	0.8
	2030	48.4	49.1	6.9	0	50.8	64.4	7.5	6
	2050	68.2	107.4	33.1	6	73.0	121.5	37.4	11

Table 8.40

OECD Europe: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
OECD Europe		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
OECD Europe		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
Central	2020	0	0	0	0	0	0	0	0	0	0
	2030	425	67	728	796	38,043	6947	515	7996	8511	139,501
	2050	59,495	28,998	32,425	61,423	546,511	99,134	35,542	48,679	84,222	549,376
UK & Islands	2020	0	0	0	0	0	0	0	0	0	0
	2030	3419	293	5808	6101	4148	12,239	440	13,977	14,417	13,195
	2050	57,089	9507	34,158	43,665	41,134	72,011	9738	38,301	48,039	40,932
Iberian Peninsula	2020	0	0	0	0	0	0	0	0	0	0
	2030	1688	186	2763	2949	2712	12,555	407	11,672	12,079	8127
	2050	52,580	7952	27,526	35,478	22,000	69,483	8273	30,928	39,201	22,448
Balkans + Greece	2020	0	0	0	0	0	0	0	0	0	0
	2030	523	62	895	957	3274	3699	172	3996	4168	11,349
	2050	19,794	5717	10,649	16,366	39,208	25,680	6267	12,033	18,300	42,798
Baltic	2020	0	0	0	0	0	0	0	0	0	0
	2030	27	2	41	42	482	190	7	174	181	1775
	2050	1071	360	542	902	6365	1504	413	677	1090	6636
Nordic	2020	0	0	0	0	0	0	0	0	0	0
	2030	149	16	274	291	6276	2111	95	2237	2332	23,031
	2050	14,144	4425	6905	11,330	80,577	22,171	5219	9360	14,580	78,294
Turkey	2020	0	0	0	0	0	0	0	0	0	0
	2030	8	4	21	25	5287	762	72	1067	1139	20,038
	2050	7887	4120	4348	8467	78,788	11,251	4744	5467	10,211	82,142
OECD Europe	2020	0	0	0	0	0	0	0	0	0	0
	2030	6238	630	10,531	11,161	60,223	38,504	1710	41,118	42,827	217,016
	2050	212,060	61,078	116,554	177,632	814,585	301,234	70,196	145,445	215,641	822,626

8.8 Africa

8.8.1 Africa: Long-Term Energy Pathways

8.8.1.1 Africa: Final Energy Demand by Sector

The development pathways for Africa’s final energy demand when the assumptions on population growth, GDP growth, and energy intensity are combined are shown in Fig. 8.44 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will increase by 103% from the current 23,200 PJ/year to 47,100 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will increase at a much slower rate, by 39% compared with current consumption, and will reach 32,300 PJ/year by 2050. The final energy demand under the 1.5 °C Scenario will reach 30,100 PJ, 30% above the 2015 demand level. In the 1.5 °C Scenario, the final energy demand in 2050 will be 7% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will increase from 540 TWh/year in 2015 to around 2590 TWh/year in 2050 in both alternative scenarios, which will be 590 TWh/year higher than in the 5.0 °C case. Although efficiency measures will reduce the specific energy consumption by appliances, the scenarios consider higher consumption to achieve higher living standards.

Electrification will lead to a significant increase in the electricity demand by 2050. In the 2.0 °C Scenario, the electricity demand for heating will increase to approximately 1200 TWh/year due to electric heaters and heat pumps, and in the transport sector, the demand will increase to approximately 1300 TWh/year in response to increased electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 1100 TWh/year The gross power demand will thus increase from 800 TWh/year in 2015 to 5700 TWh/year in 2050 in the 2.0 °C Scenario, 119% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 6300 TWh/year in 2050.

The efficiency gains in the heating sector could be even larger than in the electricity sector. In the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 3600 PJ/year is avoided through efficiency gains by 2050 compared with the 5.0 °C Scenario.

8.8.1.2 Africa: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power from renewable sources. By 2050, 100% of the electricity produced in Africa will come from renewable energy sources in the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 92% of the total electricity generation. Renewable electricity’s share of total production will be 61% by 2030 and 96% by 2040. The installed capacity of renewables will reach about 360 GW by 2030 and 2040 GW by 2050. In the 1.5 °C Scenario, the share of renewable electricity generation in 2030 is assumed to be 73%. The 1.5 °C Scenario will have a generation capacity from renewable energy of approximately 2280 GW in 2050.

Table 8.41 shows the development of different renewable technologies in Africa over time. Figure 8.45 provides an overview of the overall power-generation structure in Africa. From 2020 onwards, the continuing growth of wind and PV, up to 610 GW and 980 GW, respectively, will be complemented by up to 230 GW of solar thermal generation, as well as limited biomass, geothermal, and ocean energy, in the 2.0 °C Scenario. Both the 2.0 °C and 1.5 °C Scenarios will lead to high proportions of variable power generation (PV, wind, and ocean) of 40% and 49%, respectively, by 2030, and 71% by 2050.

Table 8.41

Africa: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	28	47	58	84	117
	2.0 °C	28	46	49	51	54
	1.5 °C	28	46	48	51	54
Biomass	5.0 °C	1	2	4	8	13
	2.0 °C	1	8	17	33	48
	1.5 °C	1	8	25	42	72
Wind	5.0 °C	3	11	14	20	29
	2.0 °C	3	42	132	415	609
	1.5 °C	3	87	197	453	633
Geothermal	5.0 °C	1	2	3	7	14
	2.0 °C	1	7	16	33	64
	1.5 °C	1	7	16	33	64
PV	5.0 °C	2	17	27	52	89
	2.0 °C	2	38	134	611	983
	1.5 °C	2	70	166	757	1162
CSP	5.0 °C	0	2	3	10	17
	2.0 °C	0	0	1	80	235
	1.5 °C	0	2	19	108	257
Ocean	5.0 °C	0	0	0	0	0
	2.0 °C	0	2	10	20	43
	1.5 °C	0	2	10	20	43
Total	5.0 °C	35	81	110	180	279
	2.0 °C	35	144	359	1243	2036
	1.5 °C	35	223	481	1464	2284

8.8.1.3 Africa: Future Costs of Electricity Generation

Figure 8.46 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated electricity-generation costs in 2015 (referring to full costs) were around 5.4 ct/kWh. In the 5.0 °C case, generation costs will increase until 2030, when they reach 11 ct/kWh, and will then stabilize at 10.8 ct/kWh by 2050. In the 2.0 °C and 1.5 °C Scenarios, the generation costs will increase until 2030, when they reach 8.4 ct/kWh and 8.2 ct/kWh, respectively. They will then drop to 5.6 ct/kWh by 2050 in both scenarios, 5.2 ct/kWh lower than in the 5.0 °C case. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, the growth in demand and increasing fossil fuel prices will cause the total electricity supply costs to increase from today’s $40 billion/year to more than $290 billion/year in 2050. In the 2.0 °C Scenario, the total supply costs will be $350 billion/year, and in the 1.5 °C Scenario, they will be $380 billion/year The long-term costs of electricity supply will be more than 23% higher under the 2.0 °C Scenario than under the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility. Further electrification and synthetic fuel generation in the 1.5 °C Scenario will result in total power generation costs that are 34% higher than in the 5.0 °C case.

Compared with these results, the generation costs when the CO₂ emission costs are not considered will increase in the 5.0 °C case to 8.1 ct/kWh. In the 2.0 °C Scenario, they will increase until 2030, when they reach 6.8 ct/kWh, and then drop to 5.6 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 7.2 ct/kWh and then drop to 5.6 ct/kWh by 2050. Therefore, the generation costs in both alternative scenarios are, at maximum, 2.5 ct/kWh lower than in the 5.0 °C case. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will increase to about $220 billion/year in 2050.

8.8.1.4 Africa: Future Investments in the Power Sector

An investment of around $3500 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including additional power plants for the production of hydrogen and synthetic fuels and investments in plant replacement at the ends of their economic lives. This value is equivalent to approximately $97 billion per year, on average, and is $2590 billion more than in the 5.0 ° C case ($910 billion). An investment of around $3910 billion for power generation will be required between 2015 and 2050 in the 1.5 °C Scenario. On average, this is an investment of $109 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will be around 45% of the total cumulative investments, and approximately 55% will be invested in renewable power generation and co-generation (Fig. 8.47).

However, in the 2.0 °C (1.5 °C) Scenario, Africa will shift almost 93% (94%) of its entire investments to renewables and co-generation. By 2030, the fossil fuel share of power sector investments will focus predominantly on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $1510 billion in 2050, equivalent to $42 billion per year. Therefore, the total fuel cost savings will be equivalent to 60% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $1610 billion, or $45 billion per year.

8.8.1.5 Africa: Energy Supply for Heating

The final energy demand for heating will increase in the 5.0 °C Scenario by 166%, from 7600 PJ/year in 2015 to 20,200 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 18% in 2050 in both alternative scenarios, relative to the 5.0 °C case. Today, renewables supply around 61% of Africa’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 71% of Africa’s total heat demand in 2030 under the 2.0 °C Scenario and 79% under the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand from renewable energy in 2050.

Figure 8.48 shows the development of different technologies for heating in Africa over time, and Table 8.42 provides the resulting renewable heat supply for all scenarios. Biomass will remain the main contributor. The growing use of solar, geothermal, and environmental heat will lead, in the long term, to a reduced biomass share of 51% in the 2.0 °C Scenario and 40% in the 1.5 °C Scenario.

Table 8.42

Africa: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	4586	5761	6317	7211	8203
	2.0 °C	4586	5308	6047	7039	6551
	1.5 °C	4586	5748	6448	6938	4222
Solar heating	5.0 °C	7	37	86	228	481
	2.0 °C	7	204	786	2066	3416
	1.5 °C	7	203	783	2109	3416
Geothermal heat and heat pumps	5.0 °C	0	0	0	0	0
	2.0 °C	0	86	215	559	2106
	1.5 °C	0	86	213	591	2106
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	0	397	720
	1.5 °C	0	0	0	429	720
Total	5.0 °C	4593	5797	6404	7440	8684
	2.0 °C	4593	5598	7047	10,061	12,793
	1.5 °C	4593	6037	7444	10,067	10,464

Heat from renewable hydrogen will further reduce the dependence on fossil fuels in both scenarios. Hydrogen consumption in 2050 will be around 720 PJ/year in both the 2.0 °C Scenario and 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of 21–34 between 2015 and 2050, and will attain a final energy share of 23% in 2050 in the 2.0 °C Scenario and 37% in the 1.5 °C Scenario.

8.8.1.6 Africa: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 will amount to around $790 billion in the 2.0 °C Scenario (including investments in plant replacement after their economic lifetimes), or approximately $22 billion per year. The largest share of investment in Africa is assumed to be for heat pumps (around $370 billion), followed by solar collectors and biomass technologies. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies. However, the lower heat demand (compared with the 2.0 °C Scenario) will result in a lower average annual investment of around $21 billion per year (Table 8.43, Fig. 8.49).

Table 8.43

Africa: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5 0 °C	3655	4036	4100	3973	3870
	2 0 °C	3655	3276	3063	2792	2251
	1 5 °C	3655	3562	3069	2440	1307
Geothermal	5 0 °C	0	0	0	0	0
	2 0 °C	0	5	9	15	37
	1 5 °C	0	5	8	15	37
Solar heating	5 0 °C	1	7	16	44	92
	2 0 °C	1	39	150	396	654
	1 5 °C	1	39	150	404	654
Heat pumps	5 0 °C	0	0	0	0	0
	2 0 °C	0	3	16	51	227
	1 5 °C	0	3	16	54	227
Total^a	5 0 °C	3656	4043	4116	4017	3962
	2 0 °C	3656	3324	3239	3253	3169
	1 5 °C	3656	3610	3244	2912	2225

^a Excluding direct electric heating

8.8.1.7 Africa: Transport

The energy demand in the transport sector in Africa is expected to increase by 131% in the 5.0 °C Scenario, from around 4400 PJ/year in 2015 to 10,100 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 53% (5410 PJ/year) by 2050 compared with the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in the transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 63% (or 6360 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.44, Fig. 8.50).

Table 8.44

Africa: projection of transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	46	52	58	67	74
	2.0 °C	46	58	71	96	110
	1.5 °C	46	69	88	125	186
Road	5.0 °C	4182	5000	5812	7522	9635
	2.0 °C	4182	4688	4828	4651	4488
	1.5 °C	4182	4493	4422	3925	3482
Domestic aviation	5.0 °C	105	159	198	256	272
	2.0 °C	105	114	110	90	71
	1.5 °C	105	110	102	74	54
Domestic navigation	5.0 °C	32	35	37	40	44
	2.0 °C	32	35	37	40	44
	1.5 °C	32	35	37	40	44
Total	5.0 °C	4366	5246	6105	7885	10,027
	2.0 °C	4366	4895	5045	4877	4714
	1.5 °C	4366	4707	4648	4164	3765

By 2030, electricity will provide 4% (50 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas by 2050, the share will be 28% (370 TWh/year). In 2050, up to 410 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 360 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 340 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of 2300 PJ/year. Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 700 PJ/year in 2050. With the lower overall energy demand by transport, biofuel use will be reduced in the 1.5 °C Scenario to a maximum of 1700 PJ/year The maximum synthetic fuel demand will amount to 470 PJ/year.

8.8.1.8 Africa: Development of CO₂ Emissions

In the 5.0 °C Scenario, Africa’s annual CO₂ emissions will increase by 126%, from 1140 Mt. in 2015 to 2585 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause annual emissions to fall to 400 Mt. in 2040 in the 2.0 °C Scenario and to 200 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 66 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 27 Gt and 22 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 59% in the 2.0 °C Scenario and by 67% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario, this reduction will be greatest in ‘Power generation’, followed by the ‘Industry’ and ‘Residential and other’ sectors (Fig. 8.51).

8.8.1.9 Africa: Primary Energy Consumption

The levels of primary energy consumption in the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.52. In the 2.0 °C Scenario, the primary energy demand will increase by 50% from around 33,200 PJ/year in 2015 to around 50,000 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 26% by 2050 in the 2.0 °C Scenario (5.0 °C: 67700 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (48,000 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 56% in 2030 and 98% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 98% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out by 2035 under both the 2.0 °C Scenario and 1.5 °C Scenario. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 290 EJ, the cumulative coal consumption to about 210 EJ, and the crude oil consumption to 390 EJ. In contrast, in the 2.0 °C Scenario, the cumulative gas demand will amount to 130 EJ, the cumulative coal demand to 70 EJ, and the cumulative oil demand to 180 EJ. Even lower fossil fuel use will achieved in the 1.5 °C Scenario: 110 EJ for natural gas, 50 EJ for coal, and 150 EJ for oil.

8.8.2 Africa: Power Sector Analysis

The African continent has 54 countries and its geographic, economic, and climatic diversity are significant. Its regional breakdown into sub-regions tries to reflect this diversity, but still requires a level of simplification. There is no pan-African power grid yet, although it is currently under discussion. The African Clean Energy Corridor (ACEC) is the most prominent regional initiative and aims to connect the Eastern Africa Power Pool (EAPP) with the Southern Africa Power Pool (SAPP). It was politically endorsed in January 2014 at the Assembly of the International Renewable Energy Agency (IRENA 2014).

8.8.2.1 Africa: Development of Power Plant Capacities

In 2050, Africa’s most important renewable power-generation technology in both scenarios will be solar PV. In the 1.5 °C Scenario, solar PV will provide just over 40% of the total generation capacity, followed by onshore wind (with 24%), hydrogen power (15%), and CSP plants (located in the desert regions), with 10% of the total capacity. All other renewable power plant technologies will have only 2%–3% shares. The 2.0 °C Scenario will arrive at similar capacities by 2050, although the transition times in the two scenarios differ. Africa must build up solar PV and onshore wind markets equal to the market sizes in China in 2017: 50 GW of solar PV installation (REN21-GSR2018) and 23 GW of onshore wind (GWEC 2018). The market for CSP plants must reach about 1 GW per year by 2025, increasing rapidly to 3 GW per year in 2029 and 15 GW per year in 2035 (Table 8.45).

Table 8.45

Africa: average annual change in installed power plant capacity

Africa power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	2	0	−2	−7	−4	0
Lignite	0	0	0	0	0	0
Gas	6	3	10	16	13	14
Hydrogen-gas	0	0	1	3	15	32
Oil/diesel	−1	−2	−2	−2	−1	−1
Nuclear	0	0	0	0	0	0
Biomass	1	3	2	3	2	3
Hydro	2	1	1	1	0	0
Wind (onshore)	5	20	21	21	23	21
Wind (offshore)	0	2	5	10	7	4
PV (roof top)	3	12	29	31	41	48
PV (utility scale)	1	4	10	10	14	16
Geothermal	1	2	2	2	3	3
Solar thermal power plants	0	2	4	9	18	16
Ocean energy	0	1	1	1	3	3
Renewable fuel based co-generation	1	2	2	2	1	1

8.8.2.2 Africa: Utilization of Power-Generation Capacities

Africa’s sub-regions are assumed to have an interconnection capacity of 5% at the beginning of the calculation period (2015). This capacity is not required for any exchange of variable electricity production, because currently, shares are only at or below 2% of the total generation capacity (Table 8.46). However, the variable generation capacity will increase rapidly towards 2030. We assume that the interconnection capacity between sub-regions will increase and that initiatives such as the African Clean Energy Corridor (ACEC) will be implemented successfully.

Table 8.46

Africa: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
Power generation structure and interconnection		Variable RE	Dispatch RE	Dispatch fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch fossil	Inter-connection
North Africa	2015	2%	25%	73%	5%
	2030	56%	23%	21%	20%	60%	8%	32%	5%
	2050	75%	25%	0%	25%	61%	10%	29%	20%
West Africa	2015	1%	26%	73%	5%
	2030	38%	24%	38%	20%	41%	18%	41%	5%
	2050	67%	33%	0%	25%	63%	23%	14%	20%
Central Africa	2015	0%	26%	74%	5%
	2030	20%	29%	50%	20%	19%	30%	52%	5%
	2050	42%	58%	0%	25%	39%	44%	17%	20%
East Africa	2015	2%	26%	72%	5%
	2030	50%	22%	28%	20%	59%	10%	31%	5%
	2050	75%	25%	0%	25%	68%	13%	18%	20%
Southern Africa	2015	1%	25%	73%	5%
	2030	46%	20%	34%	20%	52%	17%	31%	5%
	2050	81%	19%	0%	25%	70%	12%	17%	20%
South Africa	2015	2%	25%	73%	5%
	2030	63%	0%	36%	20%	54%	8%	38%	5%
	2050	67%	33%	0%	25%	49%	9%	42%	20%
Africa	2015	2%	26%	73%
	2030	47%	21%	32%		52%	13%	35%
	2050	73%	27%	0%		64%	15%	21%

The development of average capacity factors for each generation type will follow the same trend as in most world regions. Table 8.47 shows the significant drop in the capacity factors of limited dispatchable power plants under the 1.5 °C Scenario.

Table 8.47

Africa: capacity factors by generation type

Utilization of Variable and Dispatchable power generation:
Utilization of Variable and Dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
Africa			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	54.7%	33%	33%	29%	25%	40%	23%	36%	23%
Limited dispatchable: fossil and nuclear	[%/yr]	69.4%	31%	5%	19%	8%	20%	4%	10%	5%
Limited dispatchable: renewable	[%/yr]	29.7%	52%	32%	35%	24%	51%	17%	36%	17%
Dispatchable: fossil	[%/yr]	49.2%	32%	37%	16%	23%	36%	15%	16%	17%
Dispatchable: renewable	[%/yr]	43.7%	39%	28%	27%	20%	41%	12%	49%	14%
Variable: renewable	[%/yr]	12.2%	12%	12%	38%	28%	34%	27%	35%	27%

8.8.2.3 Africa: Development of Load, Generation, and Residual Load

Table 8.48 shows that under the 2.0 °C Scenario, the transmission capacities need not exceed the assumed 25% interconnection capacity. If the exchange capacity between Africa’s sub-regions is 20%—as calculated under the 1.5 °C Scenario—additional capacity will be required. Therefore, a 25% interconnection capacity seems a good target for high renewable penetration scenarios in Africa. The load in all sub-regions—from North Africa to South Africa—will increase significantly. The greatest increase is calculated for Southern Africa, with the load increasing by a factor of 7, followed by Central Africa (a factor of 6.5), East Africa (6), West Africa (5.5), and North Africa (4). The load increase in the Republic of South Africa will follow the patterns of other industrialized countries, more than doubling, due mainly to increases in electric mobility. The load increases in other parts of Africa will be first and foremost due to universal access to energy services for all households and favourable economic development.

Table 8.48

Africa: load, generation, and residual load development

Power generation structure		2.0 °C				1.5 °C
Africa		Max demand	Max generation	Max residual load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
Africa		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
North Africa	2020	23.8	19.3	8.4		23.8	20.2	7.8
	2030	31.0	33.9	4.2	0	34.0	43.6	6.0	4
	2050	99.3	161.9	63.6	0	109.8	186.1	28.5	48
West Africa	2020	38.7	19.5	19.7		38.6	22.9	16.5
	2030	64.7	56.7	25.3	0	66.5	58.5	24.5	0
	2050	214.4	310.3	164.6	0	216.1	355.7	118.0	22
Central Africa	2020	4.2	3.4	0.8		4.2	3.9	0.3
	2030	8.2	7.3	2.6	0	8.5	7.7	2.6	0
	2050	27.0	38.6	26.4	0	27.3	46.8	26.6	0
East Africa	2020	44.0	34.8	11.9		44.0	39.5	7.0
	2030	86.5	75.0	30.0	0	88.5	82.9	28.5	0
	2050	265.1	369.8	197.4	0	267.1	425.1	101.7	56
Southern Africa	2020	27.8	24.2	4.0		27.7	25.4	2.3
	2030	67.2	57.9	35.9	0	68.3	74.5	36.6	0
	2050	199.3	359.3	169.9	0	199.6	407.3	111.5	96
South Africa	2020	25.3	23.5	1.7		25.3	23.5	2.7
	2030	22.4	30.0	3.3	4	30.4	37.5	7.0	0
	2050	70.1	122.9	24.7	28	94.9	141.5	25.4	21

Table 8.49 provides an overview of the calculated storage and dispatch power requirements by African sub-region. East and West Africa will require the highest battery capacity, due to the very high share of solar PV battery systems in rural and residential areas with low power grid availability. Like the Middle East, Africa is one of the global renewable fuel production regions and it is assumed that all sub-regions of Africa have equal amounts of energy export potential. However, a more detailed examination of export energy is required, which is beyond the scope of this project.

Table 8.49

Africa: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
Africa		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
Africa		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
North Africa	2020	0	0	0	0	0	0	0	0	0	0
	2030	1456	44	857	901	0	4611	65	1500	1565	0
	2050	59,499	1959	2904	4864	37,284	77,546	1976	2994	4969	2904
West Africa	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	1	11	12	0	18	10	126	136	0
	2050	62,015	2525	3154	5679	41,842	125,281	2552	3797	6349	10,940
Central Africa	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	0	0	0	0	0	0
	2050	4938	293	298	590	6107	10,557	323	391	714	3879
East Africa	2020	0	0	0	0	0	0	0	0	0	0
	2030	54	45	827	872	0	1960	78	1787	1865	0
	2050	104,983	3467	4976	8444	65,953	182,399	3573	5673	9246	6375
Southern Africa	2020	0	0	0	0	0	0	0	0	0	0
	2030	609	33	640	673	0	3268	49	1053	1102	0
	2050	110,532	2122	3371	5493	42,521	177,898	2189	3818	6008	19,886
South Africa	2020	0	0	0	0	0	0	0	0	0	0
	2030	2757	113	2155	2268	0	1407	46	877	923	0
	2050	25,233	2659	3245	5904	19,194	11,741	2038	1886	3924	0
Africa	2020	0	0	0	0	0	0	0	0	0	0
	2030	4877	237	4489	4726	0	11,264	248	5343	5591	0
	2050	367,201	13,026	17,948	30,974	212,902	585,423	12,651	18,558	31,210	43,984

8.9 The Middle East

8.9.1 The Middle East: Long-Term Energy Pathways

8.9.1.1 The Middle East: Final Energy Demand by Sector

The future development pathways for the Middle East’s final energy demand when the assumptions on population growth, GDP growth, and energy intensity are combined are shown in Fig. 8.53 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will increase by 133% from the current 17,100 PJ/year to around 40,000 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will decrease by 8% compared with current consumption and will reach 15,800 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will reach 13,600 PJ, 20% below the 2015 demand level. In the 1.5 °C Scenario, the final energy demand in 2050 will be 14% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will increase from 650 TWh/year in 2015 to 1230 TWh/year (2.0 °C) and 1160 TWh/year (1.5 °C) by 2050. Compared with the 5.0 °C case (2330 TWh/year in 2050), the efficiency measures in the 2.0 °C and 1.5 °C Scenarios will save a maximum of 1100 TWh/year and 1170 TWh/year, respectively.

Electrification will lead to a significant increase in the electricity demand. In the 2.0 °C Scenario, the electricity demand for heating will rise to approximately 800 TWh/year due to electric heaters and heat pumps, and in the transport sector, the demand will rise to approximately 1700 TWh/year due to the increase in electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 1900 TWh/year. The gross power demand will thus rise from 1100 TWh/year in 2015 to 4700 TWh/year in 2050 in the 2.0 °C Scenario, 57% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 4100 TWh/year by 2045.

The efficiency gains could be even larger in the heating sector than in the electricity sector. In the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 10,100 PJ/year and 10,500 PJ/year, respectively, will be avoided through efficiency gains by 2050 compared with the 5.0 °C Scenario.

8.9.1.2 The Middle East: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power from renewable sources. By 2050, 100% of the electricity produced in the Middle East will come from renewable energy sources under the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 96% of the total electricity generation. Renewable electricity’s share of the total production will be 49% by 2030 and 91% by 2040. The installed capacity of renewables will reach about 430 GW by 2030 and 1910 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario is assumed to be 58%. In the 1.5 °C Scenario, the generation capacity from renewable energy will be approximately 1700 GW in 2050.

Table 8.50 shows the development of different renewable technologies in the Middle East over time. Figure 8.54 provides an overview of the overall power-generation structure in the Middle East. From 2020 onwards, the continuing growth of wind and PV, up to 480 GW and 1070 GW, respectively, will be complemented by up to 250 GW of solar thermal generation, as well as limited biomass, geothermal, and ocean energy, in the 2.0 °C Scenario. Both the 2.0 °C Scenario and 1.5 °C Scenario will lead to high proportions of variable power generation (PV, wind, and ocean) of 39% and 46%, respectively, by 2030, and 64% and 66%, respectively, by 2050.

Table 8.50

Middle East: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	16	20	22	25	29
	2.0 °C	16	22	22	25	29
	1.5 °C	16	22	22	25	29
Biomass	5.0 °C	0	0	1	3	7
	2.0 °C	0	2	3	4	4
	1.5 °C	0	3	3	4	4
Wind	5.0 °C	0	4	9	23	49
	2.0 °C	0	54	156	371	481
	1.5 °C	0	60	175	432	456
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	5	7	20	25
	1.5 °C	0	5	7	20	21
PV	5.0 °C	0	7	10	21	40
	2.0 °C	0	76	187	560	1069
	1.5 °C	0	92	236	587	928
CSP	5.0 °C	0	2	3	6	7
	2.0 °C	0	10	43	270	252
	1.5 °C	0	10	47	342	216
Ocean	5.0 °C	0	0	0	0	0
	2.0 °C	0	5	10	40	50
	1.5 °C	0	5	10	40	45
Total	5.0 °C	16	32	45	79	132
	2.0 °C	16	174	427	1290	1911
	1.5 °C	16	197	500	1449	1699

8.9.1.3 The Middle East: Future Costs of Electricity Generation

Figure 8.55 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated electricity-generation costs in 2015 (referring to full costs) were around 7.1 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2030, when they reach 14.8 ct/kWh, and then drop to 13.7 ct/kWh by 2050. The generation costs in the 2.0 °C Scenario will increase until 2030, when they reach 11.1 ct/kWh, and then drop to 6.1 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 10.7 ct/kWh, and then drop to 7.3 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs in 2050 will be 7.6 ct/kWh lower than in the 5.0 °C case. In the 1.5 °C Scenario, the generation costs in 2050 will be 6.4 ct/kWh lower than in the 5.0 °C case. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, growth in demand and increasing fossil fuel prices will cause the total electricity supply costs to rise from today’s $70 billion/year to more than $410 billion/year in 2050. In the 2.0 °C Scenario, the total supply costs will be $300 billion/year and in the 1.5 °C Scenario, they will be $310 billion/year. The long-term cost of electricity supply will be more than 27% lower in the 2.0 °C Scenario than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility. Further demand reductions in the 1.5 °C Scenario will result in total power-generation costs that are 24% lower than in the 5.0 °C case.

The generation costs without the CO₂ emission costs will increase in the 5.0 °C case to 11.1 ct/kWh by 2030, and then stabilize at 10.8 ct/kWh by 2050. In the 2.0 °C Scenario and the 1.5 °C Scenario, they will increase to a maximum of 9 ct/kWh in 2030, before they drop to 6.1 ct/kWh and 7.3 ct/kWh by 2050, respectively. In the 2.0 °C Scenario, the generation costs will be 4.7 ct/kWh lower than in the 5.0 °C case and this maximum difference will occur in 2050. In the 1.5 °C Scenario, the maximum difference in generation costs compared with the 5.0 °C case will be 3.5 ct/kWh in 2050. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will rise to about $320 billion/year by 2050.

8.9.1.4 The Middle East: Future Investments in the Power Sector

An investment of around $3450 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including additional power plants for the production of hydrogen and synthetic fuels and investments in plant replacement at the ends of their economic lives. This value will be equivalent to approximately $96 billion per year on average, and this is $2720 billion more than in the 5.0 °C case ($730 billion). An investment of around $3470 billion for power generation will be required between 2015 and 2050 in the 1.5 °C Scenario, or on average, $96 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will be around 68% of the total cumulative investments, whereas approximately 32% will be invested in renewable power generation and co-generation (Fig. 8.56). However, in both alternative scenarios, the Middle East will shift almost 94% of its entire investments to renewables and co-generation. By 2030, the fossil fuel share of power sector investment will predominantly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $2900 billion in 2050, equivalent to $81 billion per year. Therefore, the total fuel cost savings will be equivalent to 110% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $3100 billion, or $86 billion per year.

8.9.1.5 The Middle East: Energy Supply for Heating

The final energy demand for heating will increase by 139% in the 5.0 °C Scenario, from 7100 PJ/year in 2015 to 17,100 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 59% in 2050 in the 2.0 °C Scenario, relative to the 5.0 °C case, and by 62% in the 1.5 °C Scenario. Today, renewables supply almost none of the Middle East’s final energy demand for heating. Renewable energy will provide 23% of the Middle East’s total heat demand in 2030 in the 2.0 °C Scenario and 25% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.57 shows the development of different technologies for heating in the Middle East over time, and Table 8.51 provides the resulting renewable heat supply for all scenarios. The growing use of solar, geothermal, and environmental heat will supplement electrification, with solar heat becoming the main direct renewable heat source in the 2.0 °C Scenario and 1.5 °C Scenario.

Table 8.51

Middle East: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	20	56	86	169	291
	2.0 °C	20	101	132	200	196
	1.5 °C	20	92	124	183	155
Solar heating	5.0 °C	8	92	284	778	1113
	2.0 °C	8	404	932	1535	1961
	1.5 °C	8	393	909	1475	1619
Geothermal heat and heat pumps	5.0 °C	0	0	0	0	0
	2.0 °C	0	118	232	565	1387
	1.5 °C	0	115	226	540	1057
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	51	488	946
	1.5 °C	0	0	48	828	915
Total	5.0 °C	28	149	370	947	1404
	2.0 °C	28	624	1346	2788	4489
	1.5 °C	28	601	1307	3025	3746

Heat from renewable hydrogen will further reduce the dependence on fossil fuels in both scenarios. Hydrogen consumption in 2050 will be around 950 PJ/year in the 2.0 °C Scenario and 920 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of 9–10 between 2015 and 2050, and its final energy share will be 36% in 2050 in the 2.0 °C Scenario and 43% in the 1.5 °C Scenario (Fig. 8.57).

8.9.1.6 The Middle East: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies to 2050 will amount to less than $440 billion in the 2.0 °C Scenario (including investments for plant replacement after their economic lifetimes), or approximately $12 billion per year. The largest share of investments in the Middle East is assumed to be for heat pumps (more than $200 billion), followed by solar collectors and geothermal heat use. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies. However, the lower heat demand (compared with the 2.0 °C Scenario) will result in a lower average annual investment of around $10 billion per year (Table 8.52, Fig. 8.58).

Table 8.52

Middle East: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	4	10	14	25	38
	2.0 °C	4	13	15	18	14
	1.5 °C	4	12	15	17	13
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	2	8	19	30
	1.5 °C	0	2	8	18	35
Solar heating	5.0 °C	1	17	51	139	198
	2.0 °C	1	72	142	217	252
	1.5 °C	1	71	139	209	206
Heat pumps	5.0 °C	0	0	0	0	0
	2.0 °C	0	12	17	43	122
	1.5 °C	0	12	17	42	76
Total^a	5.0 °C	6	26	65	164	237
	2.0 °C	6	99	183	297	418
	1.5 °C	6	96	178	286	330

^a Excluding direct electric heating

8.9.1.7 The Middle East: transport

Energy demand in the transport sector in the Middle East is expected to increase in the 5.0 °C Scenario by 133%, from around 5700 PJ/year in 2015 to 13,300 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 67% (8860 PJ/year) by 2050 compared with the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in the transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 79% (or 10,400 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.53, Fig. 8.59).

Table 8.53

Middle East: projection of transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	184	38	48	65	75
	2.0 °C	184	64	103	169	157
	1.5 °C	184	89	117	161	194
Road	5.0 °C	5425	6613	7802	10,999	12,992
	2.0 °C	5425	5928	5732	4510	4194
	1.5 °C	5425	5246	4528	2899	2618
Domestic aviation	5.0 °C	57	83	103	136	146
	2.0 °C	57	60	57	47	37
	1.5 °C	57	57	52	36	28
Domestic navigation	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	0	0	0
	1.5 °C	0	0	0	0	0
Total	5.0 °C	5666	6734	7954	11,200	13,213
	2.0 °C	5666	6051	5893	4726	4388
	1.5 °C	5666	5392	4697	3096	2840

By 2030, electricity will provide 4% (70 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas in 2050, the share will be 39% (480 TWh/year). In 2050, up to 620 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 350 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 450 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of 370 PJ/year. Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum consumption of 1670 PJ/year in 2050. Biofuel use in the 1.5 °C Scenario with have a maximum of 430 PJ/year. The maximum synthetic fuel demand will amount to 920 PJ/year.

8.9.1.8 The Middle East: Development of CO₂ Emissions

In the 5.0 °C Scenario, the Middle East’s annual CO₂ emissions will increase by 76% from 1760 Mt. in 2015 to 3094 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause the annual emissions to fall to 510 Mt. in 2040 in the 2.0 °C Scenario and to 220 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 90 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 38 Gt and 31 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 58% in the 2.0 °C Scenario and by 66% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario, this reduction will be greatest in ‘Industry’ followed by the ‘Power generation’ and ‘Transport’ sectors (Fig. 8.60).

8.9.1.9 The Middle East: Primary Energy Consumption

The levels of primary energy consumption in the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.61. In the 2.0 °C Scenario, the primary energy demand will decrease by 16%, from around 30,300 PJ/year in 2015 to 25,400 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 59% by 2050 in the 2.0 °C Scenario (5.0 °C: 61,700 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (22,300 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 18% in 2030 and 88% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 86% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out in 2035 in both the 2.0 °C and the 1.5 °C Scenarios. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 830 EJ, the cumulative coal consumption to about 10 EJ, and the crude oil consumption to 630 EJ. In the 2.0 °C Scenario, the cumulative gas demand will amount to 330 EJ, the cumulative coal demand to 1 EJ, and the cumulative oil demand to 310 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 280 EJ for natural gas, 0.9 EJ for coal, and 270 EJ for oil.

8.9.2 The Middle East: Power Sector Analysis

The Middle East has significant renewable energy potential. The region’s solar radiation is among the highest in the world and it has good wind conditions in coastal areas and in its mountain ranges. The electricity market is fragmented, and policies differ significantly. However, most countries are connected to their neighbours by transmission lines. Saudi Arabia, the geographic centre of the region, has connections to most neighbouring countries. Both the 2.0 °C Scenario and the 1.5 °C Scenario assume that the Middle East will remain a significant player in the energy market, moving from oil and gas to solar, and that it will play an important role in producing synthetic fuels and hydrogen for export.

8.9.2.1 The Middle East: Development of Power Plant Capacities

The overwhelming majority of fossil-fuel-based power generation in the Middle East is from gas-fired power plants. Both scenarios assume that this gas capacity (in GW) will remain on the same level until 2050, but will be converted to hydrogen. The annual market for solar PV must increase to 2.5 GW in 2020 and to 28.5 GW by 2030 in the 2.0 °C Scenario, and to 35 GW in the 1.5 °C Scenario. The onshore wind market must expand to 10 GW by 2025 in both scenarios. This represents a very ambitious target because the market for wind power plants in the Middle East has never been higher than 117 MW (GWEC 2018) (in 2015). Parts of the offshore oil and gas industry can be transitioned into an offshore wind industry. The total capacity assumed for the Middle East by 2050 is 20–25 GW under both scenarios. For comparison, the UK had an installed capacity for offshore wind of 6.8 GW and Germany of 5.4 GW in 2017 (GWEC 2018). The vast solar resources in the Middle East make it suitable for CSP plants—the total capacity by 2050 is calculated to be 252 GW (2.0 °C Scenario), equal to the gas power plant capacity in the Middle East in 2017 (Table 8.54).

Table 8.54

Middle East: average annual change in installed power plant capacity

Middle East – power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	0.0	0.0	0.0	0.0	0.0	0.0
Lignite	0.0	0.0	0.0	0.0	0.0	0.0
Gas	1.5	7.0	1.9	6.2	−19.1	3.0
Hydrogen-gas	0.0	0.3	1.5	1.7	20.3	24.2
Oil/Diesel	−0.1	−4.0	−8.9	−8.1	−0.8	−0.5
Nuclear	−0.1	0.0	−0.1	−0.1	0.0	0.0
Biomass	0.2	0.3	0.2	0.1	0.2	0.0
Hydro	1.0	0.5	0.2	0.2	0.5	0.5
Wind (onshore)	6.5	19.3	28.3	35.5	14.7	7.6
Wind (offshore)	0.2	0.5	0.8	0.8	1.4	1.2
PV (roof top)	7.3	19.0	26.2	29.9	46.4	32.3
PV (utility scale)	2.4	6.3	8.7	10.0	15.5	10.8
Geothermal	0.6	0.8	1.1	1.1	1.0	0.6
Solar thermal power plants	1.3	5.4	13.1	20.3	11.4	3.7
Ocean energy	0.3	1.3	1.3	2.5	1.0	1.7
Renewable fuel based co-generation	0.0	0.0	0.1	0.1	0.0	0.0

8.9.2.2 Middle East: Utilization of Power-Generation Capacities

In 2015, the base year of the scenario calculations, the Middle East had less than 0.5% variable power generation. Table 8.55 shows the rapidly increasing shares of variable renewable power generation across the Middle East. Israel is included in the Middle East region (as opposed to the IEA region used for the long-term scenario) to reflect its current and possible future interconnection with the regional power system. The current interconnection capacity between all sub-regions is assumed to be 5%, increasing to 20% in 2030 and 25% in 2050. Dispatchable renewables will have a stable market share of around 15%–20% over the entire modelling period in the 2.0 °C Scenario and 15%–20% in the 1.5 °C Scenario.

Table 8.55

Middle East: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
Middle East		Variable RE	Dispatch RE	Dispatch fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch fossil	Inter-connection
Israel	2015	0%	12%	88%	5%
	2030	41%	18%	41%	20%	46%	18%	36%	15%
	2050	81%	18%	0%	25%	64%	15%	21%	20%
North-ME	2015	0%	12%	88%	5%
	2030	50%	20%	30%	20%	55%	19%	26%	15%
	2050	83%	17%	0%	25%	74%	15%	10%	20%
Saudi Arabia-ME	2015	0%	12%	88%	5%
	2030	51%	17%	32%	20%	55%	17%	28%	15%
	2050	83%	17%	0%	25%	72%	16%	12%	20%
UAE-ME	2015	0%	12%	88%	5%
	2030	36%	20%	45%	20%	40%	20%	40%	15%
	2050	76%	24%	0%	25%	53%	18%	28%	20%
East-ME	2015	0%	12%	88%	5%
	2030	42%	20%	38%	20%	47%	21%	32%	15%
	2050	80%	20%	0%	25%	63%	17%	20%	20%
Iraq-ME	2015	0%	12%	88%	5%
	2030	60%	18%	21%	20%	65%	17%	18%	15%
	2050	82%	18%	0%	25%	76%	16%	7%	20%
Iran-ME	2015	0%	12%	88%	5%
	2030	57%	19%	24%	20%	62%	18%	21%	15%
	2050	81%	19%	0%	25%	73%	17%	9%	20%
Middle East	2015	0%	12%	88%
	2030	51%	19%	31%		56%	18%	27%
	2050	81%	19%	0%		70%	16%	13%

Average capacity factors correspond to the results for the other world regions. Table 8.56 shows that the limited dispatchable fossil and nuclear generation will drop quickly, whereas the significant gas power plant capacity within the region can increase capacity factors to take over their load and reduce carbon emissions at an early stage. The calculation results are attributed to the assumed dispatch order, which prioritizes gas over coal and nuclear.

Table 8.56

Middle East: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
Middle East			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	52.6%	45%	43%	27%	24%	34%	21%	29%	25%
Limited dispatchable: fossil and nuclear	[%/yr]	31.1%	13%	13%	5%	2%	19%	3%	10%	5%
Limited dispatchable: renewable	[%/yr]	26.3%	34%	34%	47%	42%	50%	21%	28%	30%
Dispatchable: fossil	[%/yr]	52.9%	41%	40%	15%	10%	45%	8%	17%	16%
Dispatchable: renewable	[%/yr]	38.9%	83%	83%	66%	57%	43%	20%	36%	38%
Variable: renewable	[%/yr]	6.6%	12%	12%	24%	23%	27%	23%	29%	25%

8.9.2.3 The Middle East: Development of Load, Generation, and Residual Load

The Middle East is assumed to be one of the exporters of solar electricity into the EU, so the calculated solar installation capacities throughout the region will be significantly higher than required for self-supply.

Table 8.57 shows a negative residual load in almost all sub-regions for every year and in both scenarios. This is attributable to substantial oversupply, so the production of renewables is almost constantly higher than the demand. This electricity has been calculated as exports from the Middle East and imports to Europe.

Table 8.57

Middle East: load, generation, and residual load development

Power generation structure		2.0 °C				1.5 °C
Middle East		Max demand	Max generation	Max residual load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
Middle East		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
Israel	2020	11.5	11.0	−2.9		11.5	11.9	−2.9
	2030	14.0	17.3	−1.8	5	14.3	19.9	−1.4	7
	2050	29.7	62.7	−3.7	37	29.3	55.2	−10.3	36
North-ME	2020	33.7	25.7	−12.1		33.8	29.4	−11.6
	2030	39.7	44.6	−12.1	17	40.6	52.6	−11.2	23
	2050	83.6	196.5	−11.5	124	77.5	172.8	−19.9	115
Saudi Arabia-ME	2020	59.5	45.9	−3.4		59.6	45.4	−2.4
	2030	72.4	85.9	2.3	11	75.1	99.8	5.6	19
	2050	173.6	380.9	−21.7	229	168.6	334.0	−59.4	225
UAE-ME	2020	21.2	29.8	−0.4		21.2	29.6	1.3
	2030	26.0	44.1	2.2	16	27.0	50.7	3.4	20
	2050	62.2	120.2	−7.4	65	61.3	105.4	−23.4	67
East-Middle East	2020	12.0	23.3	−2.5		12.0	22.6	−2.6
	2030	14.8	31.3	−1.2	18	15.1	35.9	−0.8	22
	2050	32.5	63.4	−3.9	35	31.2	55.6	−7.2	32
Iraq-ME	2020	20.1	13.8	−7.6		20.2	13.8	−7.3
	2030	26.0	30.4	−7.4	12	26.8	35.8	−8.1	17
	2050	64.3	137.5	−7.8	81	57.7	119.9	−20.0	82
Iran-ME	2020	49.4	56.9	−12.2		49.4	56.4	−12.2
	2030	76.1	88.1	−14.3	26	78.3	103.9	−11.4	37
	2050	188.5	399.1	−22.7	233	174.3	348.0	−40.5	214

The Middle East will be one of three dedicated renewable energy export regions. These exports are in the form of renewable fuels and electricity. The [R]E 24/7 model does not calculate electricity exchange in 1 h steps between the world regions, and therefore the amount of electricity exported accumulates from year to year. The load curves for the Middle East and European regions are not calculated separately.

Table 8.58 provides an overview of the calculated storage and dispatch power requirements by sub-region in the Middle East. Iran and Saudi Arabia West Africa will require the highest storage capacity, due to the very high share of solar PV systems in residential areas. Like the Africa, the Middle East is one of the global renewable fuel production regions and it is assumed that all sub-regions of the Middle East have equal amounts of energy export potential. However, a more detailed examination of export energy is required, which is beyond the scope of this project.

Table 8.58

Middle East: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
Middle East		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
Middle East		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
Israel	2020	0	0	0	0	0	0	0	0	0	0
	2030	29	0	10	10	0	226	0	36	36	8
	2050	24,725	11	379	390	0	14,244	11	320	331	529
North-ME	2020	0	0	0	0	0	0	0	0	0	0
	2030	1164	0	193	194	0	3596	1	355	356	20
	2050	109,498	32	1409	1441	0	84,974	31	1434	1465	1193
Saudi Arabia	2020	0	0	0	0	0	0	0	0	0	0
	2030	3366	1	513	514	0	11,457	2	900	902	39
	2050	231,140	73	2685	2757	0	159,949	74	2429	2503	2624
UAE	2020	0	0	0	0	0	0	0	0	0	0
	2030	9	0	5	5	0	233	0	45	45	17
	2050	35,463	24	679	703	0	17,093	23	507	531	1075
East-ME	2020	0	0	0	0	0	0	0	0	0	0
	2030	2	0	3	3	0	117	0	29	29	9
	2050	21,916	12	410	421	0	12,920	12	350	362	490
Iraq	2020	0	0	0	0	0	0	0	0	0	0
	2030	3941	0	330	330	0	8185	0	446	447	10
	2050	87,343	18	892	910	0	74,252	17	920	937	684
Iran	2020	0	0	0	0	0	0	0	0	0	0
	2030	9576	1	831	833	0	21,130	1	1127	1128	30
	2050	242,799	50	2508	2558	0	190,790	47	2443	2490	2036
Middle East	2020	0	0	0	0	0	0	0	0	0	0
	2030	18,088	4	1886	1890	0	44,945	4	2939	2943	132
	2050	752,882	218	8962	9180	0	554,222	215	8404	8618	8630

8.10 Eastern Europe/Eurasia

8.10.1 Eastern Europe/Eurasia: Long-Term Energy Pathways

8.10.1.1 Eastern Europe/Eurasia: Final Energy Demand by Sector

The future development pathways for Eastern Europe/Eurasia’s final energy demand when the assumptions on population growth, GDP growth, and energy intensity are combined are shown in Fig. 8.62 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will increase by 45%, from the current 25,500 PJ/year to 37,000 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will decrease by 25% compared with current consumption and will reach 19,100 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will reach 17,800 PJ, 30% below the 2015 level. In the 1.5 °C Scenario, the final energy demand in 2050 will be 7% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will increase from 910 TWh/year in 2015 to 1000 TWh/year (2.0 °C) or 940 TWh/year (1.5 °C) by 2050. Compared with the 5.0 °C case (1600 TWh/year in 2050), the efficiency measures in the 2.0 °C and 1.5 °C Scenarios will save a maximum of 600 TWh/year and 660 TWh/year, respectively.

Electrification will lead to a significant increase in the electricity demand by 2050. In the 2.0 °C Scenario, the electricity demand for heating will be approximately 700 TWh/year due to electric heaters and heat pumps, and in the transport sector, the electricity demand will be approximately 2300 TWh/year due to increased electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 2300 TWh/year. Therefore, the gross power demand will rise from 1700 TWh/year in 2015 to 4900 TWh/year in 2050 in the 2.0 °C Scenario, 88% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 4800 TWh/year in 2050.

Efficiency gains could be even larger in the heating sector than in the electricity sector. In the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to more than 10,700 PJ/year is avoided by 2050 compared with the 5.0 °C Scenario through efficiency gains.

8.10.1.2 Eastern Europe/Eurasia: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power from renewable sources. By 2050, 100% of the electricity produced in Eastern Europe/Eurasia will come from renewable energy sources in the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 75% of the total electricity generation. Renewable electricity’s share of the total production will be 55% by 2030 and 84% by 2040. The installed capacity of renewables will reach about 560 GW by 2030 and 1900 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario is assumed to be 66%. In the 1.5 °C Scenario, the generation capacity from renewable energy will be approximately 1870 GW in 2050.

Table 8.59 shows the development of different renewable technologies in Eastern Europe/Eurasia over time. Figure 8.63 provides an overview of the overall power-generation structure in Eastern Europe/Eurasia. From 2020 onwards, the continuing growth of wind and PV, up to 740 GW and 820 GW, respectively, will be complemented by up to 30 GW of solar thermal generation, as well as limited biomass, geothermal, and ocean energy, in the 2.0 °C Scenario. Both the 2.0 °C Scenario and 1.5 °C Scenario will lead to a high proportion of variable power generation (PV, wind, and ocean) of 28% and 32%, respectively, by 2030, and 62% and 61%, respectively, by 2050.

Table 8.59

Eastern Europe/Eurasia: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	98	107	112	123	136
	2.0 °C	98	107	112	115	116
	1.5 °C	98	107	112	115	116
Biomass	5.0 °C	1	4	6	9	14
	2.0 °C	1	21	45	64	96
	1.5 °C	1	40	74	86	109
Wind	5.0 °C	6	9	10	17	23
	2.0 °C	6	70	176	469	744
	1.5 °C	6	74	196	531	697
Geothermal	5.0 °C	0	1	1	2	4
	2.0 °C	0	5	12	38	71
	1.5 °C	0	7	21	46	71
PV	5.0 °C	4	5	6	8	10
	2.0 °C	4	108	209	502	817
	1.5 °C	4	132	294	678	821
CSP	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	1	16	33
	1.5 °C	0	0	1	22	34
Ocean	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	1	13	19
	1.5 °C	0	0	1	13	19
Total	5.0 °C	108	126	136	159	186
	2.0 °C	108	310	555	1216	1896
	1.5 °C	108	360	698	1492	1869

8.10.1.3 Eastern Europe/Eurasia: Future Costs of Electricity Generation

Figure 8.64 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated electricity-generation costs in 2015 (referring to full costs) were around 4.5 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2050, when they reach 10 ct/kWh. In the 2.0 °C Scenario, the generation costs will increase until 2050, when they will reach 8.6 ct/kWh. In the 1.5 °C Scenario, they will increase to 9.3 ct/kWh, and then drop to 8.8 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs in 2050 will be 1.4 ct/kWh lower than in the 5.0 °C case. In the 1.5 °C Scenario, the generation costs in 2050 will be 1.1 ct/kWh lower than in the 5.0 °C case. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, the growth of demand and increasing fossil fuel prices will cause the total electricity supply costs to rise from today’s $120 billion/year to more than $320 billion/year in 2050. In both alternative scenarios, the total supply costs will be $490 billion/year in 2050. The long-term costs of electricity supply will be more than 54% higher in the 2.0 °C Scenario than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility. Further electrification and synthetic fuel generation in the 1.5 °C Scenario will result in total power generation costs that are 55% higher than in the 5.0 °C case.

Compared with these results, the generation costs when the CO₂ emission costs are not considered will increase in the 5.0 °C case to 6.9 ct/kWh. In the 2.0 °C Scenario, the generation costs will increase continuously until 2050, when they reach 8.6 ct/kWh. They will increase to 8.8 ct/kWh in the 1.5 °C Scenario. In the 2.0 °C Scenario, the generation costs will reach a maximum, at 1.7 ct/kWh higher than in the 5.0 °C case, and this will occur in 2050. In the 1.5 °C Scenario, the maximum difference in generation costs compared with the 5.0 °C case will be 2.6 ct/kWh in 2040. The generation costs in 2050 will still be 2 ct/kWh higher than in the 5.0 °C case. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will rise to about $240 billion in 2050.

8.10.1.4 Eastern Europe/Eurasia: Future Investments in the Power Sector

An investment of around $3600 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including additional power plants for the production of hydrogen and synthetic fuels and investments in plant replacement at the end of their economic lives. This value is equivalent to approximately $100 billion per year on average, and is $2660 billion more than in the 5.0 °C case ($940 billion). An investment of around $3770 billion for power generation will be required between 2015 and 2050 in the 1.5 °C Scenario. On average, this is an investment of $105 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will be around 40% of the total cumulative investments, whereas approximately 60% will be invested in renewable power generation and co-generation (Fig. 8.65).

However, in the 2.0 °C (1.5 °C) scenario, Eastern Europe/Eurasia will shift almost 97% (98%) of its entire investments to renewables and co-generation. By 2030, the fossil fuel share of the power sector investments will predominantly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $1730 billion in 2050, equivalent to $48 billion per year. Therefore, the total fuel cost savings will be equivalent to 70% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $1900 billion, or $53 billion per year.

8.10.1.5 Eastern Europe/Eurasia: Energy Supply for Heating

The final energy demand for heating will increase in the 5.0 °C Scenario by 46%, from 15,700 PJ/year in 2015 to 22,900 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 47% in 2050 in both alternative scenarios. Today, renewables supply around 4% of Eastern Europe/Eurasia’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 29% of Eastern Europe/Eurasia’s total heat demand in 2030 in the 2.0 °C Scenario and 42% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.66 shows the development of different technologies for heating in Eastern Europe/Eurasia over time, and Table 8.60 provides the resulting renewable heat supply for all scenarios. Until 2030, biomass will remain the main contributor. In the long term, the growing use of solar, geothermal, and environmental heat will lead to a biomass share of 28% in both alternative scenarios.

Table 8.60

Eastern Europe/Eurasia: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	537	810	873	1005	1164
	2.0 °C	537	1604	2199	2971	2819
	1.5 °C	537	1869	2684	2734	2722
Solar heating	5.0 °C	5	10	13	24	41
	2.0 °C	5	277	706	1560	1662
	1.5 °C	5	351	768	1395	1620
Geothermal heat and heat pumps	5.0 °C	6	9	11	15	21
	2.0 °C	6	265	780	2314	3493
	1.5 °C	6	410	1163	2434	3393
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	42	152	795	1934
	1.5 °C	0	155	494	1344	2032
Total	5.0 °C	548	829	897	1044	1226
	2.0 °C	548	2187	3837	7640	9908
	1.5 °C	548	2786	5110	7906	9767

The direct use of electricity for heating will also increases by a factor of 2.7 between 2015 and 2050, and its final energy share will be 18% in 2050 in the 2.0 °C Scenario and 19% in the 1.5 °C Scenario.

8.10.1.6 Eastern Europe/Eurasia: Future Investments in the Heating Sector

The roughly estimated investment in renewable heating technologies up to 2050 will amount to around $1070 billion in the 2.0 °C Scenario (including investments in plant replacement after their economic lifetimes), or approximately $30 billion per year. The largest share of the investments in Eastern Europe/Eurasia is assumed to be for heat pumps (around $490 billion), followed by solar collectors and biomass technologies. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies. However, the lower heat demand (compared with the 2.0 °C Scenario) will result in a lower average annual investment of around $29 billion per year (Table 8.61, Fig. 8.67).

Table 8.61

Eastern Europe/Eurasia: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	107	150	157	169	183
	2.0 °C	107	230	249	263	172
	1.5 °C	107	241	252	230	162
Geothermal	5.0 °C	0	0	0	1	1
	2.0 °C	0	14	26	64	61
	1.5 °C	0	12	30	52	54
Solar heating	5.0 °C	1	2	3	5	9
	2.0 °C	1	56	145	330	359
	1.5 °C	1	74	163	300	352
Heat pumps	5.0 °C	1	1	2	2	3
	2.0 °C	1	25	64	184	248
	1.5 °C	1	33	76	175	236
Total^a	5.0 °C	109	154	162	177	196
	2.0 °C	109	325	483	841	839
	1.5 °C	109	361	522	758	805

^a Excluding direct electric heating

8.10.1.7 Eastern Europe/Eurasia: Transport

Energy demand in the transport sector in Eastern Europe/Eurasia is expected to increase in the 5.0 °C Scenario by 34%, from around 6000 PJ/year in 2015 to 8000 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 48% (3840 PJ/year) by 2050 compared with the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in the transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 62% (or 4970 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.62, Fig. 8.68).

Table 8.62

Eastern Europe/Eurasia: projection of transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	434	498	528	599	674
	2.0 °C	434	509	544	646	712
	1.5 °C	434	449	470	620	796
Road	5.0 °C	3873	4321	4680	5181	5319
	2.0 °C	3873	4336	4403	3923	3195
	1.5 °C	3873	3593	2963	2346	2016
Domestic aviation	5.0 °C	232	336	403	482	471
	2.0 °C	232	247	228	188	150
	1.5 °C	232	237	207	146	114
Domestic navigation	5.0 °C	34	35	36	38	40
	2.0 °C	34	35	36	38	40
	1.5 °C	34	35	36	38	40
Total	5.0 °C	4573	5191	5647	6301	6504
	2.0 °C	4573	5127	5210	4795	4097
	1.5 °C	4573	4313	3677	3150	2966

By 2030, electricity will provide 14% (240 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas in 2050, the share will be 54% (630 TWh/year). In 2050, up to 410 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 510 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 330 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of 720 PJ/year Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 880 PJ/year in 2050. With the lower overall energy demand in transport, biofuel use will also be reduced in the 1.5 °C Scenario to a maximum of 700 PJ/year The maximum synthetic fuel demand will amount to 540 PJ/year.

8.10.1.8 Eastern Europe/Eurasia: Development of CO₂ Emissions

In the 5.0 °C Scenario, Eastern Europe/Eurasia’s annual CO₂ emissions will increase by 14%, from 2420 Mt. in 2015 to 2768 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause the annual emissions to fall to 590 Mt. in 2040 in the 2.0 °C Scenario and to 340 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 95 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 45 Gt and 36 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 53% in the 2.0 °C Scenario and by 62% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario, this reduction will be greatest in ‘Power generation’, followed by the ‘Residential and other’ and ‘Industry’ sectors (Fig. 8.69).

8.10.1.9 Eastern Europe/Eurasia: Primary Energy Consumption

The levels of primary energy consumption in the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.70. In the 2.0 °C Scenario, the primary energy demand will decrease by 25%, from around 46,000 PJ/year in 2015 to 34,600 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 40% by 2050 in the 2.0 °C Scenario (5.0 °C: 57,700 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (33,600 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 26% in 2030 and 91% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 90% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out by 2040 in both the 2.0 °C Scenario and 1.5 °C Scenario. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 840 EJ, the cumulative coal consumption to about 290 EJ, and the crude oil consumption to 340 EJ. In contrast, in the 2.0 °C Scenario, the cumulative gas demand will amount to 510 EJ, the cumulative coal demand to 100 EJ, and the cumulative oil demand to 160 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 450 EJ for natural gas, 70 EJ for coal, and 120 EJ for oil.

8.10.2 Eastern Europe/Eurasia: Power Sector Analysis

This region sits between the strong economic hubs of the EU, China, and India. Russia, by far the largest country within this region, is an important producer of oil and gas, and supplies all surrounding countries. Therefore, Eurasia will be key in future energy developments. Its renewable energy industry is among the smallest in the world, but recent developments indicate growth in both the wind (WPM 3-2018) and solar industries (PVM 3-2018).

8.10.2.1 Eurasia: Development of Power Plant Capacities—2.0 °C Scenario

The northern part of Eurasia and Mongolia have significant wind potential, whereas the southern part, especially in Central Asia, has substantial possibilities for utility-scale solar power plants—both for solar PV and concentrated solar. The annual market for solar PV and onshore wind—as for all other renewable power generation technologies—must develop from a very low MW range in 2017 to a GW market by 2025. Besides solar PV and onshore wind, bioenergy has significant potential in Eurasia, especially in the European part, Russia, and the agricultural regions around the Caspian Sea (Table 8.63).

Table 8.63

Eurasia: average annual change in installed power plant capacity

Eurasia power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	−1	−6	−6	−4	0	0
Lignite	−3	−4	−2	−1	0	0
Gas	4	1	0	−2	−17	−5
Hydrogen-gas	0	2	2	4	20	17
Oil/Diesel	−2	−2	−1	−1	0	0
Nuclear	−2	−3	−2	−4	−1	0
Biomass	3	8	3	5	4	2
Hydro	2	1	1	1	0	0
Wind (onshore)	7	20	26	28	24	21
Wind (offshore)	1	3	6	6	11	8
PV (roof top)	9	25	21	32	31	22
PV (utility scale)	3	8	7	11	10	7
Geothermal	1	3	2	4	4	3
Solar thermal power plants	0	0	1	1	1	2
Ocean energy	0	0	1	1	1	1
Renewable fuel based co-generation	2	7	4	7	5	3

8.10.2.2 Eurasia: Utilization of Power-Generation Capacities

Variable power generation starts at almost zero, but increases rapidly to over 30% in most sub-regions of Eurasia, as shown in Table 8.64.

Table 8.64

Eurasia: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
Eurasia		Variable RE	Dispatch RE	Dispatch fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch fossil	Inter-connection
Eastern Europe	2015	1%	35%	63%	5%
	2030	37%	45%	18%	10%	41%	46%	13%	10%
	2050	70%	22%	7%	20%	66%	24%	10%	20%
Russia	2015	1%	35%	63%	5%
	2030	35%	43%	22%	5%	39%	47%	14%	5%
	2050	68%	24%	8%	5%	64%	26%	10%	5%
Kazakhstan	2015	2%	35%	63%	5%
	2030	44%	42%	14%	5%	49%	42%	9%	5%
	2050	80%	16%	4%	5%	77%	18%	5%	5%
Mongolia	2015	2%	35%	63%	5%
	2030	43%	43%	13%	5%	48%	43%	10%	5%
	2050	74%	20%	6%	10%	71%	22%	8%	10%
West Caspian Sea	2015	1%	35%	63%	5%
	2030	43%	41%	16%	5%	47%	40%	12%	5%
	2050	77%	17%	6%	10%	72%	19%	9%	10%
East Caspian Sea	2015	1%	35%	63%	5%
	2030	37%	44%	19%	5%	41%	45%	14%	5%
	2050	71%	22%	7%	10%	67%	24%	10%	10%
Central Asia	2015	0%	35%	64%	5%
	2030	18%	50%	31%	5%	23%	50%	27%	5%
	2050	43%	39%	18%	5%	38%	37%	26%	5%
Eurasia	2015	1%	35%	63%
	2030	36%	43%	21%		40%	46%	14%
	2050	69%	23%	7%		65%	25%	10%

Table 8.64 shows that dispatchable renewables will experience stable market conditions throughout the entire modelling period across the whole region. Both scenarios assume that the interconnections between Eastern Europe and Russia will increase significantly, whereas the power transmission capacities for Kazakhstan, Central Asia, the area around the Caspian Sea, and Mongolia will remain low due to geographic distances.

Compared with other world regions, it will take longer for the capacity factor of the limited dispatchable power plants to drop below economic viability, as shown in Table 8.65.

Table 8.65

Eurasia: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
Eurasia			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	36.8%	31%	40%	48%	47%	34%	34%	34%	34%
Limited dispatchable: fossil and nuclear	[%/yr]	43.8%	31%	30%	22%	18%	19%	0%	7%	4%
Limited dispatchable: renewable	[%/yr]	39.3%	42%	42%	57%	54%	60%	39%	39%	40%
Dispatchable: fossil	[%/yr]	27.6%	18%	17%	7%	6%	31%	8%	12%	15%
Dispatchable: renewable	[%/yr]	38.7%	48%	73%	73%	68%	41%	49%	50%	51%
Variable: renewable	[%/yr]	10.5%	11%	11%	40%	39%	25%	32%	32%	33%

Table 8.65. The capacity factor of variable renewables will rise by 2030, mainly due to increased deployment of wind and concentrated solar power with storage. The average capacity factor of the power-generation fleet will be around 35% by 2050 and will therefore be on the same level as it was 2015 in both scenarios.

8.10.2.3 Eurasia: Development of Load, Generation, and Residual Load

The modelling of both scenarios predicts small increases in interconnection beyond those assumed to occur by 2030 (see Table 8.64).

Table 8.64. However, after 2030, significant increases will be required by 2050, especially in Russia. The export of renewable electricity can also take place via existing gas pipelines with power-to-gas technologies. Between 2030 and 2050, the loads for all regions will double, due to the increased electrification of the heating, industry, and transport sectors (Table 8.66).

Table 8.66

Eurasia: load, generation, and residual load development

Power generation structure		2.0 °C				1.5 °C
Eurasia		Max demand	Max generation	Max residual load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
Eurasia		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
Eastern Europe	2020	32.9	30.8	3.9		32.9	33.0	4.6
	2030	38.1	45.0	12.4	0	40.8	56.2	14.2	1
	2050	77.2	179.6	30.9	71	77.5	174.3	31.6	65
Russia	2020	172.7	95.8	83.6		172.7	100.6	81.8
	2030	214.2	218.6	103.5	0	221.4	275.2	94.9	0
	2050	428.3	887.6	191.7	268	429.2	859.0	194.4	235
Kazakhstan	2020	14.7	18.8	0.9		14.7	17.9	0.9
	2030	17.9	18.6	8.3	0	18.9	23.1	7.7	0
	2050	34.3	74.5	14.1	26	34.4	72.2	14.4	23
Mongolia	2020	1.7	2.0	0.1		1.7	2.0	0.1
	2030	2.0	2.3	0.9	0	2.1	2.9	0.9	0
	2050	3.7	8.5	1.2	4	3.7	8.4	1.2	3
West Caspian Sea	2020	10.7	6.2	4.6		10.7	6.9	4.2
	2030	12.5	13.9	6.4	0	13.4	17.3	5.9	0
	2050	24.3	55.8	9.8	22	24.4	54.1	10.0	20
East Caspian Sea	2020	21.6	7.5	14.2		21.6	7.8	13.8
	2030	25.2	28.2	12.7	0	26.9	35.0	12.5	0
	2050	50.0	113.4	18.6	45	50.2	109.7	19.1	40
Central Asia	2020	2.5	2.3	0.2		2.5	2.3	0.2
	2030	6.0	5.8	2.8	0	6.7	6.5	3.0	0
	2050	12.0	18.2	4.2	2	12.1	18.2	4.4	2

In Eurasia, the main storage technology for both scenarios is pumped hydro, whereas hydrogen plays a major role for the grid integration of variable generation (Table 8.67). Hydrogen production can also be used for load management, although not for short peak loads. Due to the technical and economic limitations associated with the increased interconnection via transmission lines and pumped hydro storage systems, curtailment will be higher than the scenario target (a maximum of 10% by 2050). For Eastern Europe, Kazakhstan, Mongolia, and the East Caspian Sea, the calculated curtailment will be between 10% and 14%, whereas the West Caspian Region will have the highest curtailment of 19% in the 2.0 °C Scenario and 17% in the 1.5 °C Scenario. Further research and optimization are required.

Table 8.67

Eurasia: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
Eurasia		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
Eurasia		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
Eastern Europe	2020	0	0	0	0	0	0	0	0	0	0
	2030	373	1	137	138	1720	1674	2	317	319	5920
	2050	52,516	274	2626	2900	49,057	43,933	267	2303	2570	49,858
Russia	2020	0	0	0	0	0	0	0	0	0	0
	2030	36	0	41	41	9711	2290	3	517	520	33,707
	2050	147,854	1132	9342	10,474	282,100	123,490	1049	7895	8944	287,188
Kazakhstan	2020	0	0	0	0	0	0	0	0	0	0
	2030	7	0	7	7	690	281	1	84	85	2223
	2050	28,094	133	1444	1577	13,192	23,926	127	1271	1398	13,544
Mongolia	2020	0	0	0	0	0	0	0	0	0	0
	2030	24	0	11	11	78	131	0	25	25	258
	2050	3177	17	152	169	1997	2938	16	139	155	1971
West Caspian Sea	2020	0	0	0	0	0	0	0	0	0	0
	2030	163	0	78	79	472	882	1	173	174	1558
	2050	30,281	96	1207	1303	12,025	26,053	94	1120	1214	12,088
East Caspian Sea	2020	0	0	0	0	0	0	0	0	0	0
	2030	134	0	65	65	1125	773	1	170	170	3759
	2050	32,074	202	1785	1988	30,493	27,253	195	1580	1775	30,852
Central Asia	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	309	0	0	1	1	1090
	2050	2495	39	211	250	12,181	2391	39	207	245	12,037
Eurasia Eastern Europe	2020	0	0	0	0	0	0	0	0	0	0
	2030	736	2	339	341	14,106	6031	7	1287	1295	48,516
	2050	296,490	1894	16,767	18,661	401,044	249,984	1788	14,515	16,303	407,537

8.11 Non-OECD Asia

8.11.1 Non-OECD Asia: Long-Term Energy Pathways

8.11.1.1 Non-OECD Asia: Final Energy Demand by Sector

The future development pathways for Non-OECD Asia’s final energy demand when the assumptions on population growth, GDP growth, and energy intensity are combined are shown in Fig. 8.71 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will increase by 111% from the current 24,500 PJ/year to 51,800 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will increase at a much lower rate by 16% compared with current consumption, and will reach 28,300 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will reach 25,700 PJ, 5% above the 2015 demand. In the 1.5 °C Scenario, the final energy demand in 2050 will be 9% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will increase from 830 TWh/year in 2015 to 2480 TWh/year in 2050 in both alternative scenarios. Compared with the reference case (3880 TWh/year in 2050), the efficiency measures in the 2.0 °C and 1.5 °C scenarios will save 1400 TWh/year in 2050.

Electrification will lead to a significant increase in the electricity demand by 2050. In the 2.0 °C Scenario, the electricity demand for heating will be approximately 1500 TWh/year due to electric heaters and heat pumps, and in the transport sector, the electricity demand will be approximately 1700 TWh/year due to electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 1700 TWh/year. Therefore, the gross power demand will rise from 1400 TWh/year in 2015 to 6400 TWh/year in 2050 in the 2.0 °C Scenario, 33% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 6000 TWh/year in 2050.

The efficiency gains in the heating sector could be even larger than those in the electricity sector. In the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 6900 PJ/year and 8100 PJ/year, respectively, will be avoided by 2050 compared with the 5.0 °C Scenario, through efficiency gains.

8.11.1.2 Non-OECD Asia: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power from renewable sources. By 2050, 100% of the electricity produced in Non-OECD Asia will come from renewable energy sources in the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 87% of the total electricity generation. Renewable electricity’s share of the total production will be 59% by 2030 and 87% by 2040. The installed capacity of renewables will reach about 610 GW by 2030 and 2430 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario is assumed to be 74%. In the 1.5 °C Scenario, the generation capacity from renewable energy will be approximately 2320 GW in 2050.

Table 8.68 shows the development of different renewable technologies in Non-OECD Asia over time. Figure 8.72 provides an overview of the overall power-generation structure in Non-OECD Asia. From 2020 onwards, the continuing growth of wind and PV up to 635 GW and 1280 GW, respectively, will be complemented by up to 275 GW solar thermal generation, as well as limited biomass, geothermal, and ocean energy in the 2.0 °C Scenario. Both the 2.0 °C Scenario and 1.5 °C Scenario will lead to a high proportion of variable power generation (PV, wind, and ocean) of 34% and 48%, respectively, by 2030, and 64% and 66%, respectively, by 2050.

Table 8.68

Non-OECD Asia: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	63	85	124	151	183
	2.0 °C	63	86	86	90	91
	1.5 °C	63	86	86	90	91
Biomass	5.0 °C	7	10	17	22	31
	2.0 °C	7	19	19	30	36
	1.5 °C	7	19	20	31	39
Wind	5.0 °C	2	5	17	32	54
	2.0 °C	2	53	148	389	635
	1.5 °C	2	98	229	458	631
Geothermal	5.0 °C	3	4	6	8	10
	2.0 °C	3	6	23	50	63
	1.5 °C	3	7	26	47	54
PV	5.0 °C	3	9	26	44	70
	2.0 °C	3	107	287	806	1282
	1.5 °C	3	157	396	907	1256
CSP	5.0 °C	0	0	0	0	0
	2.0 °C	0	5	45	134	275
	1.5 °C	0	5	45	110	224
Ocean	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	2	20	50
	1.5 °C	0	0	2	15	30
Total	5.0 °C	78	113	191	257	348
	2.0 °C	78	276	610	1518	2432
	1.5 °C	78	373	804	1658	2325

8.11.1.3 Non-OECD Asia: Future Costs of Electricity Generation

Figure 8.73 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated electricity generation costs in 2015 (referring to full costs) were around 5.2 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2050, when they reach 11.7 ct/kWh. The generation costs will increase in the 2.0 °C Scenario until 2030, when they will reach 8.1 ct/kWh, and will drop to 6.3 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 7.9 ct/kWh, and drop to 6.1 ct/kWh by 2050. In both alternative scenarios, the generation costs in 2050 will be around 5.5 ct/kWh lower than in the 5.0 °C case. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, the growth in demand and increasing fossil fuel prices will cause the total electricity supply costs to rise from today’s $70 billion/year to more than $560 billion/year in 2050. In the 2.0 °C Scenario, the total supply costs will be $430 billion/year and in the 1.5 °C Scenario they will be $390 billion/year. The long-term costs for electricity supply will be more than 24% lower in the 2.0 °C Scenario than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility. Further reductions in demand in the 1.5 °C Scenario will result in total power generation costs that are 30% lower than in the 5.0 °C case.

Compared with these results, the generation costs when the CO₂ emission costs are not considered will increase in the 5.0 °C case to 7.4 ct/kWh. In the 2.0 °C Scenario, they still increase until 2030, when they reach 6.5 ct/kWh, and then drop to 6.3 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 6.9 ct/kWh and then drop to 6.1 ct/kWh by 2050. In the 2.0 °C case, the generation costs will be maximum in 2050, and 1.1 ct/kWh lower than in the 5.0 °C, whereas they will be 1.3 ct/kWh in the 1.5 °C Scenario. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will increase to about $360 billion/year in 2050.

8.11.1.4 Non-OECD Asia: Future Investments in the Power Sector

An investment of $4030 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including investment in additional power plants for the production of hydrogen and synthetic fuels and investments in plant replacement at the end of their economic lifetimes. This value is equivalent to approximately $112 billion per year on average, and is $2660 billion more than in the 5.0 °C case ($1370 billion). An investment of around $3950 billion for power generation will be required between 2015 and 2050 in the 1.5 °C Scenario. On average, this is an investment of $110 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will be around 55% of the total cumulative investments, whereas approximately 45% will be invested in renewable power generation and co-generation (Fig. 8.74).

However, in the 2.0 °C (1.5 °C) Scenario, Non-OECD Asia will shift almost 93% (95%) of its entire investment to renewables and co-generation. By 2030, the fossil fuel share of power sector investment will predominantly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $2610 billion in 2050, equivalent to $73 billion per year. Therefore, the total fuel cost savings will be equivalent to 98% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $2770 billion, or $77 billion per year.

8.11.1.5 Non-OECD Asia: Energy Supply for Heating

The final energy demand for heating will increase by 103% in the 5.0 °C scenario, from 10,800 PJ/year in 2015 to 21,900 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 32% by 2050 in the 2.0 °C Scenario, relative to the 5.0 °C case, and by 37% in the 1.5 °C Scenario. Today, renewables supply around 43% of Non-OECD Asia’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 57% of Non-OECD Asia’s total heat demand in 2030 in the 2.0 °C Scenario and 70% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.75 shows the development of different technologies for heating in Non-OECD Asia over time, and Table 8.69 provides the resulting renewable heat supply for all scenarios. Up to 2030, biomass remains the main contributor. In the long term, the growing use of solar, geothermal, and environmental heat will lead to a biomass share of 40% in the 2.0 °C Scenario and 38% in the 1.5 °C Scenario. The heat from renewable hydrogen will further reduce the dependence on fossil fuels in both scenarios. The hydrogen consumption in 2050 will be around 900 PJ/year in the 2.0 °C Scenario and 1300 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of 5-5.7 between 2015 and 2050. Energy for heating will have a final energy share of 34% in 2050 in the 2.0 °C Scenario and 32% in the 1.5 °C Scenario.

Table 8.69

Non-OECD Asia: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	4459	4800	4787	4878	4919
	2.0 °C	4459	4680	4529	4232	3948
	1.5 °C	4459	4772	4890	4054	3549
Solar heating	5.0 °C	4	12	33	70	128
	2.0 °C	4	401	1129	2252	2723
	1.5 °C	4	509	1221	2141	2389
Geothermal heat and heat pumps	5.0 °C	0	0	0	0	0
	2.0 °C	0	141	740	1563	2410
	1.5 °C	0	262	839	1587	2198
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	0	454	862
	1.5 °C	0	0	133	735	1274
Total	5.0 °C	4464	4811	4821	4948	5047
	2.0 °C	4464	5222	6398	8501	9942
	1.5 °C	4464	5542	7083	8516	9411

8.11.1.6 Non-OECD Asia: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 will amount to around $1120 billion in the 2.0 °C Scenario (including investments for the replacement of plants after their economic lifetimes), or approximately $31 billion per year. The largest share of investment in Non-OECD Asia is assumed to be for solar collectors (around $480 billion), followed by heat pumps and geothermal heat use. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies. However, the lower heat demand (compared with the 2.0 °C Scenario) will results in a lower average annual investment of around $28 billion per year (Table 8.70, Fig. 8.76).

Table 8.70

Non-OECD Asia: installed capacities for renewable heat generation in the scenarios

	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	1886	1925	1767	1610	1459
	2.0 °C	1886	1850	1557	1150	821
	1.5 °C	1886	1829	1693	1084	713
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	4	18	51	73
	1.5 °C	0	4	15	44	64
Solar heating	5.0 °C	1	3	10	20	37
	2.0 °C	1	114	321	639	772
	1.5 °C	1	145	349	609	678
Heat pumps	5.0 °C	0	0	0	0	0
	2.0 °C	0	13	58	103	159
	1.5 °C	0	27	70	110	144
Total^a	5.0 °C	1888	1928	1777	1631	1496
	2.0 °C	1888	1981	1954	1944	1825
	1.5 °C	1888	2004	2127	1847	1598

^a Excluding direct electric heating

8.11.1.7 Non-OECD Asia: Transport

The energy demand in the transport sector in Non-OECD Asia is expected to increase in 2015 in the 5.0 °C Scenario from around 6500 PJ/year by 102% to 13,200 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 63% (8320 PJ/year) by 2050 compared to the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in the transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 73% (or 9660 PJ/year) by 2050 compared to the 5.0 °C case (Table 8.71, Fig. 8.77).

Table 8.71

Non-OECD Asia: projection of transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	76	81	81	83	83
	2.0 °C	76	96	116	158	183
	1.5 °C	76	115	124	148	212
Road	5.0 °C	6023	7139	9256	11,061	12,181
	2.0 °C	6023	6694	6489	5251	4245
	1.5 °C	6023	5493	4217	3258	2903
Domestic aviation	5.0 °C	225	353	447	581	621
	2.0 °C	225	240	220	180	143
	1.5 °C	225	230	200	139	108
Domestic navigation	5.0 °C	196	216	227	246	267
	2.0 °C	196	216	227	246	267
	1.5 °C	196	216	227	246	267
Total	5.0 °C	6521	7789	10,010	11,970	13,153
	2.0 °C	6521	7246	7051	5834	4838
	1.5 °C	6521	6053	4769	3791	3489

By 2030, electricity will provide 6% (120 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas in 2050, the share will be 36% (480 TWh/year). In 2050, up to 650 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 350 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 500 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of 1940 PJ/year Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 530 PJ/year in 2050. Due to the lower overall energy demand in transport, biofuel use will be reduced in the 1.5 °C Scenario to a maximum of 1540 PJ/year. The maximum synthetic fuel demand will amount to 280 PJ/year.

8.11.1.8 Non-OECD Asia: Development of CO₂ Emissions

In the 5.0 °C Scenario, Non-OECD Asia’s annual CO₂ emissions will increase by 160%, from 1880 Mt. in 2015 to 4880 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause the annual emissions to fall to 630 Mt. in 2040 in the 2.0 °C Scenario and to 330 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 121 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 42 Gt and 32 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 65% in the 2.0 °C Scenario and by 74% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario, this reduction will be greatest in ‘Power generation’, followed by the ‘Residential and other’ and ‘Industry’ sectors (Fig. 8.78).

8.11.1.9 Non-OECD Asia: Primary Energy Consumption

The levels of primary energy consumption in the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.79. In the 2.0 °C Scenario, the primary energy demand will increase by 13%, from around 38,100 PJ/year in 2015 to 43,200 PJ/year. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 47% by 2050 in the 2.0 °C Scenario (5.0 °C: 81600 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (39,300 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C Scenario and 1.5 °C Scenario aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 40% in 2030 and 93% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 92% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased out by 2045 in both the 2.0 °C Scenario and 1.5 °C Scenario. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 430 EJ, the cumulative coal consumption to about 530 EJ, and the crude oil consumption to 580 EJ. In contrast, in the 2.0 °C Scenario, the cumulative gas demand will amount to 260 EJ, the cumulative coal demand to 120 EJ, and the cumulative oil demand to 270 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 230 EJ for natural gas, 70 EJ for coal, and 190 EJ for oil.

8.11.2 Non-OECD Asia: Power Sector Analysis

Non-OECD Asia is the most heterogeneous region of all IEA world energy regions because it includes not only all the ASEAN countries (ASEAN 2018) of South East Asia, but also central and south Asian nations, as well all 16 Pacific Island states. As for the Caribbean Islands, a power system assessment—especially with regard to possible storage demand—that examines all Pacific Island states together rather than individually, is not sufficient to provide the actual required storage demand. However, with this is in mind, the ratio of solar PV generation to storage requirements does provide some indication. A specific assessment for each of the Pacific Island states is required, but is beyond the scope of this study. Indonesia and the Philippines are selected as sub-regions because they are island states with some interconnection between islands.

8.11.2.1 Non-OECD Asia: Development of Power Plant Capacities

Non-OECD Asia’s renewable power market can be subdivided into the following categories: technologies for small and medium islands (mainly solar PV–battery systems, mini-hydro and small-scale bioenergy systems); and utility-scale solar and onshore wind for all major economies in mainland Asia or on the large islands of the Philippines and Indonesia. Several countries in this region are on the Pacific Ring of Fire and have significant geothermal energy resources. The annual market for geothermal power plants is one of the world’s largest, with a projected 3–4 GW each year for almost two decades between 2025 and 2045 in both scenarios (Table 8.72).

Table 8.72

Non-OECD Asia: average annual change in installed power plant capacity

Non-OECD-Asia power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	2	−6	−7	−4	−1	0
Lignite	−2	−4	−1	−2	0	0
Gas	4	10	19	14	−26	−22
Hydrogen-gas	0	1	0	6	33	24
Oil/diesel	0	−5	−4	−5	−1	0
Nuclear	0	0	0	0	0	0
Biomass	2	1	1	1	1	1
Hydro	3	2	0	0	0	0
Wind (onshore)	4	21	20	24	26	20
Wind (offshore)	3	7	6	7	5	4
PV (roof top)	10	36	40	47	50	37
PV (utility scale)	3	12	13	16	17	12
Geothermal	0	3	4	4	2	1
Solar thermal power plants	1	6	9	8	17	13
Ocean energy	0	0	1	1	3	2
Renewable fuel based co-generation	1	2	1	1	1	1

8.11.2.2 Non-OECD Asia: Utilization of Power-Generation Capacities

Due to the geographic diversity and wide distribution of all sub-regions of the Non-OECD Asia region, it is assumed that there are no interconnection capacities available, and that there will not be any at the end of the modelling period (Table 8.73). In both scenarios, variable power generation will jump from only 1% today to around 25% in all sub-regions, whereas dispatchable renewables will remain stable at around 25%–30% until 2050.

Table 8.73

Non-OECD Asia: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
Power generation structure and interconnection		Variable RE	Dispatch RE	Dispatch Fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch Fossil	Inter-connection
Asia West: Pakistan, Afghanistan, Nepal, Bhutan	2015	1%	35%	63%	0%
	2030	31%	31%	38%	0%	44%	29%	28%	0%
	2050	62%	25%	13%	0%	64%	24%	12%	0%
Sri Lanka	2015	1%	35%	64%	0%
	2030	30%	37%	33%	0%	41%	34%	25%	0%
	2050	58%	27%	15%	0%	59%	26%	14%	0%
Pacific Island State	2015	1%	35%	64%	0%
	2030	29%	34%	37%	0%	39%	30%	30%	0%
	2050	55%	25%	20%	0%	55%	25%	20%	0%
Asia North West: Bangladesh, Myanmar, Thailand	2015	1%	35%	64%	0%
	2030	23%	37%	40%	0%	33%	35%	32%	0%
	2050	48%	31%	21%	0%	50%	30%	20%	0%
Asia Central North: Viet Nam, Laos and Cambodia	2015	1%	35%	64%	0%
	2030	27%	36%	36%	0%	38%	33%	29%	0%
	2050	53%	28%	20%	0%	56%	27%	17%	0%
Asia South West: Malaysia, Brunei	2015	1%	35%	64%	0%
	2030	26%	40%	34%	0%	36%	37%	27%	0%
	2050	52%	29%	19%	0%	57%	28%	15%	0%
Indonesia	2015	1%	35%	64%	0%
	2030	21%	34%	45%	0%	31%	35%	35%	0%
	2050	47%	30%	23%	0%	48%	30%	22%	0%
Philippines	2015	1%	35%	64%	0%
	2030	34%	34%	32%	0%	48%	30%	22%	0%
	2050	63%	23%	13%	0%	65%	22%	13%	0%
Non-OECD Asia	2015	1%	35%	64%
	2030	26%	35%	39%		36%	34%	30%
	2050	52%	28%	19%		55%	28%	17%

Compared with other world regions, the capacity factors for limited dispatchable fossil and nuclear energy will remain relatively high until 2030, as shown in Table 8.74. The time required for variable power generation to replace fossil and nuclear generation will be greater than it is in other regions. In the 1.5 °C Scenario, all coal capacities across the region will be phased out by 2030, except for 4 GW (equivalent to 4–5 power plants), which will be off-line 5 years later.

Table 8.74

Non-OECD Asia: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
Non-OECD Asia			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	55.4%	52%	53%	45%	42%	33%	33%	34%	32%
Limited dispatchable: fossil and nuclear	[%/yr]	71.4%	52%	53%	44%	33%	31%	13%	25%	0%
Limited dispatchable: renewable	[%/yr]	40.5%	61%	61%	59%	56%	58%	53%	45%	49%
Dispatchable: fossil	[%/yr]	50.2%	32%	33%	23%	27%	37%	13%	28%	12%
Dispatchable: renewable	[%/yr]	34.4%	75%	75%	74%	69%	41%	58%	53%	51%
Variable: renewable	[%/yr]	13.1%	19%	19%	36%	35%	26%	31%	30%	29%

8.11.2.3 Non-OECD Asia: Development of Load, Generation, and Residual Load

Because both scenarios were calculated under the assumption that there are no interconnection capacities at the sub-regional level, more dispatch capacity will be deployed. Table 8.75 shows that only Asia North-West and Asia South-West will require some interconnection to avoid curtailment. The development of the maximum load, generation, and the resulting residual load—the load remaining after variable renewable generation. According to the Philippine Department of Energy, the peak demand in the Philippines in 2016 was 13.3 GW (PR-DoE 2016) (9.7 GW in Luzon, 1.9 GW in the Visayas, and 1.7 GW in Mindanao). The calculated load for the Philippines in 2020 was 16.3 GW, which seems realistic. The load will increase to 75.5 GW by 2050 under the 2.0 °C Scenario. The results for all Asian regions show a quadrupling of load by 2050.

Table 8.75

Non-OECD Asia: load, generation, and residual load development—2.0 °C Scenario

Power generation structure		2.0 °C				1.5 °C
		Max demand	Max generation	Max residual load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
Asia West: Pakistan, Afghanistan, Nepal, Bhutan	2020	38.1	22.4	17.4		38.1	22.3	17.5
	2030	65.1	58.2	44.4	0	67.1	64.2	47.9	0
	2050	145.6	194.0	117.5	0	137.5	185.6	112.2	0
Sri Lanka	2020	5.6	2.7	3.2		5.6	2.7	3.2
	2030	9.0	8.6	6.3	0	9.2	10.5	6.5	0
	2050	19.7	31.1	15.2	0	18.2	29.7	14.1	0
Pacific Island State	2020	1.6	1.0	0.6		1.6	1.0	0.6
	2030	2.6	2.3	1.8	0	2.7	2.6	1.9	0
	2050	5.6	8.2	4.2	0	5.5	7.9	4.2	0
Asia North West: Bangladesh, Myanmar, Thailand	2020	57.8	18.9	41.8		57.8	18.8	41.9
	2030	97.4	88.8	67.1	0	99.6	101.2	71.5	0
	2050	218.9	321.0	171.4	0	198.1	306.3	155.8	0
Asia Central North: Viet Nam, Laos and Cambodia	2020	29.4	26.3	3.5		29.4	26.2	3.6
	2030	47.0	44.4	29.8	0	47.9	61.2	32.2	0
	2050	109.6	191.0	83.1	0	93.7	182.6	70.2	19
Asia South West: Malaysia, Brunei	2020	38.2	16.0	25.0		38.2	15.1	25.5
	2030	53.6	54.0	28.1	0	53.9	68.4	34.0	0
	2050	121.0	216.7	89.1	7	99.2	206.9	71.0	37
Indonesia	2020	60.9	34.3	26.6		60.9	33.0	27.9
	2030	106.7	99.8	59.9	0	108.7	114.5	77.4	0
	2050	239.4	363.8	188.3	0	218.6	348.2	173.2	0
Philippines	2020	16.3	13.7	3.9
	2030	33.5	33.0	19.0	0	34.3	42.6	24.1	0
	2050	75.5	133.1	58.8	0	70.3	127.3	55.5	2

The lack of interconnection potential between or even within most sub-regions will lead to some curtailment.

Table 8.76 shows that whereas countries on the Asian mainland will use and increase their capacity for hydro pump storage electricity, batteries will be used for most of the storage requirements of islands and island states. Where available, gas infrastructure must be converted to hydrogen-operated systems.

Table 8.76

Non-OECD Asia: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
Non-OECD Asia		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
Non-OECD Asia		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
Asia West: Pakistan, Afghanistan, Nepal, Bhutan	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	0	434	4	78	82	3356
	2050	36,251	767	716	1483	42,533	37,649	407	774	1181	44,157
Sri Lanka	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	0	72	1	9	10	564
	2050	4755	135	125	260	7380	5471	74	144	218	7330
Pacific Island State	2020	0	0	0	0	0	0	0	0	0	0
	2030	12	0	2	2	0	183	1	14	14	142
	2050	2178	44	43	87	2101	1932	22	42	65	2211
Asia North West: Bangladesh, Myanmar, Thailand	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	0	194	1	27	28	6617
	2050	19,992	1114	824	1938	93,720	29,141	657	1113	1770	92,309
Asia Central North: Viet Nam, Laos and Cambodia	2020	0	0	0	0	0	0	0	0	0	0
	2030	6	0	3	4	0	1031	5	121	126	3346
	2050	26,401	727	708	1435	49,483	40,048	416	919	1335	45,848
Asia South West: Malaysia, Brunei	2020	0	0	0	0	0	0	0	0	0	0
	2030	7	0	2	3	0	1036	5	120	125	4151
	2050	32,422	942	893	1835	59,371	55,862	610	1406	2016	51,750
Indonesia	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	0	176	1	21	22	7391
	2050	11,890	720	530	1250	107,913	17,040	478	717	1195	107,330
Philippines	2020	0	0	0	0	0	0	0	0	0	0
	2030	112	3	22	25	0	3723	6	232	239	1917
	2050	38,084	507	670	1177	23,954	41,017	266	743	1009	24,126
Other Asia	2020	0	0	0	0	0	0	0	0	0	0
	2030	137	4	30	34	0	6848	23	622	646	27,484
	2050	171,973	4955	4510	9465	386,454	228,160	2930	5859	8789	375,061

8.12 India

8.12.1 India: Long-Term Energy Pathways

8.12.1.1 India: Final Energy Demand by Sector

The future development pathways for India’s final energy demand when the assumptions on population growth, GDP growth, and energy intensity are combined are shown in Fig. 8.80 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will increase by 201% from the current 22,200 PJ/year to 66,800 PJ/year by 2050. In the 2.0 °C Scenario, the final energy demand will increase at a much slower rate by 57% compared with current consumption and will reach 34,900 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will reach 31,900 PJ, 44% above the 2015 level. In the 1.5 °C Scenario, the final energy demand in 2050 will be 9% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will increase from 750 TWh/year in 2015 to 3200 TWh/year in 2050 in both alternative scenarios. Compared with the 5.0 °C case (4720 TWh/year in 2050), efficiency measures in the 2.0 °C and 1.5 °C Scenarios will save around 1520 TWh/year by 2050.

Electrification will lead to a significant increase in the electricity demand by 2050. In the 2.0 °C Scenario, the electricity demand for heating will be approximately 1900 TWh/year due to electric heaters and heat pumps, and in the transport sector, the electricity demand will be approximately 3400 TWh/year due to electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 1700 TWh/year. Therefore, the gross power demand will increase from 1400 TWh/year in 2015 to 8400 TWh/year in 2050 in the 2.0 °C Scenario, 31% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increases to a maximum of 7700 TWh/year in 2050.

Efficiency gains in the heating sector could be even larger than in the electricity sector. In the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 9500 PJ/year and 9800 PJ/year, respectively, will be avoided through efficiency gains by 2050 compared with the 5.0 °C Scenario.

8.12.1.2 India: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power from renewable sources. By 2050, 100% of the electricity produced in India will come from renewable energy sources in the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 90% of the total electricity generation. Renewable electricity’s share of the total production will be 66% by 2030 and 89% by 2040. The installed capacity of renewables will reach about 1060 GW by 2030 and 3360 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario is assumed to be 77%. In the 1.5 °C Scenario, the generation capacity from renewable energy will be approximately 3040 GW in 2050.

Table 8.77 shows the development of different renewable technologies in India over time. Figure 8.81 provides an overview of the overall power-generation structure in India. From 2020 onwards, the continuing growth of wind and PV up to 1270 GW and 1570 GW, respectively, is complemented by up to 210 GW solar thermal generation, as well as limited biomass, geothermal, and ocean energy, in the 2.0 °C Scenario. Both the 2.0 °C Scenario and 1.5 °C Scenario will lead to a high proportion of variable power generation (PV, wind, and ocean) of 48% and 60%, respectively, by 2030, and 75% and 72%, respectively, by 2050.

Table 8.77

India: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	46	68	81	97	117
	2.0 °C	46	68	72	80	87
	1.5 °C	46	68	72	80	87
Biomass	5.0 °C	8	13	16	20	25
	2.0 °C	8	23	31	60	93
	1.5 °C	8	23	31	60	93
Wind	5.0 °C	25	82	119	185	246
	2.0 °C	25	200	421	938	1273
	1.5 °C	25	275	543	1002	1110
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	3	8	42	68
	1.5 °C	0	3	8	42	68
PV	5.0 °C	5	115	198	345	545
	2.0 °C	5	230	469	1090	1572
	1.5 °C	5	365	648	1185	1412
CSP	5.0 °C	0	0	1	1	2
	2.0 °C	0	8	48	138	209
	1.5 °C	0	8	48	138	209
Ocean	5.0 °C	0	0	0	0	0
	2.0 °C	0	1	11	33	59
	1.5 °C	0	1	11	33	59
Total	5.0 °C	84	279	415	648	936
	2.0 °C	84	532	1061	2381	3360
	1.5 °C	84	742	1361	2540	3037

8.12.1.3 India: Future Costs of Electricity Generation

Figure 8.82 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated electricity generation costs in 2015 (referring to full costs) were around 5.4 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2040, when they reach 11 ct/kWh, and then drop to 10.7 ct/kWh by 2050. The generation costs will increase in the 2.0 °C Scenario until 2030, when they reach 8.4 ct/kWh, and then drop to 5.7 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 7.8 ct/kWh, and then drop to 5.8 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs in 2050 will be 5 ct/kWh lower than in the 5.0 °C case. In the 1.5 °C Scenario, the generation costs in 2050 will be 4.9 ct/kWh lower than in the 5.0 °C case. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, the growth in demand and increasing fossil fuel prices will cause the total electricity supply costs to rise from today’s $75 billion/year to more than $690 billion/year in 2050. In the 2.0 °C case, the total supply costs will be $500 billion/year and in the 1.5 °C Scenario, they will be $470 billion/year. The long-term costs for electricity supply will be more than 27% lower in the 2.0 °C Scenario than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility. Further demand reductions in the 1.5 °C Scenario will result in total power generation costs that are 32% lower than in the 5.0 °C case.

Compared with these results, the generation costs, when the CO₂ emission costs are not considered, will increase in the 5.0 °C case to only 6.9 ct/kWh. In both alternative scenarios, they will still increase until 2030, when they reach 6.7 ct/kWh, and then drop to around 5.8 ct/kWh by 2050. The maximum difference in generation costs will be around 1 ct/kWh in 2050. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will rise to about $430 billion/year in 2050.

8.12.1.4 India: Future Investments in the Power Sector

An investment of around $5640 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including additional power plants for the production of hydrogen and synthetic fuels and investments in the replacement of plants after the end of their economic lifetimes. This value is equivalent to approximately $157 billion per year on average, and is $3310 billion more than in the 5.0 °C case ($2330 billion). An investment of around $5560 billion for power generation will be required between 2015 and 2050 in the 1.5 °C Scenario. On average, this will be an investment of $154 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will be around 48% of the total cumulative investments, whereas approximately 52% will be invested in renewable power generation and co-generation (Fig. 8.83).

However, in the 2.0 °C (1.5 °C) Scenario, India will shift almost 94% (95%) of its entire investment to renewables and co-generation. By 2030, the fossil fuel share of the power sector investment will predominantly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $3110 billion in 2050, equivalent to $86 billion per year. Therefore, the total fuel cost savings will be equivalent to 90% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $3330 billion, or $93 billion per year.

8.12.1.5 India: Energy Supply for Heating

The final energy demand for heating will increase in the 5.0 °C Scenario by 133%, from 11,900 PJ/year in 2015 to 27,800 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 34% in 2050 in the 2.0 °C Scenario, relative to the 5.0 °C case, and by 35% in the 1.5 °C Scenario. Today, renewables supply around 47% of India’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 53% of India’s total heat demand in 2030 in the 2.0 °C Scenario and 68% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.84 shows the development of different technologies for heating in India over time, and Table 8.78 provides the resulting renewable heat supply for all scenarios. Up to 2030, biomass will remain the main contributor. In the long term, the increasing use of solar, geothermal, and environmental heat will lead to a biomass share of 38% in the 2.0 °C Scenario and 36% in the 1.5 °C Scenario.

Table 8.78

India: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	5544	5633	5666	5595	5341
	2.0 °C	5544	5726	5600	4854	4366
	1.5 °C	5544	5600	5444	4758	4078
Solar heating	5.0 °C	28	77	115	200	310
	2.0 °C	28	589	1537	2964	3693
	1.5 °C	28	887	2271	3107	3626
Geothermal heat and heat pumps	5.0 °C	0	1	1	1	2
	2.0 °C	0	164	647	1627	2136
	1.5 °C	0	189	725	1497	2103
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	2	299	1409
	1.5 °C	0	0	2	437	1613
Total	5.0 °C	5572	5711	5781	5796	5653
	2.0 °C	5572	6478	7787	9743	11,603
	1.5 °C	5572	6675	8442	9800	11,420

Heat from renewable hydrogen will further reduce the dependence on fossil fuels under both scenarios. Hydrogen consumption in 2050 will be around 1400 PJ/year in the 2.0 °C Scenario and 1600 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of about 21 between 2015 and 2050, and the electricity for heating will have a final energy share of 36% in 2050 in both alternative scenarios.

8.12.1.6 India: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 amount to around $930 billion in the 2.0 °C Scenario (including investments for replacement after the economic lifetimes of the plants), or approximately $26 billion per year. The largest share of investment in India is assumed to be for solar collectors (around $490 billion), followed by heat pumps and biomass technologies. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies and results in a higher average annual investment of around $29 billion per year (Table 8.79, Fig. 8.85).

Table 8.79

India: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	2049	1923	1836	1633	1432
	2.0 °C	2049	1954	1798	1311	856
	1.5 °C	2049	1916	1756	1276	785
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	2	9	32	38
	1.5 °C	0	5	12	28	37
Solar heating	5.0 °C	6	17	25	43	67
	2.0 °C	6	126	327	619	777
	1.5 °C	6	191	486	653	763
Heat pumps	5.0 °C	0	0	0	0	0
	2.0 °C	0	12	42	90	131
	1.5 °C	0	11	46	82	129
Total^a	5.0 °C	2055	1940	1861	1676	1499
	2.0 °C	2055	2094	2177	2052	1802
	1.5 °C	2055	2122	2300	2039	1715

^a Excluding direct electric heating

8.12.1.7 India: Transport

The energy demand in the transport sector in India is expected to increase in the 5.0 °C Scenario by 377%, from around 3600 PJ/year in 2015 to 17,200 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 66% (11,280 PJ/year) by 2050 compared to the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in the transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 81% (or 13,930 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.80, Fig. 8.86).

Table 8.80

India: projection of transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	180	238	278	353	423
	2.0 °C	180	270	325	421	526
	1.5 °C	180	219	234	332	446
Road	5.0 °C	3294	5861	7880	12,152	16,455
	2.0 °C	3294	5017	5562	5301	5285
	1.5 °C	3294	4253	3125	2977	2730
Domestic aviation	5.0 °C	84	131	166	216	231
	2.0 °C	84	89	81	66	52
	1.5 °C	84	85	74	52	40
Domestic navigation	5.0 °C	29	34	36	40	52
	2.0 °C	29	34	36	40	52
	1.5 °C	29	34	36	40	52
Total	5.0 °C	3587	6263	8360	12,762	17,161
	2.0 °C	3587	5410	6006	5828	5914
	1.5 °C	3587	4590	3470	3401	3268

By 2030, electricity will provide 10% (160 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas in 2050, the share will be 58% (950 TWh/year). In 2050, up to 860 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 560 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 590 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of around 1000 PJ/year. Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 610 PJ/year in 2050. Due to the lower overall energy demand in transport, biofuel use will be reduced in the 1.5 °C Scenario to a maximum of 510 PJ/year. The maximum synthetic fuel demand will amount to 310 PJ/year.

8.12.1.8 India: Development of CO₂ Emissions

In the 5.0 °C Scenario, India’s annual CO₂ emissions will increase by 236%, from 2060 Mt. in 2015 to 6950 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause the annual emissions to fall to 930 Mt. in 2040 in the 2.0 °C Scenario and to 200 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 169 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 55 Gt and 38 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 67% in the 2.0 °C Scenario and by 78% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in the annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario, the reduction will be greatest in the ‘Residential and other’ sector, followed by the ‘Power generation’ and ‘Industry’ sectors (Fig. 8.87).

8.12.1.9 India: Primary Energy Consumption

The levels of primary energy consumption in the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.88. In the 2.0 °C Scenario, the primary energy demand will increase by 43%, from around 35,600 PJ/year in 2015 to 50,900 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 51% by 2050 in the 2.0 °C Scenario (5.0 °C: 104,800 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (47,100 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 40% in 2030 and 94% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 94% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased out by 2050 in both the 2.0 °C and 1.5 °C Scenarios. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 160 EJ, the cumulative coal consumption to about 1180 EJ, and the crude oil consumption to 570 EJ. In contrast, in the 2.0 °C Scenario, the cumulative gas demand will amount to 120 EJ, the cumulative coal demand to 360 EJ, and the cumulative oil demand to 220 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 130 EJ for natural gas, 220 EJ for coal, and 150 EJ for oil.

8.12.2 India: Power Sector Analysis

The electricity market in India is in dynamic development. The government of India is making great efforts to increase the reliability of the power supply and at the same time, it is developing universal access to electric power. In 2017, about 300 million Indians (RF 2018) had no power or inadequate power. In 2017, the Indian Government launched The Third National Electricity Plan, which covers two 5-year periods: 2017–2022 and 2022–2027. According to the International Energy Agency (IEA) Policies and Measures Database (IEA P + M DB 2018):

[…] “the plan covers short- and long-term demand forecasts in different regions and recommend areas for transmission and generation capacity additions … However, as India sets to meet its first nationally-determined contribution (NDC) under the Paris Agreement … Highlights of the plan include, that during the period 2017–22, no additional capacity of coal will be added – except for the coal power plants under construction […]”.

In terms of renewable power generation, India aims to have a total capacity of 275 GW for solar and wind and 72 GW for hydro, with no further increase in the coal power plant capacity until at least 2027.

8.12.2.1 India: Development of Power Plant Capacities

The Third National Electricity Plan for India is an important foundation for strengthening India’s renewable power market in order to achieve the levels envisaged in both alternative scenarios. Whereas the hydropower target is consistent with the 2.0 °C and 1.5 °C targets, the solar and wind capacity of 275 GW must be reached between 2020 and 2025 for both scenarios. The annual installation rates for solar PV installations must increase to around 50 GW—the market size in China in 2017—and remain at that level until 2040 to implement either the 2.0 °C or 1.5 °C Scenario. The installation rates for onshore wind must be equally high. In 2017, 4.15 GW of new wind turbines were installed, and significant growth is required. Offshore wind and concentrated solar power plants have significant potential for selected regions of India. Both technologies are vital to achieving the 2.0 °C or 1.5 °C targets (Table 8.81).

Table 8.81

India: average annual change in installed power plant capacity

India power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	7	−7	−6	−7	−15	−6
Lignite	0	−1	−1	−2	−2	−1
Gas	9	13	7	7	−14	17
Hydrogen-Gas	0	0	1	1	32	32
Oil/Diesel	0	−1	−1	−1	0	0
Nuclear	1	0	0	0	−1	−1
Biomass	2	2	2	2	4	4
Hydro	3	2	1	1	1	1
Wind (onshore)	20	55	54	59	44	21
Wind (offshore)	2	6	7	7	5	4
PV (roof top)	21	55	49	53	51	30
PV (utility scale)	7	18	16	18	17	10
Geothermal	0	1	3	3	4	4
Solar thermal power plants	1	6	11	11	10	10
Ocean energy	0	1	3	3	3	3
Renewable fuel based co-generation	0	1	2	2	3	3

8.12.2.2 India: Utilization of Power-Generation Capacities

The division of India into five sub-regions is intended to reflect the main grid zones and it is assumed that interconnection will continue to increase to 15% in 2030 and 20% in 2050. Both scenarios aim for an even distribution of variable power plant capacities across all Indian sub-regions. By 2030, the variable power generation will reach 40% in most regions, whereas dispatchable renewables will supply about one quarter of the demand by 2030 (Table 8.82).

Table 8.82

India: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
Power generation structure and interconnection		Variable RE	Dispatch RE	Dispatch Fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch fossil	Inter-connection
India-Northern Region	2015	4%	32%	64%	10%
	2030	41%	28%	31%	15%	56%	24%	20%	15%
	2050	60%	38%	2%	20%	48%	35%	17%	20%
India-North-Eastern Region	2015	4%	32%	64%	10%
	2030	44%	26%	30%	15%	58%	21%	21%	15%
	2050	95%	5%	0%	20%	92%	5%	3%	20%
India-Eastern Region	2015	4%	32%	64%	10%
	2030	51%	26%	23%	15%	68%	22%	10%	15%
	2050	73%	26%	1%	20%	69%	29%	2%	20%
India-Western Region	2015	4%	32%	64%	10%
	2030	44%	26%	30%	15%	57%	21%	22%	15%
	2050	70%	29%	1%	20%	49%	24%	27%	20%
India-Southern Region	2015	4%	32%	64%	10%
	2030	48%	23%	29%	15%	60%	18%	22%	15%
	2050	78%	21%	1%	20%	62%	19%	19%	20%
India	2015	4%	32%	64%
	2030	45%	26%	29%		60%	21%	19%
	2050	72%	27%	1%		58%	26%	16%

India’s average capacity factors for the entire power plant fleet remain at around 35% over the entire modelling period, as the calculation results in Table 8.83 show. Contributions from limited dispatchable fossil and nuclear power plants will remain high until 2030 and indicate that a significant replacement of coal for electricity must occur after 2030 in the 2.0 °C Scenario. In the 1.5 °C Scenario, coal will be phased-out just after 2035.

Table 8.83

India: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
India			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	60.8%	53%	57%	35%	26%	33%	30%	37%	34%
Limited dispatchable: fossil and nuclear	[%/yr]	67.7%	57%	61%	48%	38%	37%	27%	37%	12%
Limited dispatchable: renewable	[%/yr]	17.1%	24%	26%	38%	34%	58%	39%	44%	42%
Dispatchable: fossil	[%/yr]	44.7%	12%	19%	11%	12%	30%	29%	24%	29%
Dispatchable: renewable	[%/yr]	39.8%	60%	68%	57%	45%	40%	52%	65%	57%
Variable: renewable	[%/yr]	9.0%	8%	8%	19%	20%	27%	25%	29%	28%

8.12.2.3 India: Development of Load, Generation, and Residual Load

Table 8.84 shows that India’s load is predicted to quadruple in all five sub-regions between 2020 and 2050. Under the 2.0 °C Scenario, additional interconnection will increase—beyond the assumed 20% target—but may only be required for the western and southern sub-regions of India. However, for the 1.5 °C Scenario, interconnections must increase in four of the five regions. In the northern region, the calculated generation increases faster than the demand. This region has significant potential for concentrated solar power plants and could supply neighbouring regions.

Table 8.84

India: load, generation, and residual load development

Power generation structure		2.0 °C				1.5 °C
		Max demand	Max generation	Max residual load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
India-Northern Region	2020	87.8	85.6	11.1		87.8	78.2	19.9
	2030	150.1	147.3	41.2	0	149.6	240.4	57.2	34
	2050	372.2	397.2	265.7	0	366.8	381.7	211.1	0
India-North-Eastern Region	2020	10.7	10.4	0.6		10.7	10.4	0.6
	2030	18.3	21.7	2.7	1	18.3	30.4	2.7	9
	2050	45.4	69.1	32.7	0	44.8	223.9	9.3	170
India-Eastern Region	2020	64.5	47.5	25.3		64.5	38.5	34.2
	2030	110.8	118.0	43.1	0	110.4	198.8	53.1	35
	2050	276.9	364.6	183.6	0	273.0	409.7	174.8	0
India-Western Region	2020	64.6	62.9	3.5		64.6	62.9	3.5
	2030	111.0	173.5	19.4	43	110.6	196.4	20.0	66
	2050	277.4	542.0	207.2	57	273.4	401.3	86.4	42
India-Southern Region	2020	60.6	59.1	3.5		60.6	59.1	3.2
	2030	103.0	163.4	5.2	55	102.6	195.0	15.2	77
	2050	252.8	507.5	164.8	90	249.1	448.0	76.7	122

Table 8.85 shows the storage and dispatch requirements under the 2.0 °C and 1.5 °C Scenarios. All the regions remain within the maximum curtailment target of 10%. Table 8.71 provides an overview of the calculated storage and dispatch power requirements by sub-region. Charging capacities are moderate compared with other world regions. Compared to all other world regions, hydrogen dispatch utilization is very low due to a relatively moderate increase in the gas and hydrogen capacities in India.

Table 8.85

India: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
India		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
India		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
India-Northern Region	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	507	24,533	57	3063	3121	160
	2050	1244	42	51	93	9873	734	38	51	89	8647
India-North-Eastern Region	2020	1	0	1	1.1	0	1	0	1	1.1	0
	2030	307	1	65	66	0	3862	8	471	478	0
	2050	4923	126	332	457	1025	258,992	219	1896	2115	11
India-Eastern Region	2020	0	0	0	0	0	0	0	0	0	0
	2030	1657	10	427	437	476	54,903	95	4933	5028	156
	2050	27,180	729	2154	2884	6813	46,793	1519	3163	4682	5715
India-Western Region	2020	0	0	0	0	0	0	0	0	0	0
	2030	29,610	51	2978	3028	448	41,348	84	3928	4012	310
	2050	174,263	1709	5618	7327	5037	28,209	1228	2263	3491	2020
India-Southern Region	2020	0	0	0	0	0	0	0	0	0	0
	2030	27,824	42	2496	2537	328	57,916	88	4759	4847	144
	2050	165,200	1643	5274	6917	5365	103,156	1891	4931	6822	2066
India	2020	1	0	1	1	0	1	0	1	1	0
	2030	59,399	104	5966	6069	1759	182,561	333	17,154	17,487	769
	2050	372,809	4248	13,430	17,678	28,113	437,884	4895	12,304	17,199	18,459

8.13 China

8.13.1 China: Long-Term Energy Pathways

8.13.1.1 China: Final Energy Demand by Sector

The future development pathways for China’s final energy demand when the assumptions on population growth, GDP growth and energy intensity are combined are shown in Fig. 8.89 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will increase by 56% from the current 73,600 PJ/year to 114,600 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will decreases by 26% compared with current consumption and will reach 54,400 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will reach 49,200 PJ, 33% below the 2015 demand. In the 1.5 °C Scenario, the final energy demand in 2050 will be 10% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will increase from 3470 TWh/year in 2015 to around 5230 TWh/year in both alternative scenarios by 2050. Compared with the 5.0 °C case (9480 TWh/year in 2050), the efficiency measures in the 2.0 °C and 1.5 °C Scenarios save around 4250 TWh/year by 2050.

Electrification will lead to a significant increase in the electricity demand by 2050. In the 2.0 °C Scenario, the electricity demand for heating will be approximately 2800 TWh/year due to electric heaters and heat pumps and in the transport sector, the electricity demand will be approximately 4200 TWh/year due to electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 3900 TWh/year. Therefore, the gross power demand will rise from 5900 TWh/year in 2015 to 13,800 TWh/year in 2050 in the 2.0 °C Scenario, 11% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 13,300 TWh/year in 2050.

The efficiency gains in the heating sector could be even larger than in the electricity sector. In the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 24,400 PJ/year and 27,600 PJ/year, respectively, will be avoided through efficiency gains by 2050 compared to the 5.0 °C Scenario.

8.13.1.2 China: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power from renewable sources. By 2050, 100% of the electricity produced in China will come from renewable energy sources in the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 77% of the total electricity generation. Renewable electricity’s share of the total production will be 54% by 2030 and 84% by 2040. The installed capacity of renewables will reach about 2170 GW by 2030 and 5420 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario is assumed to be 63%. In the 1.5 °C Scenario, the generation capacity from renewable energy will be approximately 5310 GW in 2050.

Table 8.86 shows the development of different renewable technologies in China over time. Figure 8.90 provides an overview of the overall power-generation structure in China. From 2020 onwards, the continuing growth of wind and PV, up to 1670 GW and 2220 GW, respectively, will be complemented by up to 680 GW solar thermal generation, as well as limited biomass, geothermal, and ocean energy, in the 2.0 °C Scenario. Both the 2.0 °C and 1.5 °C Scenarios will lead to a high proportion of variable power generation (PV, wind, and ocean) of 28% and 34%, respectively, by 2030, and 51% and 52%, respectively, by 2050.

Table 8.86

China: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	320	395	424	477	525
	2.0 °C	320	383	396	420	450
	1.5 °C	320	383	396	420	450
Biomass	5.0 °C	11	24	29	39	48
	2.0 °C	11	57	101	158	195
	1.5 °C	11	72	106	160	195
Wind	5.0 °C	132	343	408	536	667
	2.0 °C	132	428	678	1299	1674
	1.5 °C	132	508	877	1460	1652
Geothermal	5.0 °C	0	0	0	1	3
	2.0 °C	0	4	19	77	134
	1.5 °C	0	7	29	77	119
PV	5.0 °C	43	265	330	430	565
	2.0 °C	43	504	889	1614	2218
	1.5 °C	43	604	1036	1781	2215
CSP	5.0 °C	0	3	5	7	11
	2.0 °C	0	11	84	413	677
	1.5 °C	0	16	103	391	614
Ocean	5.0 °C	0	0	0	1	1
	2.0 °C	0	1	7	33	74
	1.5 °C	0	1	7	33	62
Total	5.0 °C	505	1029	1196	1490	1819
	2.0 °C	505	1390	2175	4015	5421
	1.5 °C	505	1592	2555	4322	5307

8.13.1.3 China: Future Costs of Electricity Generation

Figure 8.91 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated electricity generation costs in 2015 (referring to full costs) were around 4.7 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2030, when they reach 9.2 ct/kWh, and then drop to 8.8 ct/kWh by 2050. The generation costs will increase in the alternative scenarios until 2030, when they reach around 8 ct/kWh, and will then drop to 6.5 ct/kWh by 2050, 2.3 ct/kWh lower than in the 5.0 °C Scenario. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 °C case, the growth in demand and increasing fossil fuel prices will cause total electricity supply costs to rise from today’s $310 billion/year to more than $1230 billion/year in 2050. In the 2.0 °C case, the total supply costs will be $1030 billion/year and $1010 billion/year in the 1.5 °C Scenario. Therefore, the long-term costs for electricity supply will be more than 16% lower in the alternative scenarios than in the 5.0 °C case.

Compared with these results, the generation costs when the CO₂ emission costs are not considered will increase in the 5.0 °C case to 5.7 ct/kWh in 2030 and stabilize at 5.5 ct/kWh in 2050. In the 2.0 °C Scenario, they increase continuously until 2050, when they reach 6.6 ct/kWh. In the 1.5 °C Scenario, they will increase to 7 ct/kWh and then drop to 6.6 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs will be a maximum of 1 ct/kWh higher than in the 5.0 °C case, and this will occur in 2050. In the 1.5 °C Scenario, compared to the 5.0 °C Scenario, the maximum difference in generation costs will be 1.6 ct/kWh in 2040. The generation costs in 2050 will be 1.1 ct/kWh higher than in the 5.0 °C case. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will rise to about $810 billion/year in 2050.

8.13.1.4 China: Future Investments in the Power Sector

An investment of around $9740 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including additional power plants for the production of hydrogen and synthetic fuels and investments for plant replacement at the end of their economic lifetimes. This value will be equivalent to approximately $271 billion per year on average and will be $5680 billion more than in the 5.0 °C case ($4060 billion). An investment of around $9840 billion for power generation will be required between 2015 and 2050 in the 1.5 °C Scenario. On average, this will be an investment of $273 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will be around 29% of the total cumulative investments, whereas approximately 71% will be invested in renewable power generation and co-generation (Fig. 8.92).

However, in the 2.0 °C (1.5 °C) Scenario, China will shift almost 97% (98%) of its entire investment to renewables and co-generation. By 2030, the fossil fuel share of the power sector investment will predominantly focus on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in both alternative scenarios will reach a total of more than $6200 billion in 2050, equivalent to $173 billion per year. Therefore, the total fuel cost savings will be equivalent to 110% of the total additional investments compared to the 5.0 °C Scenario.

8.13.1.5 China: Energy Supply for Heating

The final energy demand for heating will increase in the 5.0 °C Scenario by 38% from 42,300 PJ/year in 2015 to 58,200 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 42% in 2050 in the 2.0 °C Scenario, relative to the 5.0 °C case, and by 47% in the 1.5 °C Scenario. Today, renewables supply around 11% of China’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 32% of China’s total heat demand in 2030 in the 2.0 °C Scenario and 46% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.93 shows the development of different technologies for heating in China over time, and Table 8.87 provides the resulting renewable heat supply for all scenarios. Up to 2030, biomass will remain the main contributor. In the long term, the growing use of solar, geothermal, and environmental heat will lead to a biomass share of 24% in both alternative scenarios.

Table 8.87

China: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	2776	2095	2079	2291	2877
	2.0 °C	2776	4609	5603	6254	5967
	1.5 °C	2776	5378	6263	6055	5385
Solar heating	5.0 °C	892	1297	1515	1962	2535
	2.0 °C	892	2066	2906	5454	5417
	1.5 °C	892	2364	3242	4381	4360
Geothermal heat and heat pumps	5.0 °C	306	452	526	743	1026
	2.0 °C	306	1304	2720	6690	9225
	1.5 °C	306	1269	2884	5706	7943
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	0	7	1020	4118
	1.5 °C	0	0	7	1890	4549
Total	5.0 °C	3974	3844	4120	4996	6438
	2.0 °C	3974	7978	11,237	19,417	24,727
	1.5 °C	3974	9011	12,396	18,031	22,237

Heat from renewable hydrogen will further reduce the dependence on fossil fuels in both scenarios. Hydrogen consumption in 2050 will be around 4100 PJ/year in the 2.0 °C Scenario and to 4500 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increase by a factor of 3.7–4 between 2015 and 2050 and electricity for heating will have a final energy share of 27% in 2050 in both the 2.0 °C Scenario and 1.5 °C Scenario.

8.13.1.6 China: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 will amount to around $2780 billion in the 2.0 °C Scenario (including investments for the replacement of plants after their economic lifetimes), or approximately $77 billion per year. The largest share of investment in China is assumed to be for heat pumps (around $1200 billion), followed by solar collectors and geothermal heat use. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies. However, the lower heat demand (compared with the 2.0 °C Scenario) will result in a lower average annual investment of around $67 billion per year (Table 8.88, Fig. 8.94).

Table 8.88

China: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	1194	764	648	519	468
	2.0 °C	1194	1284	1214	921	578
	1.5 °C	1194	1267	1280	808	481
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	20	46	187	272
	1.5 °C	0	20	42	139	161
Solar heating	5.0 °C	281	409	478	618	799
	2.0 °C	281	592	843	1546	1539
	1.5 °C	281	688	956	1252	1275
Heat pumps	5.0 °C	52	76	89	126	174
	2.0 °C	52	151	251	449	565
	1.5 °C	52	136	213	349	446
Total^a	5.0 °C	1527	1250	1214	1263	1441
	2.0 °C	1527	2048	2355	3103	2954
	1.5 °C	1527	2111	2491	2549	2361

^a Excluding direct electric heating

8.13.1.7 China: Transport

The energy demand in the transport sector in China is expected to increase in the 5.0 °C Scenario by 107% from around 12,600 PJ/year in 2015 to 26,100 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 68% (17,840 PJ/year) by 2050 compared with the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 76% (or 19,900 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.89, Fig. 8.95).

Table 8.89

China: projection of transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	539	567	593	644	672
	2.0 °C	539	589	637	687	762
	1.5 °C	539	580	597	622	662
Road	5.0 °C	10,421	15,629	17,651	19,664	22,073
	2.0 °C	10,421	11,509	9395	7143	5894
	1.5 °C	10,421	9607	7372	4576	4020
Domestic aviation	5.0 °C	754	1234	1590	2070	2213
	2.0 °C	754	814	742	592	470
	1.5 °C	754	777	653	463	366
Domestic navigation	5.0 °C	877	984	1035	1113	1157
	2.0 °C	877	984	1035	1113	1157
	1.5 °C	877	984	1035	1113	1157
Total	5.0 °C	12,591	18,413	20,870	23,490	26,115
	2.0 °C	12,591	13,895	11,809	9535	8284
	1.5 °C	12,591	11,948	9657	6773	6206

By 2030, electricity will provide 21% (680 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas in 2050, the share will be 51% (1170 TWh/year). In 2050, up to 1600 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand is 860 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 1100 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario to a maximum of 1900 PJ/year. Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 560 PJ/year in 2050. Due to the lower overall energy demand in transport, biofuel use will be reduced in the 1.5 °C Scenario to a maximum of around 1400 PJ/year. The maximum synthetic fuel demand will amount to 720 PJ/year.

8.13.1.8 China: Development of CO₂ Emissions

In the 5.0 °C Scenario, China’s annual CO₂ emissions will increase by 25%, from 9060 Mt. in 2015 to 11,320 Mt. in 2050. The stringent mitigation measures in both alternative scenarios will cause annual emissions to fall to 1990 Mt. in 2040 in the 2.0 °C Scenario and to 760 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 392 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 174 Gt and 132 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 56% in the 2.0 °C Scenario and by 66% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in annual emissions will occur in both alternative scenarios. In the 2.0 °C Scenario the reduction will be greatest in the ‘Residential and other’ sector, followed by ‘Power generation’ and ‘Transport’ sectors (Fig. 8.96).

8.13.1.9 China: Primary Energy Consumption

The levels of primary energy consumption in the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.97. In the 2.0 °C Scenario, the primary energy demand will decrease by 30%, from around 125,000 PJ/year in 2015 to 87,800 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 54% by 2050 in the 2.0 °C Scenario (5.0 °C: 192,300 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (80,700 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C and 1.5 °C Scenarios aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 28% in 2030 and 92% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 91% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out by 2050 in the 2.0 °C Scenario and by 2045 in the 1.5 °C Scenario. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 570 EJ, the cumulative coal consumption to about 3000 EJ, and the crude oil consumption to 1080 EJ. In contrast, in the 2.0 °C Scenario, the cumulative gas demand will amount to 360 EJ, the cumulative coal demand to 1360 EJ, and the cumulative oil demand to 430 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 440 EJ for natural gas, 930 EJ for coal, and 340 EJ for oil.

8.13.2 China: Power Sector Analysis

China has by far the largest power sector of all world regions—about one quarter of the world’s total electricity generation. China’s National Energy Administration (NEA) released the 13th Energy Five-Year Plan (FYP) in January 2016 (IEA RED 2016). The FYP that is in force from 2016 to 2020 introduces framework legislation that defines energy development for the next 5 years in China. In parallel to the main Energy FYP, there are 14 additional supporting FYPs, such as the Renewable Energy 13th FYP, the Wind FYP, and the Electricity FYP, which were all released at about the same time (GWEC-NL 2018). According to the Renewable Energy 13th FYP, by 2020, the total RE electricity installations will reach 680 GW, with electricity production of 1900 TWh/year This will account for 27% of electricity production. The wind power target is set to reach 210 GW by 2020, with electricity production of 420 TWh, supplying 6% of China’s total electricity demand. The target for offshore wind is 5 GW by 2020 (GWEC-NL 2018). For other renewable power-generation technologies, the 2020 targets are 150 GW for solar PV, 10 GW for concentrated solar power (CSP), 15 GW for bioenergy, and 380 GW for hydropower, including 40 GW hydro pump storage (IEA-RED 2016). The renewable targets are consistent, to large extent, with both the 2.0 °C and 1.5 °C Scenarios. The onshore wind and solar PV capacities in both scenarios will increase to 50 GW and are within the current market size range. The targets for the 2.0 °C and 1.5 °C Scenarios for CSP, bioenergy, and offshore wind are slightly higher than current market volumes. However, the first decade of the 2.0 °C and 1.5 °C Scenarios will reflect the existing trends in China’s power sector.

8.13.2.1 China: Development of Power Plant Capacities

China’s solar PV and wind power markets are the largest in the world and represent about half the global annual market for solar PV (in 2017) and a third of the market for onshore wind. The continued growth of the annual renewable power market—for all technologies—for the Chinese market will continue to have a significant impact on other world regions. To implement the project’s 2.0 °C Scenario, the current solar PV market in China must remain at the 2017 level, and to achieve the 1.5 °C Scenario, it must double. The onshore wind market must increase by 50% compared with 2015 for the 2.0 °C Scenario and must triple to meet the 1.5 °C trajectory. All these annual market volumes must be maintained until 2035, before a moderate reduction in the annual market sizes can occur (Table 8.90).

Table 8.90

China: average annual change in installed power plant capacity

China power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	5	−51	−55	−81	−41	−5
Lignite	0	0	0	0	0	0
Gas	4	28	6	30	−16	−17
Hydrogen-Gas	0	0	1	3	24	38
Oil/Diesel	0	−1	0	−1	0	0
Nuclear	3	0	−2	0	−3	−4
Biomass	6	10	9	8	5	5
Hydro	8	5	3	3	3	3
Wind (onshore)	31	65	46	64	36	29
Wind (offshore)	2	12	20	22	11	9
PV (roof top)	41	77	69	76	62	50
PV (utility scale)	14	26	23	25	21	17
Geothermal	1	4	5	6	8	6
Solar thermal power plants	1	13	34	29	40	30
Ocean energy	0	1	2	2	5	4
Renewable fuel based co-generation	4	9	10	9	8	8

8.13.2.2 China: Utilization of Power Generation Capacities

Across all regions, an interconnection capacity of 10% is assumed for the base year calculation. The interconnection capacity will increase to 20% by 2030, with no further increase thereafter. For the entire modelling period, it is assumed that Taiwan is not connected to any other region. Under the 2.0 °C Scenario, variable renewables will attain a share of around 30% in all sub-regions, whereas the 1.5 °C Scenario will lead to shares of over 40% in five of the seven sub-regions (Table 8.91).

Table 8.91

China: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
China		Variable RE	Dispatch RE	Dispatch Fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch fossil	Inter-connection
China-North	2015	7%	35%	58%	10%
	2030	32%	21%	47%	20%	43%	29%	28%	20%
	2050	53%	43%	4%	20%	53%	37%	9%	20%
China-Northwest	2015	7%	35%	58%	10%
	2030	29%	22%	49%	20%	40%	31%	29%	20%
	2050	49%	47%	3%	20%	54%	44%	2%	20%
China-Northeast	2015	6%	35%	60%	10%
	2030	34%	24%	43%	20%	45%	31%	24%	20%
	2050	54%	43%	4%	20%	54%	45%	2%	20%
China-Tibet	2015	7%	35%	58%	10%
	2030	37%	34%	29%	20%	49%	37%	14%	20%
	2050	43%	49%	7%	20%	42%	53%	5%	20%
China-Central	2015	6%	35%	60%	10%
	2030	28%	26%	47%	20%	36%	32%	32%	20%
	2050	41%	52%	7%	20%	44%	48%	9%	20%
China-East	2015	6%	35%	60%	10%
	2030	30%	25%	45%	20%	36%	29%	35%	20%
	2050	48%	47%	5%	20%	48%	38%	14%	20%
China-South	2015	6%	35%	60%	10%
	2030	30%	28%	43%	20%	38%	31%	31%	20%
	2050	49%	47%	4%	20%	48%	46%	6%	20%
Taiwan	2015	7%	35%	59%	0%
	2030	31%	24%	46%	0%	39%	29%	31%	0%
	2050	57%	40%	3%	0%	51%	37%	12%	0%
China	2015	6%	35%	59%
	2030	30%	24%	46%		39%	30%	31%
	2050	49%	47%	5%		49%	42%	9%

Table 8.92 shows the results of the capacity factor calculations done under the assumption that variable and dispatchable power plants will have priority access to the grid and priority dispatch. The average capacity factors for limited dispatchable power plants will remain at around 30% until 2030 under the 2.0 °C Scenario. This relatively low factor indicates an overcapacity in China’s power market. The curtailment rates of 20% (REW 1-2018) and more in 2017—mainly for wind farms—confirm this.

Table 8.92

China: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
China			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	42.0%	30%	28%	26%	21%	37%	24%	37%	26%
Limited dispatchable: fossil and nuclear	[%/yr]	39.2%	34%	29%	32%	25%	20%	17%	9%	16%
Limited dispatchable: renewable	[%/yr]	47.3%	20%	17%	21%	14%	68%	19%	47%	27%
Dispatchable: fossil	[%/yr]	30.7%	28%	40%	46%	34%	24%	37%	11%	37%
Dispatchable: renewable	[%/yr]	59.1%	27%	31%	28%	23%	47%	34%	62%	39%
Variable: renewable	[%/yr]	17.9%	15%	15%	17%	16%	22%	17%	22%	17%

8.13.2.3 China: Development of Load, Generation, and Residual Load

The load for China is calculated to continue to increase. Table 8.93 shows that the maximum load will double across all regions. However, the assumed interconnection rates of 20% are sufficient for the 2.0 °C Scenario, whereas significantly higher interconnection capacities will be required under the 1.5 °C Scenario. By 2050, all regions will have an oversupply under the 1.5 °C Scenario. This surplus electricity will be used to produce synthetic fuels and hydrogen. The [R]E 24/7 model does not interface with other world regions, so surplus generation will result in a negative residual load.

Table 8.93

China: load, generation, and residual load development

Power generation structure		2.0 °C				1.5 °C
China		Max demand	Max generation	Max residual load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
China		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
China-North	2020	168.7	168.7	3.6		167.9	167.9	3.6
	2030	215.6	222.5	22.5	0	213.0	292.8	25.8	54
	2050	364.2	504.4	246.3	0	368.2	587.9	−133.4	353
China-Northwest	2020	77.4	80.5	6.1		77.1	82.4	6.1
	2030	95.6	99.5	11.8	0	94.5	126.7	13.3	19
	2050	135.3	206.2	114.3	0	136.9	246.4	−48.1	158
China-Northeast	2020	67.8	67.7	1.9		67.4	67.3	1.9
	2030	83.9	96.3	12.9	0	82.7	126.3	13.8	30
	2050	133.2	219.9	103.7	0	135.0	255.9	−22.8	144
China-Tibet	2020	0.8	0.8	0.0		0.8	0.8	0.0
	2030	1.0	1.0	0.4	0	1.0	1.3	0.2	0
	2050	2.3	2.4	1.4	0	2.4	2.8	−0.9	1
China-Central	2020	208.7	208.7	5.9		207.2	207.2	5.9
	2030	262.7	260.5	44.9	0	258.4	329.5	34.5	37
	2050	445.3	536.2	299.8	0	451.7	642.0	−218.4	409
China-East	2020	226.8	201.9	47.9		225.9	214.1	31.0
	2030	286.3	284.3	40.1	0	283.6	372.4	41.5	47
	2050	454.4	633.5	320.4	0	458.5	739.3	−132.0	413
China-South	2020	173.6	173.6	9.0		173.6	173.6	9.0
	2030	242.3	238.6	36.2	0	239.6	312.0	44.6	28
	2050	368.8	529.6	282.0	0	372.8	622.7	−49.1	299
Taiwan	2020	33.0	33.2	0.0
	2030	46.0	45.9	3.8	0	45.7	52.5	5.9	1
	2050	63.7	92.0	47.1	0	64.1	105.7	−4.0	46

Finally, Table 8.94 provides an overview of the calculated storage and dispatch power requirements in the Chinese region. The calculated hydro pump storage increase by 2050 is consistent with the Thirteenth Five-Year Plan’s requirement for 40 GW additional capacity. Furthermore, curtailment is within the acceptable range, at significantly below 10% in both scenarios by 2050. Battery capacities must increase significantly after 2030. The central, southern, and eastern sub-regions of mainland China have by far the highest storage requirements.

Table 8.94

China: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
China		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
China		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
China-North	2020	0	0	0	0	0	0	0	0	0	0
	2030	45	3	38	41	11	6734	62	2363	2425	0
	2050	14,152	14,255	641	14,896	96,848	39,562	2958	6350	9308	17,528
China-Northwest	2020	158	2	302	304	0	326	3	547	550	0
	2030	7	1	9	10	1	3401	38	1240	1278	0
	2050	12,360	15,511	661	16,172	39,433	31,642	2171	4847	7018	10,080
China-Northeast	2020	0	0	0	0	0	0	0	0	0	0
	2030	912	22	563	585	143	11,430	57	2362	2418	1
	2050	24,955	22,345	1465	23,809	39,793	49,329	2238	5393	7631	10,012
China-Tibet	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	4	43	0	15	15	0
	2050	0	0	0	0	754	3	1	1	3	230
China-Central Baltic	2020	0	0	0	0	0	0	0	0	0	0
	2030	6	1	10	11	576	6013	74	2305	2379	1
	2050	4763	7167	44	7211	167,132	23,175	2609	4372	6981	47,112
China-East	2020	0	0	0	0	0	0	0	0	0	0
	2030	59	4	79	83	797	8720	95	3042	3137	0
	2050	17,604	21,928	1036	22,964	148,351	50,402	3884	8341	12,225	18,866
China-South	2020	0	0	0	0	0	0	0	0	0	0
	2030	74	7	89	96	961	8676	93	3086	3179	0
	2050	21,703	28,028	1143	29,171	116,735	56,742	4139	9307	13,446	22,281
Taiwan	2020	0	0	0	0	0	0	0	0	0	0
	2030	0	0	0	0	89	202	5	121	126	0
	2050	6506	5734	943	6677	14,209	13,873	426	2985	3411	0
China	2020	158	2	302	304	0	326	3	547	550	0
	2030	1102	39	789	827	2582	45,217	424	14,533	14,957	2
	2050	102,042	114,967	5932	120,899	623,254	264,729	18,427	41,596	60,022	126,108

8.14 OECD Pacific

8.14.1 OECD Pacific: Long-Term Energy Pathways

8.14.1.1 OECD Pacific: Final Energy demand by Sector

The future development pathways for OECD Pacific’s final energy demand when the assumptions on population growth, GDP growth, and energy intensity are combined are shown in Fig. 8.98 for the 5.0 °C, 2.0 °C, and 1.5 °C Scenarios. In the 5.0 °C Scenario, the total final energy demand will decrease by 2%, from the current 20,100 PJ/year to 19,600 PJ/year in 2050. In the 2.0 °C Scenario, the final energy demand will decrease by 46% compared with current consumption and will reach 10,800 PJ/year by 2050. The final energy demand in the 1.5 °C Scenario will reach 10,200 PJ, 49% below the 2015 demand. In the 1.5 °C Scenario, the final energy demand in 2050 will be 6% lower than in the 2.0 °C Scenario. The electricity demand for ‘classical’ electrical devices (without power-to-heat or e-mobility) will decrease from 1520 TWh/year in 2015 to 1150 TWh/year in 2050 in both alternative scenarios. Compared with the 5.0 °C case (1890 TWh/year in 2050), the efficiency measures in the 2.0 °C and 1.5 °C Scenarios will save 740 TWh/year in 2050.

Electrification will lead to a significant increase in the electricity demand by 2050. The 2.0 °C Scenario has an electricity demand for heating of approximately 400 TWh/year due to electric heaters and heat pumps, and in the transport sector, the electricity demand will be approximately 1100 TWh/year due to electric mobility. The generation of hydrogen (for transport and high-temperature process heat) and the manufacture of synthetic fuels (mainly for transport) will add an additional power demand of 1000 TWh/year. Therefore, the gross power demand will rise from 1900 TWh/year in 2015 to 3000 TWh/year in 2050 in the 2.0 °C Scenario, 25% higher than in the 5.0 °C case. In the 1.5 °C Scenario, the gross electricity demand will increase to a maximum of 3400 TWh/year in 2050.

The efficiency gains in the heating sector could be even larger than in the electricity sector. In the 2.0 °C and 1.5 °C Scenarios, a final energy consumption equivalent to about 3000 PJ/year and 3100 PJ/year, respectively, will be avoided by 2050 through efficiency gains compared with the 5.0 °C Scenario.

8.14.1.2 OECD Pacific: Electricity Generation

The development of the power system is characterized by a dynamically growing renewable energy market and an increasing proportion of total power coming from renewable sources. By 2050, 100% of the electricity produced in OECD Pacific will come from renewable energy sources in the 2.0 °C Scenario. ‘New’ renewables—mainly wind, solar, and geothermal energy—will contribute 82% of total electricity generation. Renewable electricity’s share of the total production will be 60% by 2030 and 89% by 2040. The installed capacity of renewables will reach about 680 GW by 2030 and 1420 GW by 2050. The share of renewable electricity generation in 2030 in the 1.5 °C Scenario is assumed to be 68%. The 1.5 °C Scenario will have a generation capacity from renewable energy of approximately 1590 GW in 2050.

Table 8.95 shows the development of different renewable technologies in OECD Pacific over time. Figure 8.99 provides an overview of the overall power-generation structure in OECD Pacific. From 2020 onwards, the continuing growth of wind and PV, up to 320 GW and 830 GW, respectively, will complemented by up to 60 GW solar thermal generation, as well as limited biomass, geothermal, and ocean energy, in the 2.0 °C Scenario. Both the 2.0 °C and 1.5 °C Scenarios will lead to a high proportion of variable power generation (PV, wind, and ocean) of 40% and 47% by 2030, respectively, and of 68% in both scenarios by 2050.

Table 8.95

OECD Pacific: development of renewable electricity-generation capacity in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Hydro	5.0 °C	69	73	76	78	78
	2.0 °C	69	76	78	82	84
	1.5 °C	69	76	78	82	84
Biomass	5.0 °C	9	13	15	16	18
	2.0 °C	9	23	26	35	43
	1.5 °C	9	23	29	42	47
Wind	5.0 °C	9	23	28	40	56
	2.0 °C	9	77	145	263	322
	1.5 °C	9	84	198	335	384
Geothermal	5.0 °C	2	4	5	7	11
	2.0 °C	2	4	14	27	37
	1.5 °C	2	4	14	27	37
PV	5.0 °C	43	84	96	102	107
	2.0 °C	43	225	394	701	831
	1.5 °C	43	253	427	782	932
CSP	5.0 °C	0	0	0	1	1
	2.0 °C	0	1	15	39	57
	1.5 °C	0	1	20	49	67
Ocean	5.0 °C	0	1	1	2	4
	2.0 °C	0	3	8	27	42
	1.5 °C	0	3	8	27	42
Total	5.0 °C	132	197	221	246	275
	2.0 °C	132	409	681	1176	1416
	1.5 °C	132	444	774	1345	1594

8.14.1.3 OECD Pacific: Future Costs of Electricity Generation

Figure 8.100 shows the development of the electricity-generation and supply costs over time, including the CO₂ emission costs, in all scenarios. The calculated electricity-generation costs in 2015 (referring to full costs) were around 8 ct/kWh. In the 5.0 °C case, the generation costs will increase until 2030, when they reach 11.1 ct/kWh, and then drop to 10.9 ct/kWh by 2050. The generation costs will increase in the 2.0 °C Scenario until 2030, when they reach 10.5 ct/kWh, and then drop to 8.3 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 10.7 ct/kWh, and then drop to 8.5 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs in 2050 will be 2.6 ct/kWh lower than in the 5.0 °C case, and in the 1.5 °C Scenario, this difference will 2.4 ct/kWh. Note that these estimates of generation costs do not take into account integration costs such as power grid expansion, storage, or other load-balancing measures.

In the 5.0 ° C case, the growth in demand and increasing fossil fuel prices will cause the total electricity supply costs to rise from today’s $160 billion/year to more than $270 billion/year in 2050. In the 2.0 °C Scenario, the total supply costs will be $270 billion/year, and in the 1.5 °C Scenario, they will be $310 billion/year. The long-term costs for electricity supply will be only 2% higher in the 2.0 °C Scenario than in the 5.0 °C Scenario as a result of the estimated generation costs and the electrification of heating and mobility. Further electrification and synthetic fuel generation in the 1.5 °C Scenario will result in total power generation costs that are 17% higher than in the 5.0 °C case.

Compared with these results, the generation costs when the CO₂ emission costs are not considered will increase in the 5.0 °C case to 8.3 ct/kWh in 2050. The generation costs in the 2.0 °C Scenario will increase until 2030, when they will reach 9.3 ct/kWh, and then drop to 8.3 ct/kWh by 2050. In the 1.5 °C Scenario, they will increase to 9.9 ct/kWh, and then drop to 8.5 ct/kWh by 2050. In the 2.0 °C Scenario, the generation costs will be a maximum of 1 ct/kWh higher than in the 5.0 °C case and this will occur in 2040. In the 1.5 °C Scenario, compared with the 5.0 °C Scenario, the maximum difference in the generation costs will be 1.4 ct/kWh, again in 2040. If the CO₂ costs are not considered, the total electricity supply costs in the 5.0 °C case will rise to about $200 billion/year in 2050.

8.14.1.4 OECD Pacific: Future Investments in the Power Sector

An investment of around $2780 billion will be required for power generation between 2015 and 2050 in the 2.0 °C Scenario—including additional power plants for the production of hydrogen and synthetic fuels and investments in the replacement of plants at the end of their economic lifetimes. This value will be equivalent to approximately $77 billion per year on average, and will be $1520 billion more than in the 5.0 °C case ($1260 billion). An investment of around $3100 billion for power generation will required between 2015 and 2050 in the 1.5 °C Scenario. On average, this is an investment of $86 billion per year. In the 5.0 °C Scenario, the investment in conventional power plants will be around 56% of the total cumulative investments, whereas approximately 44% will be invested in renewable power generation and co-generation (Fig. 8.101).

However, in the 2.0 °C (1.5 °C) Scenario, OECD Pacific will shift almost 93% (95%) of its entire investment to renewables and co-generation. By 2030, the fossil fuel share of the power sector investment will predominantly focused on gas power plants that can also be operated with hydrogen.

Because renewable energy has no fuel costs, other than biomass, the cumulative fuel cost savings in the 2.0 °C Scenario will reach a total of $1420 billion in 2050, equivalent to $39 billion per year. Therefore, the total fuel cost savings will be equivalent to 90% of the total additional investments compared to the 5.0 °C Scenario. The fuel cost savings in the 1.5 °C Scenario will add up to $1510 billion, or $42 billion per year.

8.14.1.5 OECD Pacific: Energy Supply for Heating

The final energy demand for heating will increase in the 5.0 °C Scenario by 17%, from 7100 PJ/year in 2015 to 8300 PJ/year in 2050. Energy efficiency measures will help to reduce the energy demand for heating by 35% in 2050 in the 2.0 °C Scenario, relative to the 5.0 °C case, and by 37% in the 1.5 °C Scenario. Today, renewables supply around 7% of OECD Pacific’s final energy demand for heating, with the main contribution from biomass. Renewable energy will provide 33% of OECD Pacific’s total heat demand in 2030 in the 2.0 °C Scenario and 42% in the 1.5 °C Scenario. In both scenarios, renewables will provide 100% of the total heat demand in 2050.

Figure 8.102 shows the development of different technologies for heating in OECD Pacific over time, and Table 8.96 provides the resulting renewable heat supply for all scenarios. Up to 2030, biomass will remain the main contributor. The growing use of solar, geothermal, and environmental heat will lead, in the long term, to a biomass share of 37% in the 2.0 °C Scenario and of 35% in the 1.5 °C Scenario.

Table 8.96

OECD Pacific: development of renewable heat supply in the scenarios (excluding the direct use of electricity)

in PJ/year	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	314	471	504	584	714
	2.0 °C	314	633	815	1250	1579
	1.5 °C	314	650	823	1229	1463
Solar heating	5.0 °C	45	76	92	150	236
	2.0 °C	45	221	452	737	819
	1.5 °C	45	252	543	772	795
Geothermal heat and heat pumps	5.0 °C	30	33	34	36	38
	2.0 °C	30	157	307	737	1119
	1.5 °C	30	197	420	830	1094
Hydrogen	5.0 °C	0	0	0	0	0
	2.0 °C	0	6	16	251	728
	1.5 °C	0	9	160	642	772
Total	5.0 °C	390	580	629	769	988
	2.0 °C	390	1017	1591	2975	4245
	1.5 °C	390	1107	1946	3473	4124

Heat from renewable hydrogen will further reduce the dependence on fossil fuels in both scenarios. The hydrogen consumption in 2050 will be around 700 PJ/year in the 2.0 °C Scenario and 800 PJ/year in the 1.5 °C Scenario. The direct use of electricity for heating will also increases by a factor of 1.6 between 2015 and 2050, and will achieves a final energy share of 21% in 2050 in the 2.0 °C Scenario and 22% in the 1.5 °C Scenario.

8.14.1.6 OECD Pacific: Future Investments in the Heating Sector

The roughly estimated investments in renewable heating technologies up to 2050 will amount to around $530 billion in the 2.0 °C Scenario (including the investments for the replacement of plants after their economic lifetimes), or approximately $15 billion per year. The largest share of the investment in OECD Pacific is assumed to be for solar collectors (around $240 billion), followed by heat pumps and biomass technologies. The 1.5 °C Scenario assumes an even faster expansion of renewable technologies, but with a similar average annual investment of around $15 billion per year (Table 8.97, Fig. 8.103).

Table 8.97

OECD Pacific: installed capacities for renewable heat generation in the scenarios

in GW	Case	2015	2025	2030	2040	2050
Biomass	5.0 °C	44	60	63	69	75
	2.0 °C	44	77	92	117	94
	1.5 °C	44	79	91	113	80
Geothermal	5.0 °C	0	0	0	0	0
	2.0 °C	0	3	8	20	28
	1.5 °C	0	3	7	22	26
Solar heating	5.0 °C	13	22	27	43	69
	2.0 °C	13	64	128	207	230
	1.5 °C	13	73	152	215	224
Heat pumps	5.0 °C	5	5	5	5	6
	2.0 °C	5	11	23	54	74
	1.5 °C	5	16	36	63	71
Total^a	5.0 °C	62	87	95	117	150
	2.0 °C	62	156	250	397	426
	1.5 °C	62	171	287	413	401

^a Excluding direct electric heating

8.14.1.7 OECD Pacific: Transport

Energy demand in the transport sector in OECD Pacific is expected to decrease by 37% in the 5.0 °C Scenario, from around 6200 PJ/year in 2015 to 3900 PJ/year in 2050. In the 2.0 °C Scenario, assumed technical, structural, and behavioural changes will save 49% (around 1900 PJ/year) by 2050 compared with the 5.0 °C Scenario. Additional modal shifts, technology switches, and a reduction in the transport demand will lead to even higher energy savings in the 1.5 °C Scenario of 59% (or 2300 PJ/year) in 2050 compared with the 5.0 °C case (Table 8.98, Fig. 8.104).

Table 8.98

OECD Pacific: projection of transport energy demand by mode in the scenarios

in PJ/year	Case	2015	2025	2030	2040	2050
Rail	5.0 °C	158	162	163	162	161
	2.0 °C	158	154	156	154	159
	1.5 °C	158	156	156	162	161
Road	5.0 °C	5515	4317	3902	3365	2614
	2.0 °C	5515	3961	2979	1837	1456
	1.5 °C	5515	2891	1975	1399	1123
Domestic aviation	5.0 °C	331	524	663	863	922
	2.0 °C	331	338	308	242	194
	1.5 °C	331	307	240	147	109
Domestic navigation	5.0 °C	173	178	181	186	193
	2.0 °C	173	178	181	186	193
	1.5 °C	173	178	181	186	193
Total	5.0 °C	6176	5182	4908	4576	3890
	2.0 °C	6176	4631	3624	2419	2002
	1.5 °C	6176	3533	2551	1893	1586

By 2030, electricity will provide 20% (200 TWh/year) of the transport sector’s total energy demand in the 2.0 °C Scenario, whereas in 2050, the share will be 53% (300 TWh/year). In 2050, up to 480 PJ/year of hydrogen will be used in the transport sector as a complementary renewable option. In the 1.5 °C Scenario, the annual electricity demand will be 240 TWh in 2050. The 1.5 °C Scenario also assumes a hydrogen demand of 360 PJ/year by 2050.

Biofuel use is limited in the 2.0 °C Scenario and the 1.5 °C Scenario to a maximum of approximately 200 PJ/year. Therefore, around 2030, synthetic fuels based on power-to-liquid will be introduced, with a maximum amount of 270 PJ/year in 2050 in the 2.0 °C Scenario. Due to the lower overall energy demand in transport, the maximum synthetic fuel demand will amount to 210 PJ/year in the 1.5 °C Scenario.

8.14.1.8 OECD Pacific: Development of CO₂ Emissions

In the 5.0 °C Scenario, OECD Pacific’s annual CO₂ emissions will decrease by 21%, from 2080 Mt in 2015 to 1640 Mt in 2050. The stringent mitigation measures in both alternative scenarios will cause the annual emissions to fall to 280 Mt in 2040 in the 2.0 °C Scenario and to 160 Mt. in the 1.5 °C Scenario, with further reductions to almost zero by 2050. In the 5.0 °C case, the cumulative CO₂ emissions from 2015 until 2050 will add up to 67 Gt. In contrast, in the 2.0 °C and 1.5 °C Scenarios, the cumulative emissions for the period from 2015 until 2050 will be 31 Gt and 26 Gt, respectively.

Therefore, the cumulative CO₂ emissions will decrease by 54% in the 2.0 °C Scenario and by 61% in the 1.5 °C Scenario compared with the 5.0 °C case. A rapid reduction in the annual emissions will occur under both alternative scenarios. In the 2.0 °C Scenario, this reduction will be greatest in ‘Power generation’, followed by ‘Transport’ and ‘Industry’ (Fig. 8.105).

8.14.1.9 OECD Pacific: Primary Energy Consumption

The levels of primary energy consumption in the three scenarios when the assumptions discussed above are taken into account are shown in Fig. 8.106. In the 2.0 °C Scenario, the primary energy demand will decrease by 48%, from around 36,300 PJ/year in 2015 to 18,900 PJ/year in 2050. Compared with the 5.0 °C Scenario, the overall primary energy demand will decrease by 45% by 2050 in the 2.0 °C Scenario (5.0 °C: 34,700 PJ in 2050). In the 1.5 °C Scenario, the primary energy demand will be even lower (19,900 PJ in 2050) because the final energy demand and conversion losses will be lower.

Both the 2.0 °C Scenario and 1.5 °C Scenario aim to rapidly phase-out coal and oil. This will cause renewable energy to have a primary energy share of 33% in 2030 and 88% in 2050 in the 2.0 °C Scenario. In the 1.5 °C Scenario, renewables will have a primary energy share of more than 89% in 2050 (including non-energy consumption, which will still include fossil fuels). Nuclear energy will be phased-out in 2040 in both the 2.0 °C and 1.5 °C Scenarios. The cumulative primary energy consumption of natural gas in the 5.0 °C case will add up to 230 EJ, the cumulative coal consumption to about 300 EJ, and the crude oil consumption to 380 EJ. In contrast, in the 2.0 °C Scenario, the cumulative gas demand will amount to 150 EJ, the cumulative coal demand to 100 EJ, and the cumulative oil demand to 230 EJ. Even lower fossil fuel use will be achieved in the 1.5 °C Scenario: 150 EJ for natural gas, 70 EJ for coal, and 190 EJ for oil.

8.14.2 OECD Pacific: Power Sector Analysis

South Korea, Japan, Australia, and New Zealand form the OECD Pacific region (also referred to as OECD Asia Pacific or OECD Asia Oceania). Like Non-OECD Asia, a regional interconnected power market with regular electricity exchange is unlikely. Therefore, the region is broken down into seven sub-regions: (1) South Korea; (2) the north of Japan; (3) the south of Japan; (4) Australia’s National Electricity Market (NEM) (covering the entire east coast); (5) the SWIS-NT grid region (comprising Western Australia and the Northern Territory); (6) the North Island of New Zealand; and (7) the South Island of New Zealand. The sub-regions have very different electricity policies, power-generation structures, and demand patterns. In this analysis, simplifications that may not reflect the local conditions are made to ensure that the results comparable on a global level. Therefore, the results for specific countries are only estimates.

8.14.2.1 OECD Pacific: Development of Power Plant Capacities

The region has significant potential for all renewables, including the dominant renewable power technologies of solar PV and onshore wind. Japan has significant geothermal power resources, and offshore wind potentials are substantial across the region. There is also potential for ocean energy across the region, although it is currently a niche technology. Australia has one of the best solar resources in the world, so concentrated solar power plants will be an important part of both scenarios in Australia. Coal and nuclear capacities will be phased-out as plants come to the end of their lifetimes. In the 1.5 °C Scenario, the last coal power plant will be phased out just after 2030.

The solar PV market will reach 8 GW in 2020 under the 2.0 °C Scenario—the same level as the actual regional market of 8.3 GW (REN21-GSR 2018) in 2017—and increase rapidly to 43 GW by 2030. The 1.5 °C Scenario requires that solar PV will achieve an equal market size by 2030 and remain at this level until 2040.

However, the onshore market must increase significantly compared with the market in 2017, which was only 0.54 GW (GWEC-NL 2018). By 2025, 12 GW of onshore wind capacity must be installed annually across the region under the 2.0 °C Scenario, and 17 GW under the 1.5 °C Scenario. By 2030, geothermal, concentrated solar power, and ocean energy must increase by around 2 GW each (Table 8.99).

Table 8.99

OECD Pacific: average annual change in installed power plant capacity

OECD Pacific power generation: average annual change of installed capacity [GW/a]	2015–2025		2026–2035		2036–2050
	2.0 °C	1.5C°	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Hard coal	−4	−9	−5	−4	−1	0
Lignite	0	−1	−2	−2	0	0
Gas	2	−2	−1	−3	−14	0
Hydrogen-gas	0	1	1	5	12	12
Oil/diesel	−3	−2	−2	−2	−1	−1
Nuclear	0	−5	−3	−3	−2	−2
Biomass	2	1	1	1	1	1
Hydro	2	1	0	1	0	0
Wind (onshore)	7	18	12	17	7	6
Wind (offshore)	1	4	5	5	2	2
PV (roof top)	17	33	33	33	16	21
PV (utility scale)	6	11	11	11	5	7
Geothermal	0	2	2	2	2	2
Solar thermal power plants	1	2	3	4	2	3
Ocean energy	0	1	2	2	2	2
Renewable fuel based co-generation	1	1	1	2	1	1

8.14.2.2 OECD Pacific: Utilization of Power Generation Capacities

The very different developments of variable and dispatch power plants in all sub-regions reflect the diversity the Pacific region. Table 8.100 shows that because there is no interconnection between the northern and southern parts of Japan, we assume that even within Japan, the separate electricity markets of the 50 Hz and 60 Hz regions will remain as they are. For Australia, it is assumed that the east- and west-coast electricity markets will have limited interconnection capacities by 2030. The North and South Islands of New Zealand are calculated to have an increased interconnection capacity by 2050.

Table 8.100

OECD Pacific: power system shares by technology group

Power generation structure and interconnection		2.0 °C				1.5 °C
OECD Pacific		Variable RE	Dispatch RE	Dispatch Fossil	Inter-connection	Variable RE	Dispatch RE	Dispatch Fossil	Inter-connection
South Korea	2015	4%	34%	61%	5%
	2030	40%	18%	43%	20%	46%	17%	38%	0%
	2050	70%	28%	2%	25%	62%	24%	14%	0%
Japan – North (50 Hz)	2015	4%	34%	61%	5%
	2030	46%	26%	28%	20%	51%	23%	26%	0%
	2050	72%	26%	2%	25%	64%	21%	15%	0%
Japan – South (60 Hz)	2015	4%	34%	61%	5%
	2030	36%	38%	26%	20%	41%	35%	24%	0%
	2050	72%	25%	2%	25%	64%	20%	15%	0%
Australia – East and South (NEM)	2015	5%	34%	61%	5%
	2030	17%	82%	0%	20%	17%	83%	0%	10%
	2050	73%	26%	2%	25%	67%	21%	12%	20%
Australia West and North (SWIS + NT)	2015	5%	34%	61%	5%
	2030	41%	37%	22%	20%	46%	33%	21%	10%
	2050	73%	25%	2%	25%	67%	21%	12%	20%
New Zealand – North Island	2015	5%	34%	61%	5%
	2030	39%	61%	0%	20%	45%	55%	0%	10%
	2050	77%	22%	2%	25%	70%	18%	12%	20%
New Zealand – South Island	2015	5%	34%	61%	5%
	2030	39%	61%	0%	20%	45%	55%	0%	10%
	2050	77%	22%	2%	25%	70%	18%	12%	20%
OECD Pacific	2015	4%	34%	61%
	2030	40%	31%	30%		45%	29%	27%
	2050	71%	26%	2%		64%	22%	14%

Table 8.101 shows that for the region as a whole, the limited dispatchable power plants will retain a relatively high capacity factor, compared with other regions, until after 2020 and decrease thereafter. The average capacity factors from 2030 onwards will be consistent with all other regions.

Table 8.101

OECD Pacific: capacity factors by generation type

Utilization of variable and dispatchable power generation:		2015	2020	2020	2030	2030	2040	2040	2050	2050
OECD Pacific			2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C	2.0 °C	1.5 °C
Capacity factor – average	[%/yr]	54.8%	55%	55%	29%	29%	29%	29%	34%	31%
Limited dispatchable: fossil and nuclear	[%/yr]	65.1%	54%	54%	26%	31%	19%	29%	25%	32%
Limited dispatchable: renewable	[%/yr]	42.7%	63%	54%	29%	30%	54%	25%	27%	25%
Dispatchable: fossil	[%/yr]	48.6%	48%	50%	20%	23%	35%	21%	19%	26%
Dispatchable: renewable	[%/yr]	43.1%	73%	73%	50%	52%	37%	46%	49%	46%
Variable: renewable	[%/yr]	23.2%	17%	17%	20%	20%	27%	27%	31%	28%

8.14.2.3 OECD Pacific: Development of Load, Generation, and Residual Load

Table 8.102 shows the development of the maximum load, generation, and resulting residual load in the Pacific region. To verify the calculation results, we compared the peak demands in Australia and Japan.

Table 8.102

OECD Pacific: load, generation, and residual load development

Power generation structure		2.0 °C				1.5 °C
OECD Pacific		Max demand	Max generation	Max Residual Load	Max interconnection requirements	Max demand	Max generation	Max residual load	Max interconnection requirements
OECD Pacific		[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]	[GW]
South Korea	2020	86.8	86.8	1.6		86.8	86.8	1.6
	2030	92.3	145.0	6.6	46	94.5	167.5	14.9	58
	2050	116.4	298.0	58.3	123	134.7	339.9	62.4	143
Japan – North (50 Hz)	2020	130.6	97.9	35.1		130.6	97.4	36.0
	2030	79.1	125.0	4.1	42	81.6	145.4	4.1	60
	2050	106.0	252.2	49.4	97	120.1	288.5	33.9	134
Japan – South (60 Hz)	2020	83.6	83.6	3.5		83.7	83.6	3.5
	2030	87.5	126.1	4.8	34	90.4	148.0	11.3	46
	2050	116.2	287.9	51.2	121	132.6	329.3	38.8	158
Australia – East and South (NEM)	2020	6.7	7.0	1.2		6.7	7.0	1.2
	2030	4.3	6.4	3.8	0	4.4	6.6	3.9	0
	2050	5.7	12.6	2.6	4	6.4	14.4	2.5	5
Australia West and North (SWIS + NT)	2020	32.6	32.6	1.1		32.6	32.6	1.1
	2030	33.9	49.6	1.1	15	34.8	58.3	1.1	22
	2050	44.7	111.5	21.3	45	51.4	127.4	22.5	53
New Zealand – North Island	2020	5.5	5.5	3.9		5.5	5.5	3.9
	2030	5.0	6.9	0.2	2	5.1	8.2	0.2	3
	2050	6.5	15.9	3.0	6	7.5	18.1	2.1	9
New Zealand – South Island	2020	1.3	4.4	0.0
	2030	1.5	2.1	0.0	1	1.5	2.4	0.0	1
	2050	2.0	4.8	0.9	2	2.2	5.4	0.6	3

The peak load for Australia’s NEM was calculated to be 32.6 GW in 2020, which corresponds to the reported summer peak of 32.5 GW in the summer of 2017/2018 (AER 2018). Japan’s peak demand was 152 GW in 2015 according to the Tokyo Electric Power Company (TEPCO -2018) and TEPCO predicts that it will be 136 GW in 2020, which is 11% lower.

In the long term, the Pacific region will be a renewable fuel producer for the export market. Therefore, the calculated increased interconnection capacities indicate overproduction, which will be used for international bunker fuels.

The storage and dispatch requirements for all sub-regions are shown in Table 8.103. The Pacific region has vast solar and wind resources and will therefore be one of the production hubs for synthetic fuels and hydrogen, which may be used for industrial processes, for bunker fuels, or to replace natural gas. Therefore, the storage and dispatch demand may vary significantly because they depend on the extent to which renewable fuel production is integrated into the national power sectors or used for dispatch and demand-side management. The more integrated the fuel production is, the lower the overall requirement for battery or hydro pump storage technologies. Further research is required to develop a dedicated plan to produce renewable bunker fuels in Australia.

Table 8.103

OECD Pacific: storage and dispatch service requirements

Storage and dispatch		2.0 °C					1.5 °C
OECD Pacific		Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total Storage demand (incl. H2)	Dispatch Hydrogen-based	Required to avoid curtailment	Utilization battery -through-put-	Utilization PSH -through-put-	Total storage demand (incl. H2)	Dispatch hydrogen-based
OECD Pacific		[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]	[GWh/year]
South Korea	2020	0	0	0	0	70	0	0	0	0	51
	2030	13,803	275	1968	2242	241	27,635	400	3197	3596	890
	2050	156,658	46,248	8717	54,965	22,747	176,909	45,195	8599	53,793	16,906
Japan – North (50 Hz)	2020	0	0	0	0	85	0	0	0	0	62
	2030	25,236	357	2820	3177	200	44,298	418	3819	4238	131
	2050	156,580	32,626	6784	39,411	21,744	185,902	32,676	6917	39,594	15,831
Japan – South (60 Hz)	2020	0	0	0	0	121	0	0	0	0	88
	2030	21,734	343	2320	2663	303	37,937	439	3490	3929	774
	2050	199,561	38,310	8309	46,618	24,062	233,815	38,207	8381	46,588	17,382
Australia – East and South (NEM)	2020	114	0	0	0	15	202	0	0	0	11
	2030	850	0	55	55	0	1696	0	86	86	0
	2050	9375	1983	457	2440	924	11,304	1981	472	2453	538
Australia West and North (SWIS + NT)	2020	4	0	0	0	0	49	0	0	0	0
	2030	11,311	219	1621	1840	87	19,866	255	2289	2544	79
	2050	90,062	18,266	4625	22,891	8053	103,839	18,187	4637	22,824	5140
New Zealand – North Island	2020	0	0	0	0	4	0	0	0	0	3
	2030	1223	20	142	162	0	2165	26	221	247	0
	2050	12,361	2316	546	2862	1090	14,474	2304	548	2852	779
New Zealand – South Island	2020	0	0	0	0	0	0	0	0	0	0
	2030	374	6	43	49	0	658	8	67	74	0
	2050	3733	695	164	859	328	4371	691	164	855	235
OECD Pacific	2020	118	0	0	0	295	251	0	0	0	215
	2030	84,079	1246	9157	10,403	831	146,440	1564	13,290	14,855	1874
	2050	654,287	140,807	29,623	170,431	81,215	760,962	139,369	29,724	169,093	59,243

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Vorheriges Kapitel Renewable Energy Resource Assessment

Nächstes Kapitel Trajectories for a Just Transition of the Fossil Fuel Industry

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Titel: Energy Scenario Results
verfasst von: Sven Teske
Thomas Pregger
Tobias Naegler
Sonja Simon
Johannes Pagenkopf
Bent van den Adel
Özcan Deniz
Verlag: Springer International Publishing
Buch: Achieving the Paris Climate Agreement Goals
Print ISBN: 978-3-030-05842-5

Electronic ISBN: 978-3-030-05843-2

Copyright-Jahr: 2019
DOI: https://doi.org/10.1007/978-3-030-05843-2_8

Springer Professional

Abstract

8.1 Global: Long-Term Energy Pathways

8.1.1 Global: Projection of Overall Energy Intensity

8.1.2 Global: Final Energy Demand by Sector (Excluding Bunkers)

8.1.3 Global: Electricity Generation

8.1.4 Global: Future Costs of Electricity Generation

8.1.5 Global: Future Investments in the Power Sector

8.1.6 Global: Energy Supply for Heating

8.1.7 Global: Future Investments in the Heating Sector

8.1.8 Global: Transport

8.1.9 Global: Development of CO2 Emissions

8.1.10 Global: Primary Energy Consumption

8.2 Global: Bunker Fuels

8.3 Global: Utilization of Solar and Wind Potential

8.4 Global: Power Sector Analysis

8.4.1 Global: Development of Power Plant Capacities

8.4.2 Global: Utilization of Power-Generation Capacities

8.4.3 Global: Development of Load, Generation, and Residual Load

8.4.4 Global System-Relevant Technologies—Storage and Dispatch

8.4.5 Global: Required Storage Capacities for the Stationary Power Sector

8.5 OECD North America

8.5.1 OECD North America: Long-Term Energy Pathways

8.5.1.1 OECD North America: Final Energy Demand by Sector

8.5.1.2 OECD North America: Electricity Generation

8.5.1.3 OECD North America: Future Costs of Electricity Generation

8.5.1.4 OECD North America: Future Investments in the Power Sector

8.5.1.5 OECD North America: Energy Supply for Heating

8.5.1.6 OECD North America: Future Investments in the Heating Sector

8.5.1.7 OECD North America: Transport

8.5.1.8 OECD North America: Development of CO2 Emissions

8.5.1.9 OECD North America: Primary Energy Consumption

8.5.2 Regional Results: Power Sector Analysis

8.5.3 OECD North America: Power Sector Analysis

8.5.3.1 OECD North America: Development of Power Plant Capacities

8.5.3.2 OECD North America: Utilization of Power-Generation Capacities

8.5.3.3 OECD North America: Development of Load, Generation, and Residual Load

8.6 Latin America

8.6.1 Latin America: Long-Term Energy Pathways

8.6.1.1 Latin America: Final Energy Demand by Sector

8.6.1.2 Latin America: Electricity Generation

8.6.1.3 Latin America: Future Costs of Electricity Generation

8.6.1.4 Latin America: Future Investments in the Power Sector

8.6.1.5 Latin America: Energy Supply for Heating

8.6.1.6 Latin America: Future Investments in the Heating Sector

8.6.1.7 Latin America: Transport

8.6.1.8 Latin America: Development of CO2 Emissions

8.6.1.9 Latin America: Primary Energy Consumption

8.6.2 Latin America: Power Sector Analysis

8.6.2.1 Latin America: Development of Power Plant Capacities

8.6.2.2 Latin America: Utilization of Power-Generation Capacities

8.6.2.3 Latin America: Development of Load, Generation and Residual Load

8.7 OECD Europe

8.7.1 OECD Europe: Long-Term Energy Pathways

8.7.1.1 OECD Europe: Final Energy Demand by Sector

8.7.1.2 OECD Europe: Electricity Generation

8.7.1.3 OECD Europe: Future Costs of Electricity Generation

8.7.1.4 OECD Europe: Future Investments in the Power Sector

8.7.1.5 OECD Europe: Energy Supply for Heating

8.7.1.6 OECD Europe: Future Investments in the Heating Sector

8.7.1.7 OECD Europe: Transport

8.7.1.8 OECD Europe: Development of CO2 Emissions

8.7.1.9 OECD Europe: Primary Energy Consumption

8.7.2 OECD Europe: Power Sector Analysis

8.7.2.1 OECD Europe: Development of Power Plant Capacities

8.7.2.2 OECD Europe: Utilization of Power-Generation Capacities

8.7.2.3 OECD Europe: Development of Load, Generation, and Residual Load

8.8 Africa

8.8.1 Africa: Long-Term Energy Pathways

8.8.1.1 Africa: Final Energy Demand by Sector

8.8.1.2 Africa: Electricity Generation

8.8.1.3 Africa: Future Costs of Electricity Generation

8.8.1.4 Africa: Future Investments in the Power Sector

8.8.1.5 Africa: Energy Supply for Heating

8.8.1.6 Africa: Future Investments in the Heating Sector

8.8.1.7 Africa: Transport

8.8.1.8 Africa: Development of CO2 Emissions

8.8.1.9 Africa: Primary Energy Consumption

8.8.2 Africa: Power Sector Analysis

8.8.2.1 Africa: Development of Power Plant Capacities

8.1.9 Global: Development of CO₂ Emissions

8.5.1.8 OECD North America: Development of CO₂ Emissions

8.6.1.8 Latin America: Development of CO₂ Emissions

8.7.1.8 OECD Europe: Development of CO₂ Emissions

8.8.1.8 Africa: Development of CO₂ Emissions

8.9.1.8 The Middle East: Development of CO₂ Emissions

8.10.1.8 Eastern Europe/Eurasia: Development of CO₂ Emissions

8.11.1.8 Non-OECD Asia: Development of CO₂ Emissions

8.12.1.8 India: Development of CO₂ Emissions