Coal Power Overcapacity and the Investment Bubble in China
I
Executive Abstract
Electricity consumption growth in China has experienced dramatic changes from
high to more moderate rates with the advent of the new economic normal. According
to the China Electricity Council (CEC), in 2014, the annual utilization hours of power
generation units was the lowest since 1978, with 4286 hrs - 235 hrs less than in 2013.
Additionally, utilization hours of thermal units was 4706 hrs - 314 hrs less than in
2013, representing even less than the previous low record of 4719 hrs in 1999. It is
expected that the utilization rate will continue to decline in 2015. According to
available data (up to September 2015), the national average utilization hours of
thermal units is 3247 hrs, down by 7.55% compared to the same period last year.
According to existing trends, it is expected that average utilization hours of thermal
units may fall below 4400 hrs in 2015.
Several factors may lead to this decrease in utilization. Besides the impacts of
renewable energy sources and abnormal weather (cool summers and warm winters),
the mismatching between capacity growth and electricity demands is of primary
concern. In 2011, total electricity consumption grew by 11.97%. However, the
number dropped to a mere 3.77% increase in 2014; the lowest since 1998. For the first
nine months of 2015, there has been only 0.8% growth, a further reduction of 3%.
However, despite this decrease in demand, investor interest in coal power capacity
remains unabated. According to CEC, total capacity will reach 1460 gigawatts (GW)
in 2015, growing by 7.1%. For coal power sources, new additions will reach as high
as 214 GW during the 12th
Five-year-plan (FYP) period.
Lack of strategic power projections and the underestimated lead-time of
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
6%
8%
0
1000
2000
3000
4000
5000
6000
2011 2012 2013 2014 2015(expected)
ho
ur
operating hour growth rate
II
power-source installation has led to a mismatch between capacity installation and
electrical demand. Additionally, the growth of coal-power is higher than electrical
demand, which mainly results from the significant economic advantages caused by
low coal prices and high feed-in tariffs.
This report provides a brief analysis on the power sector during the 12th
FYP
period, with a particular focus on the utilization of thermal (coal power) fleets, as well
as a discussion regarding market space for coal power units and the risk of excessive
investment on coal power during the 13th
FYP period are discussed. The methodology
and the research process are shown in the Figure below.
- Power sector development
under the 12th FYP period
- Thermal (coal) power utilization
status under the 12th FYP period
Current State
Analysis
- Economic development
under the 13th Five Year Plan
- Power consumption structure
- Electricity consumption elasticity coefficient
Future
Demand
Outlook
- Electric power and energy balance
- Targets for renewable energy development
- Reasonable scale of coal power capacity
(national, regional, key provinces)
Power
planning
- Reasonable proportions of capacity
currently under construction
- Sensitivity analysis
- Investment risk
Quantifying
Coal Power
Over-capacity
Conclusions and
Policy Suggestions
The main findings are:
Under the new economic normal, electricity demand has declined to more
moderate rates since 2014. However, because of the delay in strategic planning and
III
the lengthy lead-time of new installation, the addition of coal power units remained at
a relatively high level in 2014. According to our estimate, utilization hours of thermal
units will drop to 4330 hrs and the overcapacity of coal power units will range
between 80-100 GW by 2015. This overcapacity risk in the coal power industry
should be evaluated closely by both the government and the industry.
Under a potential 4.2% growth in annual electricity demand during the 13th
FYP
period, total electricity consumption could reach 6920 hrs in 2020. Constrained by the
15% non-fossil fuel-derived energy goals and a target annual operating hours of 4800
hrs, the rational capacity of coal power would be around 910 GW. Active
implementation of clean power substitution could push electricity demand to the
expected ceiling (4.9%) and push up the rational scale by 50 GW. A 13.4% to 14%
rise in the share of the non-fossil fuel energy supply by the power sector is equivalent
to replacing 22 GW coal power. Under all non-fossil scenarios, the rational capacity
of coal power in 2020 would be significantly lower than the current industry forecasts
of 1040-1100 GW.
If all the Environment Impact Assessment (EIA) approved 160 GW coal power
projects (2012-2014) were commissioned in 2020, there would be an excess of 70-120
GW coal power. With a normal schedule of old unit decommission, this excess may
be manageable. However, if all the coal power projects submitted for EIA approval
(283 GW until the end of September 2015) were put into operation by 2020, the
excess capacity would reach 200 GW and control would be difficult to maintain. Such
large-scale overcapacity could result in disastrous effects, costing as much as 700
billion CNY—an investment that is unlikely to be recovered. This overcapacity could
cause utilization hours of coal power units to decrease to 3800 hrs, further
deteriorating the economic performance.
Unnecessary installation of coal power fleets may also inhibit renewable energy
development and deployment, leading to serious curtailment of renewable energy.
This inhibition, with the added crowding-out effect of investment interference, would
actively lead to block China's strategic opportunity for transitioning to a low-carbon
energy economy.
For the provinces of Shanxi, Hebei, Jiangsu and Zhejiang (except for Xinjiang),
actual coal power capacity could be in an acceptable excess of 2-3 GW under a partly
commissioned scenario. However, under a fully commissioned scenario, actual
capacity may be substantially higher in all provinces but Zhejiang (with an excess of
IV
2.3 GW). Shanxi could have the largest excess (21 GW), followed by Xinjiang (15.5
GW) and Jiangsu (10 GW).
Going forward, future policy must be strategic in order to address these concerns
with the coal power industry. Of top priority is consistent and coordinated power
planning. Overall, power planning with seamless coordination between unit planning
and grid expansion is vital. Ideally, this coordination will occur on both national and
local levels and should be aimed at integrating multiple sources of power generation.
The ministry in charge of energy affairs (National Energy Administration, NEA and
National Development and Reform Commission, NDRC) should function as the
primary governing body charged with regulation and information dissemination.
Power planning during the 13th
FYP should be released in a structured and timely
fashion in order to guide market investment with adequate and transparent
information. An early warning mechanism on coal power investment should also be
established. It is strongly recommended that the competent authorities regularly
publish electricity market prospective reports, update electricity demand outlooks
regularly, and provide early warning on potential coal power overcapacity risk when
detected.
Contents
Executive Abstract ........................................................................................................................... I
1. China’s power sector during the 12th FYP period ......................................................................... 1
1.1 Electricity consumption ....................................................................................................... 1
1.2 Power generation capacity .................................................................................................. 2
1.2.1 Overall analysis ......................................................................................................... 2
1.2.2 The growth of coal power ........................................................................................ 4
1.2.3 The growth of other power sources ......................................................................... 5
1.3 Trans-regional power delivery ............................................................................................. 6
1.3.1 Trans-regional transmission development during the 12th FYP period .................... 6
1.3.2 Trans-regional power and energy exchange during the 12th FYP period ................. 8
1.3.3 Outlook of trans-regional delivery in the 13th FYP period ...................................... 10
2. The operation status of thermal power during the 12th FYP period ............................................ 10
2.1 Overall analysis .................................................................................................................. 10
2.2. Regional analysis .............................................................................................................. 12
2.3 Case analysis of typical provinces ..................................................................................... 13
2.4 Impact factors of low utilization rate ................................................................................ 13
2.5Factors contributing to high coal power investment ......................................................... 14
3. Newly EIA approved coal power projects .................................................................................. 15
3.1 Overall analysis .................................................................................................................. 15
3.2Regional analysis ................................................................................................................ 16
3.3 Typical provinces ............................................................................................................... 18
4. Electricity demand outlook and low-carbon development targets during the 13th FYP period ... 18
4.1 Electricity demand outlook ............................................................................................... 18
4.1.1 Structural factors affecting electricity demand ...................................................... 19
4.1.2 Electricity demand projection ................................................................................ 20
4.2 The goal of non-fossil primary energy share and low-carbon electricity .......................... 20
4.2.1 Power sector’s contribution to the 15% target ...................................................... 21
4.2.2 Officially declared clean energy development target by 2020 ............................... 22
5. Coal power investment bubble during the 13th
FYP period ........................................................ 22
5.1 Coal power development space during the 13th FYP period ............................................. 23
5.2 Sensitivity analysis of coal power development space ..................................................... 25
5.3 Quantification of Coal Investment Bubble during the 13th FYP period ............................. 26
5.3.1 National level analysis ............................................................................................ 27
5.3.2 Regional Analysis .................................................................................................... 29
5.3.3 Typical provinces .................................................................................................... 30
6. Conclusion .................................................................................................................................. 32
6.1 Research conclusions ........................................................................................................ 32
6.2 Policy recommendations ................................................................................................... 33
AppendixⅠ: Transmission capacity of 27 UHV lines .................................................................... 35
Appendix Ⅱ: New EIA approved coal power projects from 2012 to 2015 ................................... 38
1
1. China’s power sector during the 12th
FYP period
1.1 Electricity consumption
During the 12th FYP period (2011-2015), electricity consumption growth in China has
experienced radical adjustment from high to more moderate rates with the advent of the new
economic normal. According to CEC, total electricity consumption grew by 11.97% [1]
in
2011. However, this growth dropped to a mere 3.77% in 2014, representing the lowest
recorded since 1998 [2]
.The electricity demand has continued to decline during 2015.
According to NEA, the growth seen from January to September 2015, comparing same period
last year, has been only 0.8%, an additional reduction of 3% [3]
. According to existing
information, growth in demand is not likely to exceed 2% [4]
in 2015. Information on
electricity consumption and its growth during the 12th FYP period is shown in Figure1-1:
Figure1- 1 Electricity consumption in the 12
th FYP period
Reference: [1, 2, 5, 6]
.
On a regional grid level, electricity demand in six regional grids has been declining in
the 12th FYP period, which is consistent with the national trend. The downward amplitude in
the Northwest grid is particularly notable.
4703
4966
5342
5523 5634
11.97%
5.60%
7.58%
3.77%
2.00%
0%
2%
4%
6%
8%
10%
12%
14%
4200
4400
4600
4800
5000
5200
5400
5600
5800
2011 2012 2013 2014 2015(expected)
TW
h
Electricity consumption Electricity demand growth
2
Figure1- 2 Regional electricity demand growth in the 12th
FYP period
Reference: [1, 2, 5, 6]
.
In this report, five provinces were selected for a case study at the provincial level,
including two coal power base provinces (Shanxi and Xinjiang), two load center provinces
(Jiangsu and Zhejiang), and one province saturated with heavy industry and plagued with
serious air pollution (Hebei). During the 12th FYP period, electricity demand dropped by 9%
in Zhejiang, Jiangsu and Hebei. Meanwhile, the growth in power export provinces like Shanxi
and Xinjiang fell from high rates (more than 25% for Xinjiang and 13% for Shanxi in 2011)
to negative growth in 2014(Figure 1-3):
Figure1- 3 Electricity demand growth in typical provinces in the 12
th FYP period
Reference: [1, 2, 5, 6]
.
1.2 Power generation capacity
1.2.1 Overall analysis
0%2%4%6%8%
10%12%14%16%18%20%22%
2011 2012 2013 2014
North China East China Central China
Northeast Northwest Southern
-5%
0%
5%
10%
15%
20%
25%
30%
35%
40%
2011 2012 2013 2014
Hebei Shanxi Zhejiang Jiangsu Xinjiang
3
During the 12th FYP period, new additions to the power sector kept capacity at a high
level. The total generation capacity was 1063 GW [1]
in 2011, increasing to 1360 GW [2]
by
2014. According to data until the end of September 2015, the new additions reached
capacities as high as 74290 megawatts (MW) in 2015, growing by 21790 MW compared to
the same period last year. In particular, the new addition of thermal units was 39550
MW—13750 MW [3] more compared with the same period last year. According to CEC, total
capacity will reach 1460 GW at the end of 2015, growing by 7.1%, and non-fossil energy
power capacity will account for approximately 35% [2]
. There will be 320 GW of hydropower,
28.64 GW of nuclear power, 110 GW of grid-connected wind power, 36.5 GW of
grid-connected solar power and 11 GW of biomass [2]. Investment in the power generation
sector has maintained high growth since 2014, coexisting with the low growth of electricity
demand. This mismatch, caused by the planning lag and lead-time issues, requires
strategically structured adjustments in order to avoid long-term negative impact, which is the
core concern of this report.
Figure1- 4 The growth of total generation capacity in the 12th
FYP period
Reference: [1, 2, 5, 6]
.
1062.36 1146.75
1257.68
1362.21 1458.97
9.95%
7.94%
9.67% 8.31%
7.10%
0%
2%
4%
6%
8%
10%
12%
0
200
400
600
800
1000
1200
1400
1600
2011 2012 2013 2014 2015(expected)
GW
Total capacity Growth rate
4
Figure1- 5 Generation capacity mix of China in the 12th
FYP period
Reference: [1, 2, 5, 6]
.
During the 12th FYP period, renewable energy has developed rapidly, and installed
capacity and power generation continue to increase steadily. By comparing the new capacity
additions from 2015 with the amount added in 2011, the share of coal power has declined
while the share of renewable energy has increased year by year.
Figure1- 6 The structure of newly-added generation capacity in 2011(left) and 2015(right)
Reference: [1, 2]
.
1.2.2 The growth of coal power
During the 12th FYP period, coal power capacity increased dramatically from 710 GW [1]
in 2011 to 830 GW [2] by the end of 2014. Although the growth trend is slowing down, the
rate of coal power capacity was still relatively high (4.3%) in 2014 despite renewable energy
deployment[2]
. This amount was higher than the growth of electricity consumption. Notably,
the new addition of coal power dropped from 59.95 GW [1]
in 2011 to 34.22 GW [2]
in 2014.
According to CEC, the new addition of coal power is expected to be 38 GW [2]
at the end of
67.23% 66.17% 63.27% 60.93% 59.49%
5.09% 5.31% 5.91% 6.61% 6.89%
28.98% 30.05%
32.86% 34.45%
36.28%
0%
5%
10%
15%
20%
25%
30%
35%
40%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2011 2012 2013 2014 2015(expected) Coal Other thermal Hydro
Nuclear Wind Solar and others
Non-fossil
5
2015 and the annual new addition of coal power is nearly 43 GW [1, 2, 3, 4]
during 2011-2015.
Figure1- 7 The growth of coal power in the 12th
FYP period
Reference: [1, 2, 5, 6]
.
1.2.3 The growth of other power sources
During the 12th FYP period, other sources of power also maintained rapid growth. While
the growth of hydropower remained relatively stable, the growth of wind power stabilized at
25.2% [2]
in 2014 after a substantial increase of 56.3% [1]
in 2011. The grid-connected wind
power capacity was 95.81 GW at the end of 2014, and the scale in Inner Mongolia and Gansu
reached 20.7 GW and 10.08 GW [2]
, respectively. The growth of nuclear power recovered in
2014 after the freezing point in 2012 due to the impact of Fukushima nuclear accident. Solar
power capacity was further developed and grid-connected solar power capacity reached 26.52
GW at the end of 2014, growing by 67% [2]
, with the majority being from photovoltaics (PV).
For 2011 and 2013, the growth of PV capacity reached as high as 864% [1]
and 342% [6]
,
respectively. Wind power has entered the stage of large-scale commercialization, while solar
power is rapidly moving towards it. Clean and non-fossil fuel power is developing rapidly to
achieve the goal of 15% non-fossil fuel[7]
in primary energy supply by 2020. Ambitious
targets of 20% non-fossil primary energy and greenhouse gases (GHG) that peak by 2030
have been proposed in China’s Intended Nationally Determined Contributions, (INDCs)
submitted to the United Nations recently [8]
. Because of the inevitable trend towards a
low-carbon transition of the energy and power system, it is of vital importance to discuss the
prospects of coal power in China.
7.77%
6.25%
4.87%
4.30% 4.58%
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
0
100
200
300
400
500
600
700
800
900
1000
2011 2012 2013 2014 2015(expected)
GW
Coal power Growth rate
6
Figure1- 8 The capacity growth of major clean generation technologies in the 12th
FYP period
Reference: [1, 2, 5, 6]
.
1.3 Trans-regional power delivery
1.3.1 Trans-regional transmission development during the 12th
FYP period
The spatial distribution of power resources and power loads makes trans-regional
delivery a challenging and inevitable choice for China. Overall, power load centers are
concentrated in East China, North China, South China, and part of Central China. However,
power resources are most concentrated in Northwest China. With the construction of a
long-distance transmission network, abundant power resources in the Northwest can be
transferred to these load center regions.
Limited by research purpose and report length, this report mainly focuses on the
trans-regional ultra high-voltage (UHV) transmission network. According to publicly
available statistical data, there are nearly thirty UHV routes in operation or under construction
(Figure 1-9). Among them, the number of direct current (DC) lines accounts for about
two-thirds, with transmission capacity at about 147 GW, and the rest are alternating current
(AC) lines with about 62.2 GW transmission capacity. (Refer to Appendix I for detailed
project information.)
7.83% 7.08%
12.41%
6.97% 5.45%
16.13%
0.00%
16.62%
35.62%
44.06%
56.31%
32.86%
24.57% 25.21%
14.81%
0%
10%
20%
30%
40%
50%
60%
2011 2012 2013 2014 2015(expected)
Hydro Nuclear Wind
7
Northeast Power
Grid
Northwest Power Grid
North China Power Grid
East China Power Grid
Central China Power Grid
Southern Power Grid
±800kV DC
1000kV AC
±1000kV DC
Figure1- 9 Prospect of UHV transmission network in China
Reference: [35-61]
.
East China contains a dense network of AC UHV transmission lines, accounting for 68%
of total AC transmission capacity, with 32.8 GW delivery capacity inside the region and 9.4
GW delivery capacity from other regions (table 1-1). There are 4 AC UHV transmission lines
in North China, mainly for internal delivery, and partly for delivery to East and Central
China.
Table 1-1 trans-regional UHV power transport capacity Unit: GW
Export
Import Northern East Central Northeast Northwest South Total
North AC 15
15
DC 10
10
East AC 9.4 32.8
42.2
DC 18
22.2
30
70.2
Central AC 5
5
DC
10
42.06
52.06
South AC
DC
15 15
Total 57.40 32.8 32.2 0 72.06 15 209.46
Reference: [35-61]
.
8
The Northwest grid is a primary DC UHV export region with 8 transmission lines
delivering electric power to East China and Central China and accounting for about 50% of
DC UHV trans-regional transmission capacity. East China is the main DC UHV import
region, with 8 input lines receiving electricity from Northwest, North and Central China,
accounting for 48% of DC UHV trans-regional transmission capacity (table 1-1).
1.3.2 Trans-regional power and energy exchange during the 12th
FYP period
0-300
300-400
400-550
550-700
700+
North China Power Grid
Northwest Power Grid
Northeast Power Grid
East China Power Grid
Central China Power Grid
Southern Power Grid
Figure1-10 Trans-regional power exchange in China
Among the six regional power grids, the Northwest and Northeast power grids are
usually exporters of power and energy, while the North China, East China and Central China
grids are generally importers, with the South power grid playing an important role in
exchanging power with the Central China grid (Figure 1-10).
In 2011, the trans-regional power delivery experienced significant growth. However,
there was a big decline in 2012, largely because of enhanced power supply capacity in load
center regions and slowing electricity demand. In 2013 there was very little growth of
trans-regional power delivery (Figure 1-11).
9
Figure1-11 Trans-regional power exchange in China, 2010-2013
Reference: [1, 5, 6]
.
Figure1-12 Trans-regional electricity exchange in China, 2010-2014
Reference: [1, 2, 5, 6]
.
Trans-regional energy exchange has been increasing each year in 2011-2014. By the end
of 2014, the amount of trans-regional electricity delivery had reached 274.1 TWh, increasing
by 13% as of 2013 scale and nearly doubling the 2010 scale [2]
. In addition, we can see that
trans-regional electricity delivery increased rapidly in the first three years of 12th FYP period.
However, the growth rate has been falling since 2014. According to available data,
trans-regional electricity delivery reached 230.3 TWh from January to September in 2015, a
growth of only 1.0% [3]
. Based on these trends, we expect the rate of trans-regional energy
delivery will drop significantly in 2015.
0
20
40
60
80
100
120
140
160
2010 2011 2012 2013
GW
regional power exchange
13%
20% 21%
13%
0%
5%
10%
15%
20%
25%
0
50
100
150
200
250
300
2010 2011 2012 2013 2014
TW
h
Regional transport power Growth rate
10
1.3.3 Outlook of trans-regional delivery in the 13th
FYP period
With the commission of more UHV power transmission projects; there will be a total of
27 UHV lines in operation by 2020, including 18 DC transmission lines and 9 AC
transmission lines (See Appendix Ⅰ). From a regional perspective, the trans-regional
transmission capacity of Northwest grid will reach 72 GW, among which Xinjiang will hold a
substantial share (48 GW), including 3 AC and 5 DC lines for export. The power exchange
capacity of North China will reach about 60 GW, among which 35 GW is for trans-regional
delivery. The electricity exchange capacity of Central China will be about 32 GW, 22 GW of
which is used for trans-regional transmission. East China and South China grids will mainly
improve the capacity of internal power exchange, without significant trans-regional export.
Among the case study provinces, Shanxi and Xinjiang are considered as the power export
provinces, while Hebei, Jiangsu and Zhejiang are power import provinces. It is estimated that
trans-regional power transmission capacity in Shanxi will reach 13 GW by 2020, and the
maximal trans-regional power transmission capacity of Xinjiang could reach 46 GW.
According to the estimate, the national trans-regional electricity delivery is expected to be
about 520 TWh in 2020, nearly doubling the 2014 scale.
2. The operation status of thermal power during the 12th
FYP period
2.1 Overall analysis
Figure 2-1 shows the statistics on operating hours of thermal power during 2011-2014. A
general downward trend can be seen. In the first nine months of 2015, the average operating
hours of thermal power is 3247hrs, a reduction of 7.55% compared to the same period in 2014
[3]. Assuming 8% reduction of the entire year, the number of annual thermal power operating
hours in 2015 may be 4330 hrs. Based upon a reasonable annual utilization of 4900 hrs, in
2015 roughly 80-100 GW of overcapacity in coal power is expected.
11
Figure 2-1 Change of thermal power operating hour during the 12th
FYP period
Reference: [1, 2, 5, 6]
.
Ever since the 11th FYP period, the operating hours of thermal units in China has shown
a distinct downturn. The number of hours has gradually fallen from as high as 5800hrs [9]
in
2005 to a reasonable range of 5000-5200hrs in 2010 and 2011(Figure 2-2), when power
shortages was no longer a concern in China. With the exception of an increase of 30hrs in
2013, the number of hours dropped significantly during the 12th FYP period and the rate of
decline is increasing. It is estimated that operating hours of thermal power will fall by
approximately 18.38% during the 12th FYP period, with annual decline by 3.98%.
Figure 2-2 Change of operating hour of thermal power during 2005-2015
Reference: [9-11]
.
Since there is no publicly available data on the operation hours of coal power in China,
5305
4982 5012
4706
4330
5.40%
-6.10%
0.60%
-6.10%
-8.00%
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
6%
8%
3500
3700
3900
4100
4300
4500
4700
4900
5100
5300
5500
2011 2013 2015(expected)
gro
wth
ra
te
op
era
tin
g h
ou
r
operating hour growth rate
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
6%
8%
3000320034003600380040004200440046004800500052005400560058006000
op
era
tin
g h
ou
r (h
ou
r)
Thermal power Coal power
growth rate of thermal power growth rate of Coal power
12
our estimate of national average coal power operating hours since 2009 is based on fuel mix
data from thermal power use as well as empirical values of annual operations of other thermal
units. Generally speaking, during the same year, the operation hours gap between coal power
and thermal power is small, with just about 100 hrs more in coal units than thermal units. Our
estimate also reveals a similar trend. Hence, due to issues with data availability, our analysis
uses thermal power data to approximate coal power statistics.
2.2. Regional analysis
Figure2-3 Thermal power operating hour in six regional power grids, 2011-2014
Reference: [9-11].
Figure 2-3 reports the operating hours of thermal units in China’s six regional grids
during 2011-2014. Regional patterns are consistent with the national trends, with the
exception of a slight increase in 2013. In 2011, supply and demand was balanced in South
China grid, Central China grid, Northwest grid, and North China grid, and thermal operating
hours were about 5000 hrs [1]
in these regional grids. There was power shortage in the East
China grid, and the operating hours of thermal units was about 5400 hrs [1]
there. However,
due to weak increases in demand in the Northeast grid, there was an excess of power supply;
thermal power operating hours was as low as 4300 hrs [1]
. In 2013, under the direction of the
regional industrial development and the enhancement of trans-regional UHV transmission
lines, thermal operating hours in the Northwest grid was up to 5500 hrs [6]
, largely pushing up
the power industry and local governments’ expectations on future expansion of coal power
capacity. Surplus continued in the Northeast grid and thermal operating hours declined to
around 4000 hrs [6]
. In 2014, except for the Northeast grid, thermal power operating hours in
other regional power grids continued to decline. In the East China grid the number fell by 530
3500
3700
3900
4100
4300
4500
4700
4900
5100
5300
5500
2011 2012 2013 2014
ho
urs
North China East China Central China
Northeast Nothwest South China
13
hrs, largely due to the decrease in demand and electricity import [2]
. In the South China grid,
thermal power operating hour fell by 645 hrs due to lack of demand as well as strong
hydropower development [2]
. With sluggish demand increases in 2015, it is expected that
thermal power operating hours are likely to decrease even more sharply than in past years..
2.3 Case analysis of typical provinces
Figure 2-4 reports the situations of thermal operation in typical provinces during the 12th
FYP period. The numbers in 2015 are estimated based on the data for the first half year.
Figure 2-4 Thermal operating hour in case provinces during the 12th
FYP period
Reference: [9-11]
.
Annual operation hours of thermal units in the five case study provinces consistently
declined over this period. In 2014, operating hours of thermal units in Hebei, Jiangsu and
Xinjiang were still higher than 5000 hrs [10]
. However, in 2015, the number in the rest may be
less than 5000 hrs (with the exception of Jiangsu). The operating hours of thermal units in
Zhejiang was less than 5000 hrs in 2014, while in 2015 the number will likely be as low as
4000 hrs. In 2015, for Shanxi, a major coal power province, the thermal unit’s operating hours
are expected to be less than 4200 hrs.
2.4 Factors Impacting low utilization rate
The factors contributing to low utilization rate of thermal (coal) power are as follows.
(1) The most important factor is the mismatch between coal power capacity installation
and power demand. With the institution of the new economic normal, electricity demand is
also losing its momentum. In 2014, total electricity consumption grew by only 3.8% [14]
,
roughly half of the growth rate in 2013. But in the same year, generation capacity increased
5686
5268 5296
4522
4007
5785 5734 5690
5240 5105
5979
5767 5649
5248
4745
5284
5046 5147
4938
4175
5752 5621
5527
5231
4903
3900
4400
4900
5400
5900
2011 2012 2013 2014 2015(E)
op
era
tin
g h
ou
r
Zhejiang Jiangsu Xinjiang Shanxi Hebei
14
by 8.31%. For the first nine months of 2015, electricity consumption increased by only 0.8%
comparing same period last year, while generation capacity increased by 9.4% [3]
. Because of
this large mismatch, electricity generation in these units decreased by 2.2% [3]
. For thermal
units, the operating hours went down by 265 hrs, 83 hrs more than the decline over the same
period in 2014.
(2) Because of the transition to renewable energy, coal power will continue to serve as
an increasingly ancillary service [12]
. Gas power, which is the best candidate for providing
peak loads and system flexibility, is underdeveloped in China. Hence in China, mainly coal
power units and partly adjustable hydropower units serve as mechanisms for peak load
regulation. With the integration of more renewable energy sources, the operation hours of
coal power will certainly decrease. It is, therefore, likely that gas power and pumped storage
hydropower may not be able to provide enough system flexibility. This could, in turn, cause
the operation hours of coal power to continue to decline.
(3) Abnormal warm winters and cool summers in recent years led to a decline in
electricity demand. For example, in July 2015, due to the impact of El Nino effect, continuous
precipitation in the middle and lower reaches of Yangtze River resulted in an abnormally cool
summer. On the other hand, a warmer winter occurred in 2014 and is expected to happen
again in 2015 [13]
. The declined power load for cooling in summer and for heating in winter
reduces the overall operating hours of generating units.
2.5 Factors contributing to high coal power investment
China's energy resource endowment and the cost advantage of coal power generation led
to a coal-dominated energy mix of power generation infrastructure that has persisted, despite
the dramatic increases in renewable energy deployment. Local governments in regions with
abundant coal resources and power generation enterprises have always had abundant interest
in investing in coal power projects. These investment interests are because of the following
factors:
(1) Low coal price while high on-grid wholesale tariff encourages generators’ investment
enthusiasm. In recent years, coal price has dropped down continuously and lowered the cost
of coal power generation. Although NDRC has debased the benchmark tariffs of coal power,
the price reduction is less than actual cost reduction. Though fewer utilization hours cut
generators’ revenues, low coal prices enable generators to take advantage of generous profits
[15]. Additionally, the current model involves local government’s participation in the planning
of generation units’ annual operating hours. This, in turn, also adds to generators’ stable
15
return expectations.
(2) The provincial governments have been delegated with the rights of approving
thermal power projects under their jurisdiction. This, to a certain extent, indulges the
investments interests and desires of local governments. In addition, the economic downturn
pressure further fosters local governments’ preference for capital-intensive projects such as
coal power. Data shows that, in the first half of 2015, there was a total of 23.43 GW new
additions in coal power capacity, a 55% increase compared to the same period in last year.
According to media reports, though not yet confirmed by the government, the scale of newly
approved thermal power projects was as high as 200 GW in the first half of 2015 [16]
.
(3) These substantial economic advantages compared with renewable energy empower
coal power with a huge market opportunity in China. At present, the cost of renewable energy
is still high, while coal power remains relatively inexpensive. Although the production costs
of onshore wind power and utility-scale PV in some areas have been close to that of coal
power, the prices of offshore wind power and Concentrating Solar Power (CSP) are much
more expensive. Hence, in all, coal power projects are more lucrative and have more stable
profit expectation than renewable energy. Therefore, to realize the low carbon power sector
transition in China, it is very important to eliminate institutional barriers that hinder the
development of renewable energy.
3. Newly EIA approved coal power projects
3.1 Overall analysis
Figure 3-1 Statistics on EIA approved coal power projects, 2012-2015
160
10
30
83
123
approved, 2012-2014 applied, 2015 pre-approved, 2015 approved, 2015
16
Reference: [17]
.
The project team adopts this database from Greenpeace [17]
, which operates under
construction coal power projects from EIA applications and approval by the national and local
environmental protection departments. According to the database, from 2012 to September of
2015, a total of 283 GW1 coal power projects have been submitted for EIA approval, among
which the approved projects in 2012-2014 are 160 GW2. In this report, the projects approved
before 2015 are regarded as under construction, accounting for 56.6% of new coal power
projects and the other 123 GW projects are new applications or newly EIA-approved in 2015,
accounting for 43.4%3
[17]. (See AppendixⅡ)
3.2Regional analysis
From the regional perspective, the Northwest grid takes the leading position in coal
power development. On the one hand, the western provinces are China's coal power bases,
while in some eastern regions new coal power projects have been strictly limited. On the
other hand, western regions are also wind power and solar energy bases in China. Due to the
intermittence of renewable energy, the current developmental model involves bundling
renewable and coal power together for export into load center regions. To some extent,
renewable energy has accelerated the development of coal power in some western provinces.
In addition, there are a large number of new coal power projects in the North China Grid. The
projects in Northwest and North China Grids account for about 50% of the national total.
1. This data is different from the statistics released by China Electricity Council (CEC). According to a CEC report
on power sector’s operation status from January to September in 2015, the total scale of power generation projects
is 177GW, among which thermal power is 78GW. There is a possibility that some approved projects ceased
construction, and some commissioned projects did not receive environmental protection certificate are included in
the under construction projects.
2. According to Greenpeace, there are another 4510MW coal power projects under construction but without
receiving government approval.
3. Coal power projects approved during 2012-2014 refer to projects approved by Ministry of environmental
protection, not including CHP projects approved by local environmental protection departments. 2015 Projects
include those new ones until the end of September 2015 (By Ministry of environmental protection from January to
March 2015 and by local environmental protection departments from April to September 2015).
17
Figure 3-2 Statistics on EIA approval of new coal power projects in six regional power grids
Reference: [17]
.
Figure 3-3 Regional distribution of approved coal power projects
Reference: [17]
.
Inside the regional grid, the new coal projects in the Northwest Power Grid are mainly
located in Xinjiang and Shaanxi, those in Southern China Power Grid are mainly located in
Guangdong and Guizhou, North China power grid mainly in Inner Mongolia, Shandong and
Shanxi, while East China grid mainly in Anhui. The scale of new coal power projects in each
of the above provinces is more than 14 GW, while in Guangdong and Shanxi the scale is
more than 20 GW, especially in Xinjiang it is more than 30 GW [17]
(See AppendixⅡ). These
provinces can be easily divided into two categories: one is rich in coal resources, such as
Xinjiang, Shanxi, etc., the other is a load center or close to load center with high demand
growth expectation, such as Guangdong, Anhui, etc. There are much fewer new projects in
0
10
20
30
40
50
60
70
80
Northwest North China Central
China
East China South Northeast
GW
approved, 2012-2014 approved, 2015 pre-approved, 2015 applied, 2015
23.9%
23.0%
17.5%
16.0%
15.2%
4.3%
Northwest North China Central China East China South Northeast
18
Central China due to a shortage of coal resources and few in the Northeast due to weak
demand.
3.3 Case study provinces
In the five case provinces, new coal power projects are mostly concentrated in western
regions rich in coal resources, among which 34.23 GW and 27.01 GW [17]
projects are located
in Xinjiang and Shanxi, respectively.
Figure 3-4 Statistics on EIA approval new coal power projects in case provinces
Reference: [17]
.
4. Electricity demand outlook and low-carbon development targets during the
13th
FYP period
4.1 Electricity demand outlook
0
5
10
15
20
25
30
35
40
Xinjiang Shanxi Jiangsu Hebei Zhejiang
GW
approved, 2012-2014 approved, 2015 pre-approved, 2015 applied, 2015
19
Figure4- 1 Electricity demand growth in China, 2000-2014
Reference: [1, 2, 5, 6]
.
Since 2000, total electricity consumption has grown dramatically. By the end of 2014,
total consumption reached 5220 TWh [2]
, fourfold compared with 1330 TWh [6]
in 2000. As
indicated in Figure 4-1, the growth rate has gradually slowed down from the 10th FYP to the
12th FYP, and the electricity consumption elastic coefficient has gradually reduced from 1.36
to 0.88 [6]
. From the perspective of structural change, the share of primary industry
consumption fell; the share of secondary industry reached a peak of 75.25% in the 11th FYP
period and then gradually declined to 74.02% [1-6]
in the 12th FYP period, while the shares of
tertiary industry and household consumption went up.
4.1.1 Structural factors affecting electricity demand
Electricity demand during the 13th FYP period will likely be affected by many factors.
First, economic growth rates have switched from two-digit rapid growth rates in recent
decades to the new economic normal, which highlights restructuring, growth quality and
sustainability. A strong linkage has been demonstrated between electricity demand and
economic development. Hence, electricity demand will also likely slow to more moderate
speeds.
Second, in terms of industrial electricity consumption patterns, there will likely be little
change in the growth of primary industry and the share of primary industry in total industrial
electricity usage is generally small. Therefore, the impact of primary industry on total
13.24% 11.21% 7.09%
1.36
1.00
0.88
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
0%
20%
40%
60%
80%
100%
10th FYP 11th FYP 12th FYP (by 2014)
household tertiary industry
secondary industry primary industry
power demand growth rate electricity consumption elastic coefficient
20
electricity demand can be ignored. The traditional electricity-intensive sectors in the
secondary industry have been saturated in their market demand. Together with the
requirements for improving energy efficiency, electricity demand in these sectors will slow
down and even decrease. The strategic emerging industries will contribute most of the
electricity demand growth in the secondary industries. But, the electricity consumption
intensity of strategic emerging industries is much lower compared with traditional
electricity-intensive sectors. Meanwhile, the transformation of economic development toward
tertiary industry will also be accelerated in the future. Therefore, electricity demand growth in
secondary industry will likely decrease. Thus, tertiary industry will be the main force of
electricity demand growth. With the emerging of new service sectors, the popularization of
office automation and the electrification of the transportation sector (especially the
development of electric vehicles), tertiary industry will maintain strong growth in electricity
demand in the future [18]
.
Finally, regarding household electricity consumption, the increase in developed cities
like Beijing, Shanghai and Guangzhou will also likely slow and most future growth in
demand will come from the central and western regions. Besides, with the improvement of
living standards and rural infrastructure, household consumption will also play a strong
supporting role in electricity consumption growth for a long time [19]
.
4.1.2 Electricity demand projection
In this report, a consumption elastic coefficient is employed to project the growth of
electricity consumption during 2016-2020. As indicated in Figure 4-1, the elastic coefficient
of electricity consumption is continuously descending in China, which is consistent with the
experiences of other developed economies. In order to achieve the requirement of a well-off
society by 2020, which was proposed in the 18th CPC National Congress, the bottom line of
annual economic growth is 6.5% [20]
. Consensus on the prospective GDP growth during 13th
FYP is around 7% [21-22]
.
Based upon our analysis, we assume that electricity consumption elastic coefficient will
stay around 0.5-0.7 during 2016-2020 and thus use 0.6 [19]
in our recommended scenario.
Accordingly, we estimate that annual electricity demand growth will stay around 3.5%-4.9%
during the 13th FYP period and employ 4.2% as the recommended scenario.
4.2 The goal of non-fossil primary energy shares and low-carbon electricity
21
After 2013, capping primary energy consumption and excessive growth of coal
consumption in particular, and accelerating the development of non-fossil energy have
become the tone of national energy policy in China.
4.2.1 Power sector’s contribution to the 15% target
The National Plan on Climate Change (2014-2020) by NDRC clearly requires the power
sector to reach 15% non-fossil primary energy target and to cap primary energy consumption
at about 4800 Mtce [7]
by 2020. For the power sector, it is imperative to optimize the mix of
power generation. On one hand, it is important to cap coal use for power generation and
realize clean coal utilization. On the other hand, it is of vital importance to accelerate clean
energy deployment, especially wind and solar energy [23]
. Relevant national policy guidance
is as follows:
Develop clean and efficient coal power: Raise the proportion of coal efficiently used
for power generation; enhance the emissions standards of new coal units. The heat rate of
newly built coal-fired power generating units should be less than 300 grams of standard
coal/KWh while the pollutant emissions standard should be close to that of gas power [24]
.
Develop gas power: In Beijing-Tianjin-Hebei, Yangtze River delta, Pearl River delta,
and other key atmospheric pollution prevention and control areas, develop utility-scale simple
cycle gas power units orderly. Combined Cycle Gas Turbine (CCGT) Combined Heat and
Power (CHP) units and distributed gas units should also be deployed according to heating
load situations in these regions.
Develop nuclear power with safety as the top priority: Initiate new nuclear power
projects timely in coastal regions while taking strictest safety standards. Also conduct
research on the feasibility of building inland nuclear power projects. Combining technology
import and independent innovation, breakthrough should be realized in key technologies
including AP1000, CAP1400, HTGR, faster reactor and nuclear fuel reprocessing technology
[25].
Vigorously develop renewable energy: Attach equal importance to large-scale
development and distributed integration, and speed up the development of renewable energy
[26]. Advance the construction of large hydropower bases actively. Develop
medium-and-small size hydropower stations according to local conditions. Implement the
planning and construction of pumped storage power stations and strengthen the
comprehensive utilization of water resources. Plan and build nine large wind power bases and
22
the supporting power grids projects. Vigorously develop distributed wind power in south and
east China. Develop offshore wind power steadily. Advance the construction of PV power
bases and synchronize transmission channels construction with local integration. Speed up the
demonstration of distributed photovoltaic application. Deploy demonstration projects of solar
thermal power generation and enhance grid-integration service for solar power generation [25]
.
4.2.2 Officially declared clean energy development target by 2020
According to related policy documents, the state has already made clear targets on clean
power development:
Active and orderly development of hydropower: By 2020, the conventional
hydropower capacity will reach 350 GW and annual generation will reach 1200 TWh [7]
. Plan
and construct pumped storage power stations with scientific verification.
Safe and efficient development of nuclear power: By 2020, installed nuclear power
capacity will reach 58 GW, while the capacity under construction will reach more than 30
GW [25]
.
Rapid development of wind power: Speed up the construction of large-scale wind
power bases, build small-and-medium-sized projects and offshore projects according to local
conditions, and strengthen the construction of grid integration projects. By 2020, grid
connected wind power capacity will reach 200 GW, and wind power be competitive with coal
power in term of generation cost [25]
.
Acceleration of solar power: Develop centralized large-scale and distributed PV
projects simultaneously. Encourage the construction of distributed PV power generation in
large-scale public buildings, public facilities, industrial parks, etc. By 2020, installed PV
capacity will reach 100GW, and the price of PV generation should be equivalent with
electricity retail price [25]
.
Active development of geothermal, biomass and Ocean energy: Adhere to the policy
of overall planning, localization and diversified development. Actively promote the efficient
use of geothermal energy, biomass and ocean energy. By 2020, the supply of geothermal
energy will reach 50Mtce [25]
.
5. Coal power investment bubble during the 13th
FYP period
Based on the preceding forecast on electricity demand, as well as analysis on the
officially declared clean energy development targets, we can now quantify the development
space of coal power.
23
5.1 Coal power development space during the 13th
FYP period
Status analysis of
power sector
Electricity Demand
Economic
development
outlook
National
Regional
Provinces
Electricity
consumption
elastic
coefficient
Balanced coal
power capacity
Renewable
power
planning
Electric power
exchange
Figure5- 1 Logical framework of power planning
According to preceding analysis, the growth rate of total electricity demand would be no
higher than 2% in 2015 and about 4.2% during the 13th FYP period. By 2020, total electricity
consumption would reach around 6920 TWh. The development potential of coal power is
quantitatively analyzed under a demand scenario and with full consideration of clean energy
targets. Considering the integration of more renewable energy, we assume that the normal
utilization of coal power will be reduced to 4800 hrs4. Meanwhile, for our analysis, we
assume that all the other types of generation units remain at normal utilization. In this report,
the rational capacity of coal power is quantified based on the officially declared clean energy
and renewable power development targets by using a power planning model [27-28]
. Without
detailed load characteristic data, only electric power and energy balance is considered in
estimating coal power capacity. Hence, the quantitative results inevitably suffer from some
4 4. There was still a shortage of electricity in some parts of China in 2011. However, the shortage didn’t happen
in 2012 and 2013 when annual utilization hour of thermal units was about 5000hrs. Hence, we regard 5000hrs as
rational utilization hour of coal power at this stage. With substantial increase in wind power and PV capacity, the
utilization hour of coal power will drop due to assuming more flexibility service function. Since the planning also
requires stronger development of flexible power sources like pumped-storage and gas power, we only assume a
slight decline in the rational utilization hour of coal power.
24
estimate errors. Quantitative analysis (Table 5-1) shows that, during the 13th FYP period,
China’s balanced coal power capacity would be 910 GW, approximately 42GW of additional
capacity on the basis of estimated CFPP capacity by the end of 2015.
In a report released in March 2015 by CEC, the expected electricity demand is 7700
TWh, the total installed capacity is 1960 GW and the coal power capacity is 1100GW [2]
.
While the forecasts conducted by Wu Jingru are 7400 TWh, 2000 GW and 1040 GW [29]
,
respectively. Our estimated coal power capacity is significantly lower than these reports have
projected and the difference is mainly in demand projection and the guiding planning
principle.
Table5- 1 Generation capacity planning during the 13th
FYP period
Installed capacity (GW) Generation (TWh)
2015 2020 2015 2020
Hydropower 293 350 1025.5 1225
Pumped storage 23.35 70 18.7 56.
Coal 868 910 3906 4371
gas 61.7 100 185 300
Nuclear power 28.6 58 200.5 406
Wind 110 200 220 400
Solar 36.5 100 58.4 160
Biomass 11 14 46.2 58.8
Total 1432 1802 5641.6 6920.5
Based on regional power consumption growth during the 12th FYP period and national
electricity demand projection during the 13th FYP period, we can make predictions on
regional electricity consumption growth. Demand growth in the Northwest grid would be
significantly higher than the national average. The growth in the Southern China grid is
projected to be similar to the national average, while in the North China, East China and
central China grids, demand growth will be slightly lower than the national average. We also
expect that demand growth will be the slowest in the Northeast.
Table5- 2 Regional power demand growth forecast during the 13th
FYP period5
National
average
North China
Power Grid
East China
Power Grid
Central China
Power Grid
Northeast
Power Grid
Northwest
Power Grid
Southern
Power Grid
Demand
growth 4.2% 3.8% 3.8% 3.8% 2.4% 7.5% 4.3%
Based on clean power development status, regional power demand growth prospective
and the development of a trans-regional transmission network, we can make predictions on
5. According to regional electricity demand growth in the past 5 years, we decomposed the national electricity
demand during the 13th FYP into each regional power grid by also considering with the characteristics of regional
economic development.
25
regional power development. We find that North China and East China will have a large gap
that will need to be filled by import. Meanwhile, northwest, northeast and south grids will be
the main export regions. We then quantified the regional balanced coal power capacity in
2020 (Figure 5-2).
Figure5- 2 Balanced coal power capacity in six regional power grids, 2020
5.2 Sensitivity analysis of coal power development space
Change in electricity demand can have a huge impact on power planning. The hypothesis
of high growth (4.9%) corresponds to strengthening electricity substitution, i.e., promoting
the transition of energy consumption patterns through the implementation of electric boiler,
electric furnace, electric vehicles, etc. The full implementation of electricity substitution will
greatly accelerate the growth of power demand The main consideration under a low growth
scenario (3.5%) is the potential to strengthen energy efficiency and conserve electricity,
which could make demand growth at a relatively low level by implementing demand
management and developing energy efficient products. The moderate growth or the
recommended scenario is a proper balance considering economic restructuring, power
demand growth, electricity substitution and energy efficiency.
In addition, the 15%6 non-fossil primary energy target by 2020 will also require a faster
low-carbon transition in the power industry. According to the officially declared clean energy
target, non-fossil energy supply from the power sector, including hydropower, nuclear power,
wind power, solar power and biomass power generation, could contribute about 13.4% of
primary energy (4800 Mtce) by 2020. Therefore, to ensure full realization of 15% non-fossil
6. Besides power sector, other non-fossil energy utilization including geothermal energy, solar heat water, biogas
and biofuel can supply 50-80Mtce primary energy. Hence, 13.4%-14% by power sector can properly ensure the 15%
non-fossil primary energy target.
0.0
50.0
100.0
150.0
200.0
250.0
300.0
North China East ChinaCentral China Southern Nothwest Northeast
251.8
209.7
139.8 128.2
114.5
66.6
GW
26
fuel energy target, it is necessary to regulate the expansion and use of coal power.
With the planning model, sensitivity analysis is carried out by considering the fluctuation
ranges of electric power demand growth (3.5%-4.9%) and power sector’s contribution to 15%
non-fossil primary energy target (13.4%-14.0%). The results show that, under different
demand growth scenarios, China’s balanced coal power capacity could fluctuate around the
recommended capacity with a range of 50 GW. Different shares of non-fossil energy by the
power sector also affect the development space of coal power. In sum, we find that a 1%
increase in the power sector’s share will cut down the market space of coal power by 38 GW.
Under the recommended growth scenario, if the power sector contributes 14% of non-fossil
primary energy instead of 13.4%, the reasonable coal power usage should be lowered from
910 GW to 888 GW. Also, the planned capacity of wind and solar power (including
solar-thermal power) should be raised up to 230 GW from 200 GW and to 120 GW from 100
GW, respectively (equivalent to replacing 22 GW coal power). According to the latest media
report, the planning of PV could further be adjusted to 150 GW [30]
, replacing another 8 GW
coal power.
Figure5- 3 Sensitivity analysis on reasonable coal power capacity in China, 2020
In general, with the recommended annual power demand growth of 4.2% during the 13th FYP
period and annual operating hours of 4800 hrs, China’s balanced coal power capacity would
be around 910 GW by 2020. Because China has already committed to employ electricity
substitution as part of its national energy strategy, another 50 GW of coal power addition will
be necessary for implementing the strategy. Under such a situation, the capacity of coal power
will reach around 960 GW.
5.3 Quantification of Coal Investment Bubble during the 13th
FYP period
800
820
840
860
880
900
920
940
960
13.4% 14.0%
960
937
910
888
863
840
GW
non-fossil primary energy share by power sector, 2020
High-demand Medium-demand Low-demand
27
According to the most recently available data, as of September 2015, there are about 283
GW new coal power projects EIA (either approved or waiting to be approved [17]
) in China. If
all projects were successfully put into operation by 2020, the coal power capacity would reach
1151 GW, about 200 GW higher than the reasonable scale of 960 GW corresponding to high
demand scenario, under which active electricity substitution strategy is fully implemented.
Large-scale overcapacity would lead to huge investment waste and could further deteriorate
the operation efficiency of coal power and block the low-carbon transition of the power
sector.
The integration of more renewable energy into the power system requires more system
flexibility and reduces the operational efficiency of coal power to some degree. But of greater
concern is that the growth rate of coal power capacity exceeds the growth of electricity
demand. Approval of power projects are generally based on historical and present electricity
demand, while the construction period of coal power project is generally 3-4 years. A strong
implication here is that systematic and accurate prediction on future demand must be made in
advance. Additionally, an integrated power planning program should be enacted as well as an
early warning and regulation system be put in place to remedy the errors in prediction,
planning and its actual implementation. Only in this way, can the efficiency of power sector
investments be ensured with high confidence, while the installation of coal power capacity
and power demand growth can be properly coordinated.
In this report, we employ annual operation hours as an indicator for the utilization
efficiency of coal power. It is assumed that when the number is less than 4500 hrs utilization
rate will be too low to be acceptable [31]
. In other words, an investment bubble can be detected
when national average utilization of coal power is less than 4500 hrs.
5.3.1 National level analysis
Based on preceding analysis, the reasonable scale of coal power in 2020 would be
910-960 GW, about 42-92 GW over the 2015 base, under which the national average
utilization hour would move around 4800hrs and stay within reasonable level.
28
Figure 5-4 The influence of new capacity addition on annual operating hour during 13th
FYP period
(under recommended demand growth scenario)
As shown in Figure 5-4, by 2020, if coal capacity stayed in the 2015 level (868 GW)
utilization hour would increase to 5035 hrs. Although energy balance would not be a problem,
the power balance could be. The integration of more large-scale renewable energy could
endanger the stability of the power system without more flexible generation sources
(including coal power). In the case of more reasonable 4800 hrs, coal power would reach 910
GW by 2020. However, according to data of new projects under construction during
2012-2014, if all projects under construction were commissioned by 2020, total coal power
capacity would reach above 1030 GW and utilization hours could fall to 4243 hrs. If all EIA
approved (and to be approved) projects by September 2015 were put into operation, total coal
power capacity would reach 1150 GW and utilization hours would fall below 3791 hrs.
We then separate the influencing factors of coal utilization hour into two aspects, the
change in electricity demand and the growth of coal power capacity. As we can see from
Figure 5-5, both factors have significant impact, but unchecked capacity growth actually
contributes a larger share.
5035 4800
4243
3791
0
1000
2000
3000
4000
5000
6000
0 42 160 283
coa
l p
ow
er o
per
ati
ng
ho
urs
(h
ou
rs)
new coal power capacity, 2015-2020 (GW)
29
Figure 5-5 Factors contributing to decreasing coal power operating hour
5.3.2 Regional Analysis
By the end of 2013, China's thermal power reached 870 GW [6]
, among which most is
coal power except for a small share of gas turbines and biomass generators. Again, because of
data availability, we use thermal units in 2013 to approximate coal power units as the
beginning of analysis. We can differentiate three scenarios. The first one is an ideal state
under which utilization hours of coal power stay around 4800 hrs and a reasonable scale of
coal power is built by 2020. The second, or partly commissioned, includes a scenario where
only 160 GW projects under construction during 2012-2014 are put into operation while the
rest of the approved projects are not built by 2020. The third scenario represents on in which
all the projects submitted for EIA approval by September 2015 (283GW) will be put into
operation by 2020.
Table 5- 3 Regional coal power scenarios by 2020 Unit: MW
2013
2020
Ideal scale
2020
Partly
commissioned
2020
Fully
commissioned
Excess capacity
Partly
commissioned
Fully
commissioned
North China 246640 251840 265520 311840 13680 60010
East China 209320 209670 237490 254600 27820 44920
Central China 137400 139810 165620 187110 25810 47300
Northeast 66250 66560 74270 78420 7710 11860
Northwest 87790 114500 130230 155510 15730 41010
South China 122320 128180 156890 165510 28720 37340
Total 869720 910570 1030020 1152990 119450 242420
47.64% 52.36%
reducing electricity demand increasing coal power capacity
30
Figure 5-6 Operating hour of coal power units in six regional grids, 2020
From Table 5-5, under the recommended scenario of medium electricity demand growth
and with the existing scale of new coal power projects, there will likely be an excess capacity
of 119-242 GW in China by 2020. On a regional level, the degrees of overcapacity vary.
Under the partly commissioned situation, excess in East China, Central China and South
China grids will be above 25 GW. With fully commissioned, the excess scale in North China,
East China, Central China and Northwest will be more than 40 GW.
Utilization hours can directly reveal the impact of excess investment. As shown in
Figure 5-6, in a partly commissioned scenario, utilization hours of coal power in all six
regional grids is lower than 4600 hrs. In particular, in the Central China and South China
grids, the number is below 4000 hrs. Under fully commissioned situation, utilization hour will
further decrease to about 3900 hrs for North China and East China grids, 3700 hrs for South
China grids, and only 3534 hrs for Northwest Grid.
5.3.3 Typical provinces
These five case provinces represent three different scenarios in our study. Hebei and
Shanxi are provinces saturated by heavy industry while seeking transformation. Zhejiang and
Jiangsu are provinces with high electricity demand but unable to manage self-sufficiency.
Xinjiang is planning to export electric power on a large-scale. These five provinces also have
different prospective of electricity demand growth. With saturated heavy industry, Hebei and
Shanxi will likely experience lower than national average growth. Thus, new additions to
thermal power must been strictly balanced with demand growth, while taking electricity
substitution into full consideration. Since local economy and tertiary industry is already well
3000
3200
3400
3600
3800
4000
4200
4400
4600
4800
North
China
East
China
Central
China
Northeast Nothwest Southern
ho
urs
balanced scenario partly commissioned fully commissioned
31
developed, Zhejiang and Jiangsu may also have lower growth than the national average.
During the 13th FYP period, efforts should be put on alleviating the existing overcapacity
of coal power, integrating more renewables locally and receiving more imports. New
construction of coal power should be rigorously restricted. Xinjiang is less developed in the
manufacturing industry, but the “One Belt, One Road” initiative will boost its industry
development. So its power demand is expected to be much higher than the average. But the
growth potential of coal power there is uncertain and highly depends on the scale of electric
power exports during the 13th FYP period. According to available information, Xinjiang is
trying to realize economic growth by more power export and is making every effort to
construct more power transmission channels [32]
. However, in our opinion, for Xinjiang,
above all it is the outlook of electricity market and the stressful water resource supply
incurred by coal power development that must be carefully considered.
Similar to the national and regional analysis, in the power planning model we estimated
the reasonable scale of coal power in each of these provinces. Detailed projections on power
and energy exchange among provinces must be considered in the estimation process. Based
on regional market outlook, demand forecast of individual case provinces and analysis of
trans-provincial power exchange, we can estimate the reasonable coal power capacity for
these provinces by 2020 (table 5-6).
Table 5-6 Coal power capacity of 5 provinces, 2020 unit: MW
2013
2020
Ideal scale
2020
Partly
commissioned
2020
Fully
commissioned
Excess capacity
Partly
commissioned
Fully
commissioned
Hebei 41870 43870 45070 47300 1200 3430
Shanxi 52050 57190 57750 79060 560 21870
Zhejiang 49950 50530 52590 52830 2060 2300
Jiangsu 75550 78460 79300 88020 840 9560
Xinjiang 29390 48120 47110 63620 0 15500
In terms of the absolute scale of coal power excess, under the partly commissioned
scenario, with the exception of Xinjiang, the other case provinces will have overcapacity but
will likely have the excess under control. However, under the scenario that all the approved
units are commissioned by 2020 (except Zhejiang with low excess scale at 2.3GW) the other
case provinces will have much more capacity excess. This is especially serious for Shanxi
with over 21 GW excess and for Jiangsu and Xinjiang with about 10 GW and 15.5 GW
respectively.
As to the operation efficiency, under the partly commissioned scenario (except in
Xinjiang), operation hours of coal power units in other case provinces will be lower than the
32
optimal, at about 4600 hrs. Under a fully commissioned scenario, except in Zhejiang,
operating hour in other provinces could dramatically drop to less than 4500 hrs. The worst is
Shanxi, where coal power operating hours may lower to 3472 hrs; the next is Xinjiang where
the number would barely stay around 3600hrs (Figure 5-7).
Figure 5-7 Projection on the operation hours of coal power in case provinces, 2020
6. Conclusion
6.1 Research conclusions
In this report, we provide a brief analysis of the power sector during 12th FYP period,
with a particular focus on the utilization of thermal (coal power) fleets. Then the market space
for coal power units and the risk of excessive investment in coal power during the 13th FYP
period are also estimated. The findings are:
Under the new economic normal, electricity demand growth has reduced to more
moderate rates since 2014. However, because of the delay of planning implementation and the
lead time of new unit installation, the new addition of coal power units remained at a high
scale in 2014. According to our estimate, utilization hours of thermal units will drop to 4330
hrs and the overcapacity of coal power units will range between 80-100 GW at the end of
2015. The overcapacity risk in coal power industry deserves close attention from the
government and the industry.
Under the assumption of 4.2% in annual electricity demand growth during the 13th FYP
period and constrained by the 15% non-fossil energy target, the rational capacity of coal
power would be around 910 GW. Active implementation of electricity substitution will push
up the rational scale by 50 GW. If by 2020 the capacity of wind power and solar power was
3000
3200
3400
3600
3800
4000
4200
4400
4600
4800
5000
Hebei Shanxi Zhejiang Jiangsu Xinjiang
ho
urs
balanced scenario partly commissioned fully commissioned
33
increased to 230 GW and 120 GW respectively, the share of non-fossil energy supply in the
power sector would increase from 13.4% to 14%, equivalent to replacing 22 GW coal power.
If solar power capacity was increased to 150 GW, it would replace 8 GW more coal power.
There would be an excess of 70-120 GW if all the 160 GW [17]
coal power projects
approved during 2012-2014 were commissioned by 2020. With the normal decommission of
old units, such an excess may be partially resolved7. On the contrary, if all the coal power
projects submitted for EIA approval (283 GW) [17]
were put into operation by 2020 the excess
capacity would reach as high as 200 GW and be out of control. Such a large scale of
overcapacity will bring forth disastrous effects, costing as much as 700 billion CNY, which is
an investment that is unlikely to be recovered. The utilization hours of coal power units would
decrease to 3800 hrs and further constrain the economic performance of generators.
Unnecessary capacity installation of coal power would also inhibit renewable energy
deployment, leading to serious renewable energy curtailment. This crowding-out effect of
investment could also block China's strategic opportunity in deploying the low-carbon energy
transition.
For the case provinces, under the partly commissioned scenario, except for Xinjiang,
actual coal power capacity in Shanxi, Hebei, Jiangsu and Zhejiang may be in an acceptable
excess of 2-3 GW. However, under a fully commissioned scenario, actual capacity would be
substantially higher in all provinces (excluding Zhejiang). Shanxi would have the worst
impact with an excess of 21 GW, Xinjiang would experience an excess of 15.5 GW, and for
Jiangsu would have an excess of nearly 10 GW.
6.2 Policy recommendations
Strengthening consistent and coordinated power planning must be the top priority [33]
.
Overall power planning with smooth coordination between generation planning and grid
expansion, among different power sources [34]
, especially the matching of flexible resources
to adapt to renewable energy integration, and between national and local levels should be
formulated. After delegating the authority of project approval to provincial level, the
instructional functions of national planning must be emphasized. In other words, local
governments must approve new energy projects based upon the national power sector
planning formulated by the competent ministries (NEA and NDRC).
7. If employing the CEC statistical data (80GW), together with the 110GW approved projects (yet to be
constructed) since 2015, the sum is also consistent with the partly commissioned scenario in our report. In other
word, whether new coal power projects would be approved and whether all the approved projects would be
constructed, deserves careful attention from both central and provincial governments, in particular those with large
approved projects such as Xinjiang and Shanxi.
34
NEA and NDRC should coordinate and function effectively, including timely releases of
information and regulation. Power planning for the 13th FYP should be planned and released
to guide market investment with adequate and transparent information.
An early warning mechanism on coal power investment should be established. It is
strongly recommended that these competent authorities regularly publish an electricity market
prospective report, update the electricity demand outlook regularly and provide early warning
on potential coal power investment risk when detected.
35
AppendixⅠ: Transmission capacity of 27 UHV lines
NO. Route Type Origin Destination Provinces along
the route
Capacity
(MW)
1
North Shanxi-Nanjing in
Jiangsu ±800kV HV DC
transmission project
DC Shanxi Jiangsu
Shanxi, Hebei,
Shandong, Henan,
Anhui, Jiangsu
8000
2
Southeast Shanxi-
Nanyang-Jingmen 1000kV
UHV AC demonstration
project
AC
Hubei Shanxi, Henan,
Hubei 5000
3 Ximeng-Shandong 1000kV
UHV AC project AC
Inner
Mongoli
a
Shandong
Inner Mongolia,
Hebei, Tianjin,
Shandong
9000
4
Shanghai temple in Inner
Mongolia-
Shandong ±800kV HV DC
project
DC
Shandong
Inner Mongolia,
Shaanxi, Shanxi,
Hebei, Henan,
Shandong
10000
5 West Mongolia-South Tianjin
1000kV UHV AC project AC
Tianjin
Inner Mongolia,
Shanxi, Hebei,
Tianjin
6000
6 Ximeng-Taizhou in Jiangsu
±800kV HV DC project DC
Jiangsu
Inner Mongolia,
Hebei, Tianjin,
Shandong,
Jiangsu
10000
7 Ximeng-Nanjing 1000kV
UHV AC transmission project AC
Jiangsu
Inner Mongolia,
Hebei, Beijing,
Shandong,
Jiangsu
9400
8
North Zhejiang- Fuzhou
1000kV UHV AC
transmission project
AC Zhejian
g Fujian Zhejiang, Fujian 6800
9
Huainan-Nanjing-Shanghai
1000kV UHV AC project in
North-loop of East China
Power Grid
AC Anhui Shanghai Anhui, Jiangsu,
Shanghai 26000
10
The left bank of
Xiluodu-Jinhua in Zhejiang
±800kV HV DC project
DC Sichuan Zhejiang
Sichuan, Guizhou,
Hunan, Jiangxi,
Zhejiang
8600
11 Xiangjiaba-Shanghai ±800kV
HV DC transmission project DC
Shanghai
Sichuan,
Chongqing,
Hubei, Hunan,
Anhui, Zhejiang,
Jiangsu, Shanghai
6400
12 Jinpin-Sunan DC
Jiangsu Sichuan, Yunnan, 7200
36
±800kV HV DC
transmission project
Chongqing,
Hunan, Hubei,
Zhejiang, Anhui,
Jiangsu
13 Ya’an-Wuhan 1000kV UHV
AC project AC
Hubei
Sichuan,
Chongqing, Hubei 12000
14 Jinshang-Jian ±800Kv HV
DC project DC
Jiangxi
Sichuan,
Chongqing,
Guizhou, Hunan,
Jiangxi
10000
15
Yuheng in North
Shaanxi-Huaifang in
Shandong 1000kV UHV AC
transmission project
AC Shaanxi Shandong Shaanxi, Shanxi,
Hebei, Shandong -
16 North Shaanxi-Jiangxi ±
800kV HV line DC
Jiangxi
Shaanxi, Shanxi,
Henan, Hubei,
Anhui
-
17
Longbin-North Henan
1000kV UHV AC
transmission project
AC
Henan Shaanxi, Henan -
18 Jiuquan-Hunan ±800kV HV
DC transmission project DC Gansu Hunan
Gansu, Shaanxi,
Chongqing,
Hubei, Hunan
8000
19
Longdong-Jiangsu
±800kV HV DC delivery
project
DC
Jiangsu Gansu, Shaanxi,
Henan, Jiangsu 10000
20
Ningdong-Shaoxing
±800kV HV DC transmission
project
DC Ningxia Zhejiang
Ningxia, Shaanxi,
Shanxi, Henan,
Anhui, Zhejiang
8000
21 Zhundong-East China
±1100kV HV DC project DC Xinjiang Anhui
Xinjiang, Gansu,
Ningxia, Shaanxi,
Henan, Anhui
12000
22
Zhundong-Chengdu in
Sichuan ±1100kV HV DC
project
DC
Sichuan Xinjiang, Gansu,
Shaanxi, Sichuan 10450
23
South Hami-Zhengzhou ±
800kV HV DC transmission
project
DC
Henan
Xinjiang, Gansu,
Ningxia, Shaanxi,
Shanxi, Henan
15610
24
North Hami-Chongqing ±
800kV HV DC transmission
project
DC
Chongqing
Xinjiang, Gansu,
Sichuan,
Chongqing
8000
25
Chuxiong in Yunnan-
Huidong in Guangdong
±800kV HV DC transmission
DC Yunnan Guangdong Yunnan, Guangxi,
Guangdong 5000
37
project
26
Pu’er in Yunnan-
Jiangmen in Guangdong
±800kV HV DC transmission
project
DC
Guangdong Yunnan, Guangxi,
Guangdong 5000
27
Northwest Yunnan-
Guangdong ±800kV HV DC
transmission project
DC
Guangdong
Yunnan, Guizhou,
Guangxi,
Guangdong
5000
38
Appendix Ⅱ: New EIA approved coal power projects from 2012 to 2015
The project team adopts the coal power project database from Green peace, which
includes coal power projects approved by national and local environmental protection
departments since 2012 to September 2015.
Unit: MW
Total
2012-2014
approval
2015 application and approval
application Pre-approval approval Total
North China
Beijing 0 0 0 0 0 0
Tianjin 2000 2000 0 0 0 0
Hebei 5425 3200 0 50 2175 2225
Shandong 15229 4400 2024 4460 4345 10829
Shanxi 27010 5700 2640 700 17970 21310
Inner Mongolia 15540 3580 0 1400 10560 11960
Total 65204 18880 4664 6610 35050 46324
East China
Shanghai 0 0 0 0 0 0
Zhejiang 2877.5 2640 0 0 237.5 237.5
Jiangsu 12473.5 3750 1063.5 0 7660 8723.5
Anhui 19248 13140 700 1320 4088 6108
Fujian 10676.1 8640 0 2000 36.1 2036.1
Total 45275.1 28170 1763.5 3320 12021.6 17105.1
Central China
Hubei 7877 3100 0 105 4672 4777
Henan 11356 7320 0 2036 2000 4036
Hunan 3929 3920 0 0 9 9
Jiangxi 13345 6000 2000 0 5345 7345
Sichuan 6000 2000 0 0 4000 4000
Chongqing 7200 5880 0 0 1320 1320
Total 49707 28220 2000 2141 17346 21487
North-east
Liaoning 8244 5420 0 0 2824 2824
Jilin 1450 700 0 750 0 750
Heilongjiang 2475 1900 160 0 415 575
Total 12169 8020 160 750 3239 4149
North-west
Shanxi 14640 8700 0 0 5940 5940
Gansu 3420 3420 0 0 0 0
Qinghai 3320 1920 0 0 1400 1400
Ningxia 12112 10680 700 700 32 1432
Xinjiang 34232 17720 0 16512 0 16512
Total 67724 42440 700 17212 7372 25284
South China
Guangdong 20392 16492 0 0 3900 3900
Guangxi 6640 5920 0 0 720 720
Yunnan 600 600 0 0 0 0
Guizhou 14160 10860 660 0 2640 3300
Hainan 1400 700 0 0 700 700
Total 43192 34572 660 0 7960 8620
39
Total 283271.1 160302 9947.5 30033 82988.6 122969.1
40
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42
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