HIAS-E-46

GROWTH, UPGRADING AND EXCESS COST IN
CHINA’S ELECTRIC POWER SECTOR
Thomas G. Rawski
University of Pittsburgh
Hitotsubashi Institute for Advanced Study, Hitotsubashi University

July 2017

Hitotsubashi Institute for Advanced Study, Hitotsubashi University
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GROWTH, UPGRADING AND EXCESS COST IN CHINA’S ELECTRIC POWER SECTOR
Thomas G. Rawski
University of Pittsburgh and Hitotsubashi Institute for Advanced Study, Hitotsubashi University
tgrawski@pitt.edu

Abstract

China’s electricity industry has recorded immense achievements in many areas: growth, technicalupgrading and innovation, improved reliability, and universal service. This record of excellence coexists
with massive inefficiency. Despite China’s multiple cost advantages, the unit cost of producing,transmitting and delivering electricity is at least 30 percent higher in China than in the United States.
Latent potential for cost reduction clusters in coal-fired generation that supplies about two-thirds oftotal output. New reforms that deepen the influence of market forces will strengthen financial pressuresand thus increase the likelihood of achieving potential cost reductions, perhaps increasing the output
and share of coal-fired thermal plants.

Key words: China; electricity; reform; upgrading; coverage; cost; inefficiency
JEL Codes: L2, L6, O14, O25, O32

1
Submitted July 4, 2017. COMMENT INVITED.

GROWTH, UPGRADING AND EXCESS COST IN CHINA’S ELECTRIC POWER SECTOR1
Thomas G. Rawski
University of Pittsburgh and Hitotsubashi Institute for Advanced Study, Hitotsubashi University
tgrawski@pitt.edu 2

INTRODUCTION
Electricity is the ubiquitous facilitator of modern economic activity. While typically taken for
granted, the consequences of power outages quickly demonstrate that electricity truly is theindispensable resource.
This chapter reviews the recent trajectory of China’s power sector, which has delivered an
impressive combination of growth, technological upgrading, network expansion and improved
reliability during the past several decades. These advances come at high cost. Chinese and U.S.
electricity prices are similar; Chinese power providers enjoy multiple cost advantages over U.S.
electric utilities, but achieve consistently weaker financial results. This combination of prices
and financial results implies that the average cost of producing and delivering each unit ofelectricity is higher in China than in the United States.
This surprising outcome signals the presence of substantial inefficiency. Our review of thedecade 2005-2015 identifies 30 percent as a lower bound for excess costs within China’s
electricity system. We conclude with a survey of recent reform initiatives, which fix prices fortransmission and delivery of electricity, expand the scope for direct contracting between
generating companies and end-users and introduce competition into retail electricity sales.

1This paper was completed during the author’s tenure as a visiting scholar at the Hitotsubashi Institute forAdvanced Study, Hitotsubashi University. It is part of a project on “Policy, Regulation and Innovation in Chinese
Industry.” Reference to companion chapters indicates work by other project participants. This research builds on
generous financial support from the Hitotsubashi Institute, the Smith Richardson Foundation and the University ofPittsburgh’s China Studies and Global Studies programs.
2

Many people have assisted my efforts to understand this complex industry. Particular thanks go to Midhu
Balasubramanian, Loren Brandt, Michael Davidson, Marco diCapua, FENG Fei, Lee Hwa Gebert, GU Xiaoyun, Dan
Guttman, John Hanson, Carsten Holz, Fritz Kahrl, Nicholas Lardy, Lotus Liu, LIU Pei, LIU Qilin, Ravi Madhavan, Tom
Nguyen, Gregory Reed, Ryan Rutkowski, Yang Song, Richard P. Suttmeier, TIAN Qingfeng, Tianni Wang, Ivy Wong,
Tim Wright, Harry X. Wu, Irene Wu, Haihui Zhang, ZHANG Peili, ZHANG Wenkui, Haihui Zhang, ZHENG Xinye,
Xiuying Zou and dozens of patient Chinese informants. Seminar participants at Renmin University, at the Shanghai
campus of New York University, and at the Hitotsubashi University Institute of Economic Research provided
stimulating comments. Responsibility for errors rests with the author.

2

These changes have begun to exert downward pressure on electricity prices. Falling prices will
force producers to explore the potential for cost reductions. Prospects of lower costs seemconcentrated in the generation and delivery of coal-fired thermal electricity. The likely
outcome is an unexpected and unwelcome increase in the volume and share of coal-based
electricity production.
We begin with a brief summary of features that distinguish electricity from other widely-utilized
products.
Electric power is a network industry with considerable scale economies and huge fixed costs.
The network element means that costs shrink and benefits multiply when the number ofinterconnected users expands. In China, as elsewhere, the electricity sector originated withisolated power plants, each connected to multiple customers. By the 1930s, the need to ensure
timely and sufficient power supplies encouraged Japanese-controlled generating firms in
China’s northeast (but apparently not in Shanghai) to establish rudimentary arrangements thatunified the characteristics of power from multiple generating facilities and enabled big
industrial users to absorb electricity from multiple sources (Manshū kaihatsu 1964, 2: 536-539).
Networking is synonymous with scale economies, meaning that unit costs decline as thenumber of participants and the volume of power flow expands. The production processcontributes further scale economies: the standard size of generation plants continues to rise:
the share of thermal generation capacity rated at 300 MW and up rose from 17 percent in 1990
to 39 and then to 79 percent in 2000 and 2015 (Energy Report 1997, p. 58 and Table 2).
Technical factors complicate electricity markets. On the supply side, fixed costs are high,meaning that power companies incur substantial expenses regardless of sales volume. Large
differences in operational flexibility as well as the split between fixed and variable cost acrossvarious power generating technologies – coal, hydro, natural gas, nuclear, wind, solar –complicate efforts to achieve high levels of operational efficiency.
The unusual combination of long lead times for expansion of generation and distribution
facilities with the need for instantaneous supply response – customers expect power to flow at
the flip of a switch – and wide variations in power demand according to time of day, season andeconomic conditions creates a potential for mismatch between shifting user requirements andavailable production capabilities.
Avoiding such mismatches, which can cause temporary blackouts or more serious system
disruptions, requires continuous oversight to ensure smooth matching of supply and demandthroughout the power grid. “Dispatch” – assigning delivery quotas to individual power plants –is a key element of system operation.
These complexities lead to universal problems of governance and management. Historically,
policy-makers viewed electricity as a “natural monopoly.” Customers typically had no choice of
supplier, but were protected from overcharging either by public ownership or by regulatory

3bodies that controlled pricing and limited private utility companies’ charges to levels consistent
with “reasonable” profits.
During the 1990s reformers, arguing that monopoly and regulation concealed vast excess costs,
initiated an agenda of “unbundling” – forcing vertically integrated utilities to divest somesegments of their businesses in order to expand commercial rivalry and consumer choice. The
reform agenda aimed to inject elements of market pricing in place of governmental pricesetting wherever feasible. Implementation of reforms began in the United Kingdom andgradually spread across the globe.
Several decades later, results remain limited. Unusual features of the electricity industry,
especially the combination of extreme reliability requirements, lack of viable means to store
surplus power and absence of effective rationing mechanisms to resolve episodes of excess
demand, make it difficult to implement economists’ standard recommendation of “marginal
cost pricing” that equates retail price with the cost of producing the final unit purchased. As inother capital-intensive sectors, there is an unavoidable tension between marginal cost pricing
and the need to provide incentives for new investment.
Efforts to use auctions as a means for steering production quotas toward low-cost suppliers
have stumbled into frightening episodes of instability in which temporary power shortages
trigger price spikes that threaten to bankrupt suppliers or to inflate retail power prices. Thereis some evidence that clever participants can “game the system” and reap windfall profits fromactions that magnify or even initiate such episodes.
As a result, there is no consensus on how best to organize, administer and govern the
production and distribution of electricity. The current U.S. structure combining elements ofregulated (via officially-imposed price controls) and deregulated (without price controls)
electricity markets reflects this state of affairs. China’s circumstances display similar ambiguity:
despite the substantial impact of past and recent reform initiatives, the architecture of a fullyreformed electricity sector remains unclear, as does the nature of concrete steps that could
advantageously restructure this large and important industry.

CHINA’S ELECTRICITY INDUSTRY
Basic Elements of Industry Structure
Following several decades of rapid growth, China’s electricity sector is now the world’s largest.
Notwithstanding rapid expansion of renewable technologies, especially wind farms (Mathews
and Tan 2014), coal continues to dominate, with thermal (90 percent coal-fired) facilities
accounting for 73.1 percent of 2015 production and 65.7 percent of generating capacity at yearend 2015 (Electricity Operations 2014; China Electricity Council 2016).

4

Industry is the largest electricity user, absorbing 71.6 percent of 2015 supply (Table 8).
Household consumption occupies a far smaller share of power consumption than in the U.S.
(13.2 percent in China vs. 36.2 percent in the U.S. in 2015), but continues to expand at doubledigit rates, and thus seems likely to claim a rising share of China’s future electricity supply.3
Geographic imbalance is a central feature of China’s energy economy. Map 1 shows that
resources are concentrated in a wide arc stretching from Heilongjiang (oil) in the northeast
through Inner Mongolia (coal, wind) and Shanxi (coal) in the north, Shaanxi (coal), Gansu (wind)
and Xinjiang (coal, wind, sun) in the northwest and Sichuan, Chongqing, Guizhou and Yunnan(hydropower) in the southwest, while demand clusters in a diametrically opposed arc runningsouthward along the coast from the Beijing metropolitan area through Shandong, Jiangsu,
Shanghai, Zhejiang and Guangdong. Feeding the energy demand of this coastal belt requires
some combination of large-scale domestic energy transport and cross-regional powertransmission. In the absence of international trade in electricity or large-scale local power
production from nuclear plants or offshore wind farms, massive long-distance shipments offuel, principally coal, or of electricity itself must figure prominently in China’s power system.
Recent economic expansion in central provinces like Hubei, Hunan and Jiangxi has created newgaps between energy demand and local supply that intensify the pressure to build nuclear
plants or expand long-distance shipments of coal or power (Jiang 2014; Zhu 2016).
Map 1 about here
The institutional evolution of China’s power sector is well-understood (Xu 2002, 2004). In the
pre-reform planned economy, electricity was a state-run monopoly under the Ministry ofElectric Power. Once reform policies implemented from the late 1970s began to accelerate
overall economic growth, and hence the growth of demand for electricity, severe shortages ofelectricity created a powerful incentive for reform.4
Early reform initiatives focused on decentralization: provincial and local governments werepermitted to organize, manage and finance (sometimes with foreign investments) new power
plants, actions formerly reserved for the center. This accelerated the growth of production
capacity, especially in regions that had suffered the biggest supply gaps. There were significant
unintended results: a proliferation of small, high-cost producers as well as the emergence of
substantial de facto provincial and local control over power supplies, developments that
increased the potential for local authorities to oppose, obstruct or simply ignore unwelcome
instructions from Beijing.

3

Chinese data from China Electricity Council 2016 and Table 8 below; U.S. data fromhttp://www.eia.gov/consumption/, accessed April 2, 2016.
4

The author recalls touring factories by flashlight during the summer of 1982; one manufacturer of cashmere
garments reported large losses from the destruction of yarn stranded in dyeing vats during repeated episodes of
unexpected power outages.

5

Next came a 1998 initiative aimed at commercializing the power sector by transforming the
Ministry of Electric Power into the State Power Corporation. Subsequent reforms,
implemented in 2002, involved “unbundling” the formerly integrated electricity sector to rollback vertical integration, expand competition, and establish a clear demarcation between
commercial enterprises and the state.
The new structure eliminated the State Power Corporation, transferring its regulatory authority
to a new body, the State Electricity Regulatory Commission (SERC) and assigning its generationand grid equipment to newly created companies. Massive resources were poured into fivehuge generating companies, while two immense grid management firms were assigned totransmit and distribute electricity. These five generating firms, which now produce nearly halfof China’s electricity, own and operate power plants on a nationwide scale, ensuring somedegree of commercial rivalry. Map 2 shows the territories served by the two main grid firms:
China Southern Grid, which spans five provinces in the south and southwest, and the muchlarger State Grid Corporation, which manages power networks elsewhere. The two do notcompete directly, but create the potential for performance comparison.5
Map 2 about here
Further reform plans produced extensive discussion, but, until recently, little action. Reformstalled through a combination of institutional resistance to unbundling, transparency, andmarketization, priority for eliminating chronic power shortages, and difficulties revealed inexperimental reform pilots.
The resulting system combines elements of plan and market. Substantial competition (as well
as lobbying) surrounds the construction and equipping of new generation facilities, typicallyinvolving rivalry among giant state-controlled generation, construction and machine-building
enterprises. Generating companies face single buyers – all power goes to the local gridcompany, which acts as a monopoly seller of electricity in its service territory, a circumstancethat recent reforms, discussed below, have begun to change.
Three prices dominate the finances of these firms: the wholesale or “on-grid” tariff thatgenerating firms receive from the grid, the retail price that the grid charges to end-users, andthe price of coal, the main component of variable cost for China’s predominantly coal-fired
power producers. Table 1 lays out the trajectory of these prices since 2003.
Table 1 about here
Two of these prices, the on-grid and retail tariffs, are controlled by the National Development
and Reform Commission (NDRC), which sets basic tariffs. These vary according to power source(low on-grid tariffs for hydropower and for western thermal plants, higher feed-in tariffs forthermal plants in coastal regions and for nuclear, wind and solar power) and user (low retail5

Smaller grid companies manage power networks in western Inner Mongolia and parts of Shaanxi.

6

prices for households and for agriculture, higher prices for industry and commerce). A blizzardof taxes, fees and subsidies, many imposed by provincial and local governments, surrounds
these reference prices, resulting in a labyrinth of charges – more than 300 in Beijing alone (Huo
2013).
Table 1 includes two coal price indexes: a domestic series that tracks mine-mouth prices and amore volatile indicator reflecting Asian regional coal prices. Gradual domestic marketizationand growing Chinese participation in global coal markets makes the latter index increasingly
relevant to the finances of Chinese power producers; the domestic index clearly understates
the volatility of coal costs during the past decade.
This combination of official price regulation, with its slow and politically charged adjustments,
and an increasingly volatile coal market has created a financial roller coaster for China’s power
sector. Coal price spikes in 2008 and 2011 pushed up generation costs, whereupon inflexible
on-grid tariffs splashed red ink over large segments of the power generating sector. Falling coalprices have the opposite effect. A mechanism linking coal costs and power prices, adopted in
2004, has worked poorly, as NDRC officials have blocked prompt implementation of supposedly
automatic price changes for electricity in the wake of coal price fluctuations (Huang and Yu
2014; Bie 2014).
Prior to the latest reforms, grid company revenues came from the spread between the on-gridtariffs paid to generation companies and the retail prices collected from end-users (Table 1).
Until recently, the grid companies’ refusal to provide detailed cost information – State Gridfamously classified up to 31 percent of its costs under the opaque heading “other” (其他 qita) prevented regulators from calibrating grid charges to actual costs (Power Prices 2014; Yu 2014).
Financial volatility originating in the coal market has also affected the grid companies. In 2009,
for example, NDRC raised on-grid tariffs to give generation companies some relief from higher
coal prices, while imposing a slight reduction in average retail prices (Table 1). This resulted in
an unexpected drop in the grid companies’ price-cost differential that eliminated profits until
compensating adjustments in the following year sharply increased grid company margins.
Table 1 uses standard currency exchange rates to convert average Chinese retail prices, as wellas the prices charged to “large industrial users” (大工业) into U.S. dollars. The comparison
shows that the average price of electricity in China has risen in recent years to matchcomparable U.S. figures. For large industrial users, average Chinese retail tariffs consistently
exceed U.S. industrial electricity prices, with Chinese costs outrunning corresponding U.S. prices
by 50 percent or more beginning in 2011. This observation contradicts claims, for example by
Haley and Haley (2013), that Chinese manufacturers enjoy cheap electricity supplies; while
regional and local governments may lower prices for favored sectors, Table 1 shows that power
prices charged to industrial users are consistently higher in China than in the U.S.

7

The run-up to the 13th Five Year Plan (2016-2020) brought a push to revive electricity reform,
partly to curb the power of the State Grid Corporation, which has strenuously resisted official
regulatory efforts,6 and particularly to implement the Xi Jinping administration’s mandate toelevate market forces to a “dominant role” in China’s mixed economy.
The new wave of reforms focuses on three issues, discussed further below: audits of gridcompany costs leading to imposition of fixed grid charges; expansion of direct powertransactions between end-users and generating companies, initially confined to large industrial
purchasers with the intention of full marketization within several years; and replacing theformer grid company monopoly of retail electricity sales with a competitive regime that willallow new entrants, including private operators, to establish retail sales companies.

DEVELOPMENT AND INNOVATION IN CHINA’S POWER SECTOR
GrowthThe central task for any electrical system is to supply customers with power on demand. With
overall economic growth approaching, and annual increments to power consumption often
exceeding 10 percent, fulfilling this basic function posed a huge challenge. Figure 1 illustrates
the protracted, and finally successful response that enabled power supply to catch up withdemand.
This supply surge pushed China past the United States as the world’s largest producer andconsumer of electricity, with 2016 power consumption reaching 151 percent of the comparable
U.S. figure. In 1990, China’s power use was a mere 22 percent of the U.S. total. Figure 1
demonstrates the magnitude of subsequent Chinese investment: beginning in 2005, annual
increments to generating capacity consistently exceeded 57 GW, the peak annual increment toU.S. capacity achieved in 2002. In 2010, and again in 2014-2016, new Chinese generating
capacity more than doubled the historic U.S. peak.7

6

Thus when the National Energy Administration, responding to complaints that large-scale spillage of wind power
was hampering efforts to raise the share of renewables in China’s electricity mix, “ordered grid companies ‘to plugin all renewable power sources‘,” State Grid’s leader promptly demurred, insisting that “‘the approval process forwind power and for the grid are different’” (Shepherd and Hornby 2016).
7

Chinese output and capacity data for 2015-2016 accessed March 22, 2017 fromhttp://www.cec.org.cn/guihuayutongji/tongjxinxi/niandushuju/2017-01-20/164007.html; Data for 2014
are from China Electricity Council 2016. For earlier years, data on Chinese generation capacity is fromhttp://www.cec.org.cn/guihuayutongji/tongjxinxi/niandushuju/2015-11-30/146012.html , accessed December 19, 2015; annual dataon Chinese power consumption is from Fifty Years (2000, p. 279), Energy Statistics (1997-99, p. 143; 2006, pp. 110111; 2011, pp. 124-125; 2015, pp. 122-123), and from Yearbook 2016, Table 9-6. U.S. electricity output fromvarious issues of U.S. EIA Monthly, Table 7.1; U.S. electric power industry generating capacity from U.S. EIA 2015b.

8

Figure 1 about here
As the addition of new power plants and grid connections began to shrink the gap between
power demand and available supply, China’s grid operators implemented pre-announced
rotating power blackouts; this reduced the costs associated with power shortages.8 The initial
decade of the current century brought a general balance between demand and supply, despite
the persistence of regional and seasonal shortages (State Grid 2012, pp. 32, 157).9 Most
recently, continued investment together with an unexpected and steep fall-off in the growth ofelectricity demand have created a new problem: widespread excess capacity, which has sentutilization rates for generation facilities into a downward spiral: on average, thermal plants
operated for only 4165 hours during 2016, the lowest figure since 1964 ((Table 3).

Scale
Rather than replicating existing facilities, expansion of China’s power industry has pursued thescale economies characteristic of electricity generation and distribution by increasing the
average size of individual facilities.
Table 2 summarizes a massive shift toward large-scale thermal generation plants. Between
2000 and 2015, the number of generating stations with capacity of 600 MW and up rose from22 to 609, and their share in overall capacity jumped from 5 to 43 percent. Table 2 also tracks aparallel, but less rapid extension of the length and voltage of power transmission lines – anessential component of China’s energy economy due to rail system’s limited coal-carrying
capacity as well as growing dissatisfaction with the environmental costs of coal-burning
generation facilities in coastal cities.
Table 2 about here
This shift to larger facilities brings multiple benefits. Standard technical indicators increasingly
resemble outcomes observed in advanced market economics. Table 3 documents a steadydecline in coal consumption per KWh of electricity, which, thanks to large numbers of new

These comparisons ignore slight differences among different Chinese data sources and in the measures used totabulate U.S. and Chinese electricity output.
8

During the 1990s, the 15-storey office building of the Chinese Academy of Social Sciences in downtown Beijing
had a regular schedule of Friday power outages. In 2005, an invitation to visit a Beijing-area machine tool plantcame with the proviso that power shortages limited operating hours to midnight-6 am.
9Kahrl and Wang (2014) provide a detailed account of the “orderly electricity use” (有序用电) system developed
to cope with power shortages.

9plants, has fallen below the U.S. average.10 Similar conditions apply to the grid, which has
achieved a steady decline in transmission losses, which now approach the U.S. level of 5-6
percent.11 The share of power consumed within generating facilities has also declined.
Table 3 about here

Reliability and Access
Although 2009 data show that “the number of outage hours would need to be reduced by morethan half to reach current US average” levels (Kahrl et al 2011, p. 4036), more recent informationfrom the World Bank’s enterprise survey summarized in Table 4 demonstrates impressive levelsof reliability. Chinese respondents report fewer outages, and quicker response to requests for
new connections than informants in Brazil, India or the Russian Federation. The proportion ofChinese informants owning or sharing backup generators matches outcomes in Brazil andRussia and is far smaller than in India. Firms in Brazil, India and Russia are more than ten times
as likely to identify electricity as a “major constraint” than are Chinese enterprises.
Reliability is highest in major cities. A visitor to western Sichuan province, reported daily power
outages in May 2016 (personal communication).
Table 4 about here
China has reached a remarkable milestone by extending electricity to its entire rural populace.
The electrification of isolated communities in Qinghai province completed this task in 2015 (Jia
2015a; China Electricity Yearbook 2015, p. 68). China has attained universal access at a far
lower income level than in other large nations; in the U.S., the share of farm dwellings withelectricity surpassed 50 percent only in 1946 and reached 95 percent only in 1956 (Historical
Statistics 1975, series S, pp. 108-119).

Falling construction costs
Despite the considerable challenge of developing equipment and materials capable ofwithstanding the elevated temperatures and pressures associated with new generations of
power generating equipment, the accumulation of experience in equipment manufacture andplant construction resulted in the downward trend in the unit cost of new thermal power plants

10“In 2007 China’s average heat rate for coal-fired power plants was. . . roughly 5% higher than the U.S.
equivalent” indicating lower unit coal consumption (Williams and Kahrl 2008, p. 4). Average coal consumption in
Chinese thermal generating plants declined thereafter (Table 3).
11

See https://www.eia.gov/tools/faqs/faq.cfm?id=105&t=3.

10

shown in Figure 2. North America and Western Europe experienced the opposite – rising costsof building new thermal plants (Samaras et al 2011, p. 18).
The magnitude of Chinese cost reductions is surprising: between 1996 and 2004, investment
cost (gongcheng zaojia) per kilowatt of new thermal generating capacity declined by 38.4
percent while the overall investment cost index12 rose by 12 percent – a gap of 50 percentage
points! Comparing 1996 with 2012 shows an even larger gap of 77.3 percentage points
between (declining, then stable) power plant costs and the steadily rising investment costindex. Unit cost for thermal power plants declined slowly after 2012, while the overall
investment cost index continued to creep upward (China Electricity Report 2014, pp. 55-56;
2015, pp. 49-50; Abstract 2016, p. 57).
Figure 2 about here
The contrasting trends between unit cost of new thermal plants and the overall investment costindex indicates a remarkable combination of productivity gains and cost controls in building andequipping thermal power plants. This episode recalls a 1940s phenomenon in which
unexpectedly rapid productivity gains accompanied steep wartime increases in U.S. productionof cargo vessels known as “Liberty ships” (Thornton and Thompson 2001; Thompson 2001).

Technological catch-up and innovation
Successive international comparisons highlight the extent of technical progress in China’s
power sector. In 1990, the efficiency of coal-fired power generation in China, Korea and India
lagged far behind results for the U.S. and Western Europe. By 2011, China and Korea had
closed this gap, nearly matching the U.S. figure, while thermal efficiency in India’s coal-fired
plants showed little change from the 1990 level (Hussy et al 2014, p. 66).
As the scale of expansion in China’s power sector created what quickly emerged as the world’s
biggest market for power plant equipment, major producers from Europe, North America andJapan rushed to seize this new opportunity. As in other sectors, Chinese officials adroitly
deployed market size as a bargaining tool, steering international firms into joint ventures andtechnology licensing agreements that enabled domestic firms, most notably China’s big three
power equipment makers - Dongfang Electric, Harbin Electric and Shanghai Electric - to accessadvanced technology.
Although we cannot gauge the relative importance of various sources of knowledge andinformation, Chinese equipment-makers clearly benefited from expanded interaction withforeign partners, accelerating efforts to increase the scale of their equipment, while
12

Investment cost index from http://data.stats.gov.cn/workspace/index?m=hgnd, accessed December 4, 2014;
unit cost data from author’s file “Thermal power construction costs.042316.”

11

simultaneously introducing new generations of thermal technology – first “super-critical” andthen “ultra-supercritical” - that employ elevated temperature and pressure in the combustion
chamber to reduce fuel requirements and boost thermal efficiency.
Chinese policymakers place heavy emphasis on import substitution, especially in sectors likeelectricity that officials view as central components of national economic growth. With
domestic firms supplanting overseas equipment suppliers, rapid upgrading – not just forthermal generation, but, as is evident from subsequent chapters, in multiple segments of thepower sector, reflects advances on the part of equipment producers as well as among power
generating and grid companies.
China’s success in “breaking into the top ranks of global power-equipment exporters,” together
with growing overseas marketing of grid management services, and, most recently, of nuclear
power expertise (see the chapter by Madhavan, Rawski and Tian), underlines the rapidity andextent of China’s catch-up in the electrical sector. While ”Chinese equipment makers facequestions about quality control on their power turbines. . . . multinational companies that once
cooperated with Chinese business groups now face them as competitors” (Areddy and Glader2010). Similar comments apply to leading multinational suppliers of equipment for electricgrids, hydroelectric facilities, wind turbines, solar assemblies and nuclear power plants.
Along with diminishing industry-wide technological and quality gaps, China’s power sector has
begun to approach the global technology frontier in specific areas, of which long-distancetransmission of ultra-high voltage AC current provides a leading example. The chapter by Yichong Xu attributes China’s advance in this area to an entrepreneurial campaign by leaders ofState Grid Corporation, the world’s largest utility company. While some commentators
question the economics of long distance AC power transmission and other State Grid
innovations, Chinese grid facilities now use domestically manufactured equipment to movelarger volumes of electricity over longer distances and at higher voltage than in Europe or North
America.
Evidence of innovative effort is readily visible in Chinese factories and trade journals. A cuttingedge coal-fired generation plant in Shanghai reports unit coal consumption of 276 grams per
KWh; combined with low effluent levels, the result is “far superior to the original design. . .
creating the world’s best level” (Jia 2014a). The chapter by Madhavan, Rawski and Tian showsthat Chinese researchers are investigating novel approaches to nuclear power generation.
Shanghai Electric is experimenting with elongated rotors that could increase the efficiency of
steam turbines (Interview, May 28, 2014). Alloy U-tubes tubes from Baoyin Special Steel Tube
Co. used in nuclear plants’ steam generators reportedly deliver superior resistance to pitting
while matching other characteristics of imported alternatives (Baiyin 2014).

Growing Environmental Concerns

12

Despite reductions in unit coal consumption (Table 3), expansion of power output andcontinued dominance of thermal generation place electricity generation among the leading
contributors to urban air pollution. Data for 2013 show thermal power plants accounting forover one-third of China’s total emissions of SO2, 17 percent of soot and dust, and over half ofnitrous oxides (Li 2016). The combined impact of industrial emissions (with power plants
contributing a considerable share) and exhaust from China’s rapidly expanding fleet of motor
vehicles has reversed two decades of gradual improvement (Rawski 2009) in urban air quality.
Protracted episodes of haze and smog have aroused public indignation and turned urban air
quality into a major political issue.
The official response has powerfully influenced the electricity sector:
 Rapid expansion of renewables, especially wind power, has raised the combined shareof hydro (19.8 percent), wind (3.3), nuclear (2.9) and solar (1.2) in 2015 electricity
output to 27.2 percent (Mathews 2016). Although the size of China’s power industry
limits the pace of structural change – the share of thermal facilities in overall generating
capacity declined from 73.4 to 65.7 percent between 2010 and 2015 (China Electricity
Council 2016), the impact of renewables and nuclear power is visible at the margin,
where, as Mathews and Tan (2014) emphasize, the “leading edge” of both capacity andoutput growth is “demonstrably getting greener.” Efforts to move dispatch toward prioritizing supply quota allocations for “clean” energy
providers.
 Choice of technologies. Beijing has banned construction of new coal-fired generation
plants in leading cities and, in some instances, required the conversion of coal-fired
plants to natural gas. A nationwide campaign has sought to close small generating
plants employing technologies now regarded as obsolete; modest results are visible in
Table 2.
 Retrofitting. New policies require new coal-burning plants and incentivize older facilities
to install modifications to increase combustion efficiency and/or remove harmful
effluents from smokestack emissions, often with partial compensation in the form of
supplements to on-grid tariffs.13 Regulators have ramped up enforcement, imposing
fines on violators (Jia 2014c).

13

In December 2015, for example, NDRC joined with the Ministry of Environmental Protection and the National
Energy Bureau to announce a program that awards price top-ups to coal-fired generation plants that meet “ultralow” emission guidelines. See NDRC 2015; reference courtesy of Fredrich Kahrl.

13 Subsidy elimination. Further policy initiatives have required provincial and local
governments to eliminate power price discounts that had encouraged the expansion ofenergy-intensive industries like aluminum, steel, cement and heavy chemicals.14
 Penalty pricing. NDRC has added surcharges to electricity prices charged to energyintensive industries, particularly when firms are judged to be employing obsolete
technologies. In some cases, provincial governments are authorized to increase theselevies.
 Long-distance transmission. Planners appear to be considering proposals that would
increase the transmission of electricity from coal-rich provinces like Shanxi and Xinjiang
to power-hungry coastal regions. This could be accomplished by building conventional
coal-fired generation facilities or by converting solid coal into coal gas, which could
serve as fuel for power generation. Such proposals seem problematic because they
relocate rather than reduce effluents and also because the associated waterrequirements would strain the capacity of water-scarce mining regions. Use of aircooled generation technology economizes on water, but reduces thermal efficiency,
which raises coal consumption and unwanted emissions (Jia 2014b).
Globalization
Following an initial period in which the electric power sector’s global involvement focused on
equipment imports and absorption of overseas technology, China’s electricity sector has
emerged as a growing force in global markets for electrical equipment, project management
and the construction and operation of generation facilities and electrical grids.
 Hydropower. Sinohydro Corporation is “the world’s largest hydropower construction
company with a 50% share of the international hydropower market”(http://www.internationalrivers.org/campaigns/sinohydro-corporation).

 State Grid Corporation, the world’s largest utility company, has substantial overseas
investments in power generation and grid construction and management (Xu 2016).

14

Provincial and municipal power tariffs issued between 1980 and 2009 in Gansu and Lanzhou, for example,
included concessional rates for electric furnace production of iron alloys and other enumerated industrial activities(Lanzhou 2011, pp. 265-282).

14

 China’s Big 3 equipment makers are major sellers of thermal power equipment, with a
combined 2013 global market share slightly trailing Alstom, the third-ranking firm(behind General Electric and Siemens) (Dash 2014).
 Slowing domestic demand growth has encouraged generation and construction firms toseek international contracts (Li 2015; Chen 2016).
 China’s nuclear industry has recorded major progress in raising its global profile, withrecent agreements and contracts in Argentina, Romania, Pakistan and the United
Kingdom (see the chapter by Madhavan, Rawski and Tian).
Overseas activity is mostly, but not entirely in low- and middle-income countries: State Grid has
invested in Australia, Portugal, Italy and Greece, while leading nuclear firms have joined aconsortium undertake the United Kingdom’s Hinkley nuclear project.
The motivation for overseas involvement combines standard trade drivers – Chinese firms offer
an attractive price-quality combination – and special circumstances, including growing excess
capacity and the obligation for big electricity firms, as centrally-directed State-controlled
enterprises, to join the government’s “Go Outward” and “One Belt One Road” campaigns.

This survey highlights China’s electricity sector as the locus of dramatic achievement during thepast several decades. Electricity producers and grid companies have increased supply,
overcome massive power shortages, built a nationwide service network, improved reliability,
absorbed new generations of technologies, and approached – in some cases, perhaps reached global technology frontiers. These advances have transformed China’s electrical industry froma weak laggard into a major force in global markets for equipment, construction, design andgrid management services.
Despite these substantial and impressive accomplishments, discussions of China’s electricity
system bristle with strongly negative evaluations. Thus “China’s electricity sector continues todemonstrate a number of fundamental shortcomings in its basic institutions and functions”
which lead to “intractable implementation problem[s]” (Williams and Kahrl 2008, p. 12).

SHORTCOMINGS AND DEFICIENCIES IN CHINA’S ELECTRIC POWER SECTOR
What are these “fundamental shortcomings”? How do they lead to “intractable problems”? It
is immediately evident that some difficulties reflect circumstances that extend far beyond theelectric power industry: thus knowledgeable observers comment that “Many of the obstacles toelectricity reform in China lie outside the electricity sector” (Kahrl et al 2011, p. 4033).

15

Overview
Although electricity markets in many countries display uncomfortable compromises between
state control and market allocation, the imprint of the former plan system is particularly strong
in China’s power sector even after several decades of market-leaning reform. Documents andreports highlight details about physical quantities – of power production and consumption, coaluse, equipment stocks, operating hours, and so on. Aside from information about investment
spending, systematic compilations regarding prices, revenues, costs, and profits – the lifebloodof any market system – remain scarce. Rigid prices largely divorced from market pressures –another legacy of the plan era – may partly explain the tendency of official sources to omit
information about values.
Preoccupation with investment reflects an emphasis on scale, a Stalinist legacy that permeates
Chinese policy-making and is particularly prominent in the power sector. Even if expectedfinancial returns are scant, investment projects that establish specific firms or industries as“key” or “backbone” elements in their local or sectoral environments may achieve handsome
payoffs in the form of favorable policy treatment. The emergence of massive excess capacity
beginning in 2014 did not induce a major pullback in investment spending that one would
anticipate in a market system; instead, investment spending rolls on as firms “intensify
investment to stake claims” (“跑马圈地”愈演愈烈投资 paoma qiandi yuyanyulie touzi) to
capture market share in anticipation of the favorable policy treatment routinely awarded toscale (Wang and Yu 2016; Jiao 2016).
Vertical integration and self-reliance represent further plan legacies that figure prominently intoday’s electricity system. While specialization intended to develop firms’ “core capabilities” isa central principle of the unbundling component of sectoral reforms in China and elsewhere,
the desire to avoid dependence on outsiders, to limit negative consequences of unexpected
price changes, and to create opportunities for resource extraction via opaque transactions
among related parties motivates power generating companies to acquire coal mines,
encourages grid companies and coal mines to invest in generating capacity, and inspires bothgenerating and grid firms to acquire captive equipment producers.
Local and provincial governments, the subject of Margaret Pearson’s chapter in this volume,
pursue their own version of vertical integration through actions that reveal their preference forsupplying their jurisdictions with locally-generated power and, especially under the shadow ofpossible electricity shortages, avoiding commitments to transfer electricity to otherjurisdictions.
These tendencies have major consequences. Table 3 reveals the surprisingly small scale ofpower transfers across provincial boundaries and especially between China’s seven multiprovince electric power districts. Under the heading of “current problems facing the power

16

industry’s development,” a 2001 report notes tartly that “the inter-provincial market is closed”(China Electricity Yearbook 2001, p. 16). Recent discussions confirm the persistence of obstacles
to interregional power sales. A 2015 analysis suggested “allowing cross regional transactions
and creating a nationwide power market" (Fan 2015). Numerous references to “barriers” (壁垒bilei) hampering power sales across jurisdictions indicate that this issue remains unresolved (Lu2017, Wang 2017).
Given the geographic gap between energy supply and demand, limited interregional power
flow translates into larger shipments of coal and therefore greater concentration of air quality
problems in coastal urban centers of electricity demand.
Within the sphere of official management, we encounter similarly uncomfortablearrangements, with central and local authorities jousting for control. Provincial and local taxes,
fees and subsidies modify on-grid tariffs and retail prices set by NDRC, often with Beijing’s
assent, but sometimes in direct contradiction of central government preferences. Long lists ofprojects built without official authorization, invariably with the connivance of local leaders,testify to persistent incentive conflicts between different levels of China’s complex
administrative hierarchy (Cheng and Tsai 2009). In one particularly egregious episode, theNeimenggu provincial government concealed the construction of major power facilities, only to
be caught out following a fatal construction accident; local authorities allowed work tocontinue “even after it was labeled illegal by central authorities” (Officials Penalized 2006;
Oster 2006). Flouting of regulations may extend to the nuclear sector: 2016 draft regulations“clarify penalties for unauthorized construction or operation” of nuclear plants (NPP Siting2016).
While the boundaries between plan and market and between central and local control remain
unsettled, reform has injected intense focus on financial outcomes into every segment of theelectric power system. China’s system of dispatch illustrates how the resulting combination of
profit seeking with ill-defined regulatory jurisdictions, conflicting governmental incentives15 andsticky prices16 ensures the emergence of substantial inefficiency.

Inefficient Dispatch

15

Shenzhen officials complain of being required to purchase expensive electricity from external suppliers while
low-cost local generation facilities are limited to fractional operation (Shenzhen Grid Reform 2015). Electricity
Databook (2014, pp. 468-481) confirms low operating hours for Shenzhen plants.
16

In the Hami district of Xinjiang, where the benchmark on-grid price is RMB 0.25 per KWh, large-scale industrial
users pay RMB 0.35-0.4 per KWh, the same amount charged for deliveries to Henan, 2000 km away, even though
local deliveries entail no long-distance transmission costs (Zhang Shuwei 2015).

17

Modern power grids deliver electricity from multiple producers to thousands of users. Since
the demand for electricity reflects trends in overall economic activity as well as seasonal andtime-of-day variations, the continual ebb and flow of power requirements calls for carefulmanagement of deliveries to the grid. This “dispatch” function assigns annual, monthly, daily,
hourly, even minute-by-minute delivery quotas to individual power plants. Unless production
falls short of demand, in which case dispatch involves nothing more than asking each plant tocontribute the maximum possible output, effective grid operation requires the intervention of asystem operator (in China, the grid company; elsewhere often an independent agency) thatassigns hourly, daily etc. production quotas to specific generating facilities in order to match
deliveries to shifting power demand.
In what order will the operator assign production quotas to various producers? The obvious
answer: begin with the lowest-cost operator (where cost might include both environmental andfinancial metrics), then the next cheapest etc. This procedure is unusual in China. Instead,continuing a practice inherited from the former planned economy, multiple operators –typically coal-fired plants - are often assigned similar annual operating hours, even thoughsome may have lower costs and/or lower unit coal consumption (and hence produce fewer
effluents) than others (Interview, May 17, 2012). Thus the world-leading Shanghai Waigaoqiao
plant mentioned above reported a load factor of only 78 percent, evidently because regulators
sacrificed some of its “clean coal” potential to allow dirtier plants their “fair share” of sales (Jia
2014a). Elsewhere, ad hoc arrangements favor specific plants: at one Shaanxi firm, foreign
investors obtained a special quota enabling them to sell 40-50 percent more power to the gridthan nearby rivals (interview, June 11, 2013).
Organized trading of quotas, which would allow clean, low-cost producers to purchase quota
from high-cost operators (thus reducing system costs while improving financial outcomes for allparties), although present, is not widespread. The result: unnecessarily high consumption ofcoal, excessive discharge of effluents, avoidable financial and maintenance costs (the latter
resulting from capacity fluctuations in coal-fired plants that are designed to run near rated
capacity). The current system also encourages overbuilding, because new plants can expect toreceive a “fair share” of future demand (Kahrl et al 2011, p. 4034).
Chinese grid operators have recently begun to introduce “merit dispatch,” which prioritizes
generators with low variable cost, thus dispatching hydro, nuclear, wind and solar energy aheadof power from coal-fired plants (Kahrl et al 2013, p. 362). This approach holds the promise oflimiting environmental costs, but can be problematic because the intermittent power flow from
non-nuclear sources of clean energy necessitates reliance on a flexible production component
to fill temporary or seasonal gaps in the availability of water, wind or sun. Since limited
resources and ill-advised policies have hindered the expansion of (relatively flexible) gas-fired

18

power plants,17 grid managers typically rely on coal-fired plants to fill supply gaps, a policy that,as noted above, raises both financial and environmental costs.
Despite these difficulties, efforts to quantify the inefficiencies arising from current dispatch
arrangements deliver surprisingly small results. As the “equal hours” system would predict,plant-level data reveal low correlation between unit coal consumption and annual operating
hours: a simple regression depicting 2010 operating hours as a linear function of coal use perdelivered kilowatt-hour accounts for only 1.2 percent of observed variation in operating hours
among 957 plants nationwide. Adding provincial fixed effects raises this figure to 8.7 percent;further inclusion of an interaction term linking coal use to interior location achieves a further
increase, but only to 9.0 percent.18 Similar analysis for Shandong province, among China’s
largest industrial producers, finds differential coal use accounting for only 7.3 percent of thevariation in operating hours among 149 coal-fired plants.
Widespread underutilization of efficient plants prompts the following experiment with the 2010
data for Shanxi province: assign 6000 operating hours (a high figure) to the most efficient coalfired plant; then assign 6000 hours to the next-best plant. Continue the process until the
cumulative output of included plants matches the actual 2010 total. Then compare coalconsumption under this hypothetical arrangement with the actual outcome. Although thisprocedure would result in the closure of 43 of 74 generating facilities, projected reduction incoal use is only 3 percent.
The reason: massive investment has boosted the share of large, modern plants in thermal
plants (Table 2). In Shanxi, the combined 2010 output share of the plants (hypothetically)
assigned zero operating hours was only 10.7 percent. This outcome confirms an earlier finding
using 2008-2009 data for Guangxi province: “energy efficient dispatch delivers at most amodest (2-4%) coal savings” (Kahrl et al 2013, p. 365).
The surprising finding that glaring episodes of misallocation – inefficient dispatch is one, largescale “spillage” of wind power is another – impose only marginal increases in system-wide costs
prompts a different approach focused on the analysis of costs for the entire power system.

17

Domestic production of natural gas remains modest; imports of Russian gas will provide no more than a modest
increase in the share of gas-fired generation. Large shale gas deposits will be difficult to develop. High domesticgas prices and low profitability limit prospects for import-fueled development. Lu Bin (2016a) emphasizes thepotential of gas-fired power expansion. He (2015ab) blames “existing pricing mechanisms and policies” for theslow advance of natural gas, reports low utilization of existing facilities, and proposes a price link between gas andelectricity of the sort that has functioned poorly in responding to fluctuating coal prices.
18

Plant-level data are from Electricity Databook 2010. Following advice from Michael Davidson, I eliminatedobservations for which reported coal consumption per KWh of delivered electricity was below 280 or above 600
grams. Statistical analysis courtesy of Professor Yang Song.

19

Excess Cost – A Sector-wide Perspective
Electricity, a large, high priority sector that affects China’s entire economy, offers a unique
opportunity to gauge the scale of inefficiency. This industry produces a single, homogeneous
product. Five enterprise groups generate nearly half of total output, and two grid firms virtuallymonopolize distribution and delivery. The presence of a reasonable statistical base, along withextreme concentration, enhances the prospect that analyzing power sector data can provide
fresh insight into China’s economic performance and prospects.
Hsieh and Klenow (2009) estimate the productivity gains achievable by limiting cross-industry
variations in efficiency to the level observed in U.S. manufacturing. We follow their approachby using information about U.S. prices and profitability to identify excess costs – the mirror
image of inefficiency-related productivity shortfalls – in a single Chinese industry, theproduction and distribution of electricity. Since perfect efficiency is rarely attained, reference
to observable benchmarks – outcomes in the U.S. electricity sector - avoids the exaggeration
implicit in comparing actual outcomes with assumed perfection – a procedure that Demsetz(1969) ridicules as the “economics of nirvana.”
Table 5 summarizes basic information about the Chinese and U.S. power systems in 2011, when
the two systems generated similar volumes of electricity (Figure 1). The two sectors areroughly comparable in terms of generating capacity and geographic expanse, but show widely
divergent patterns of employment and labor productivity.
Table 5 about here
Our procedure for ascertaining the rough dimensions of excess cost in China’s power sector issimple and direct. A review of price and profitability shows that Chinese electricity prices are
generally higher, and profits generally lower than in the U.S. power sector. The combination ofhigher prices and lower profits carries an unexpected implication: the unit cost of generating,transmitting and delivering electricity is higher in China than in the United States.
Excess costs measure the cost reductions needed to enable financial outcomes in China’s
electricity sector to match U.S. results over the decade 2005-2015 under a sequence of
successively more demanding circumstances: with no price changes, with a 40 percent
reduction in prices charged to industrial users, and with an across-the-board reduction of 33
percent in electricity prices.
The calculations that follow are far from precise. China’s utility majors operate coal mines andequipment factories; sectoral totals include outcomes from these non-power businesses. The
U.S. figures relate exclusively to investor-owned companies, and thus exclude public-sector
operations; the U.S. totals also include results from non-power businesses. There is no
adjustment for possible differences in Chinese and U.S. data definitions or accounting
standards.

20

As a result, the margin of error surrounding our estimation of excess costs is large. This meansthat only large, decisive verdicts can be plausible.
Prices. Table 1 presents annual averages for Chinese electricity prices for all users and for“large industrial” purchasers (大工业 dagongye) covering 2003-2014. Chinese prices areconverted to U.S. dollars at standard exchange rates for comparison with U.S. electricity prices
for all users and for industrial customers. We derive an index of Chinese prices, taking therelevant U.S. price for each year as 100.
The economy-wide Chinese price average stood at roughly 70 percent of the comparable U.S.
figure during 2003-2006, after which a combination of domestic price increases and increases in
the international value of China’s renminbi currency pushed Chinese prices to approximate
parity with the U.S. average beginning in 2012.
Similar economy-wide average prices conceal major differences in the internal structure ofChinese and U.S. electricity charges. In comparison with U.S. rates, prices charged to Chinesehouseholds are far lower, and unit costs for Chinese industry are much higher. Table 1 showsthat, once converted to U.S. dollar terms, electricity costs for Chinese large-scale industry ( 大工业 dagongye) have consistently matched or exceeded comparable U.S. prices, with the gap
between (higher) Chinese and (lower) U.S. rates rising from under 10 percent during 2003-2007
to 50 percent or more beginning in 2011. Unit costs facing manufacturers outside the scope oflarge-scale industry are even higher: rates for “ordinary industry and commerce” (一般工商业
yiban gongshangye) were 28-30 percent above the charges for large-scale industrial users
during 2013-15 (State Energy Administration 2015, p. 8; Price Competition 5, 2016).19
Currency exchange rates are not ideal for comparing prices and costs in economies with widely
varying levels of per capita output and income. The central difficulty is the presence of activities
like internal transportation and personal services that are rarely traded across national borders
and therefore do not contribute to the determination of currency exchange rates. Purchasing
power parity (PPP) exchange rates, calculated from price arrays that include non-traded as wellas traded commodities and services, aim to overcome this weakness. Because non-tradedcommodities and services are often relatively inexpensive in low-income countries, multiple
studies find that shifting from market to PPP exchange rates substantially raises the values ofcurrencies of low-income countries relative to those of advanced economies.

19

A comparison of “fully burdened” power costs for 2015, including all taxes and fees, found that “medianelectricity prices for industrial loads in the U.S. tend to be 34-49% lower than Chinese prices” (Comerford et al
2016, pp. 2-3).

21

China is no exception: Table 1 shows that PPP exchange rates for recent years value China’s
RMB currency at roughly RMB 3.5 per U.S. dollar, far above the market price of approximately
RMB 6.3 per dollar. This study uses market exchange rates to compare prices, profits and costsof electricity generation, transmission and distribution in China and the United States. Shifting
to PPP rates would sharply increase the U.S. dollar price of Chinese electricity – as shown by theitalicized rows marked PPP in Table 1 – which would strengthen the unexpected conclusion thatthe cost of generating, transmitting and distributing each kilowatt-hour of electricity is
substantially higher in China than in the United States.

Profitability. Compared with U.S. electric utilities, Chinese power firms benefit from low prices
for labor, equipment and materials as well as low construction costs for new facilities and lessstringent environmental requirements.20 Chinese power operations use newer equipment that,on average, consumes less coal and may require less maintenance than is needed at older U.S.
facilities.21 At times, Chinese power plants have enjoyed access to domestic coal at prices
below international market levels.
Industry-wide figures22 summarized in Table 6 confound the expectation that high power prices
and low costs should enable Chinese electricity firms to reap substantial profits. Table 6
provides two measures of returns showing annual industry-wide profits as percentages ofannual sales revenue and of total assets during the decade 2005-2015.23
Table 6 about here
Profit margins – the ratio of profits to annual sales – are modestly higher for U.S. investorowned electric utilities than for Chinese electricity firms. The average and median of annual
profit margins on the U.S. side exceed comparable Chinese figures by 43 and 2 percent.
Profit margins are far more volatile on the Chinese side. During this 11-year period, profit
margins for U.S. investor-owned utilities fluctuate within a narrow range between 9.97 and12.21 percent. Annual profit margins in China’s power sector fall within the range of 11.3-13.5

Renmin University Professor ZHENG Xinye 郑新业 emphasized the latter item in an October 2016 seminar.

20

21

Chinese specialists express surprise at the age and limited capacity of equipment that they encounter in U.S.
power facilities. One informant commented that computers installed at a California dispatch facility “could not run
the software that I write” for China’s power system (June 3, 2013 interview).
22

Industry-wide figures come from annual industrial statistics yearbooks that omit small plants and include firmsthat produce heat as well as electricity; both categories are small.
23

As explained in the Appendix, reported sales are adjusted to eliminate double counting that would artificiallyreduce the profit-sales ratio for China’s electricity sector.

22

percent in the initial and terminal years, but fall sharply in between, reaching a low of 2.83
percent in 2008.
Figures showing the annual pre-tax return on assets (ROA) display a similar contrast: ROA, theratio of annual pre-tax profits to total assets, is substantially higher for U.S. investor-owned
electric utilities (average 4.09, median 4.25 percent) than for Chinese firms (average 2.95,
median 2.98 percent). As with profit margins, volatility is far higher on the Chinese side.
Average and median ROA values for U.S. utilities during the decade 2005-15 exceed comparable
results for China’s electricity firms by 89 and 30 percent respectively.
These observations establish low profitability in China’s electricity system as a long-term rather
than a cyclical phenomenon. Low profits span intervals of rising (2005-2008) and declining(beginning in 2012) coal prices, variations that massively affect costs in China’s coal-dominatedpower sector.24 Low profits persist through periods of rapid (2005-07, 2009-11) and slow (from2012) demand growth.
The figures in Table 6, while highlighting the U.S. power sector’s superior financial results, may
exaggerate the profitability of Chinese electricity firms. The difficulty involves possible
underreporting of depreciation allowances, which reflect the annual costs assigned to longlived assets (structures, machinery, vehicles, etc.). Standard sources give annual figures for“cumulative depreciation allowances” (积累折旧费 jilei zhejiufei); figures for “current year
depreciation” (本年提取折旧费 bennian tiqu zhejiufei ) appear for some, but not all years.
Missing “current year” entries can be derived as the difference between cumulative
depreciation totals for successive years.
Variation in the projected service lives of various assets adds unavoidable complexity. Although
we cannot replicate the underlying calculations, industry-wide figures covering 2005-2015,
summarized in Table 7, reveal obvious difficulties. China’s power sector invests on a massive
scale, resulting in substantial net annual additions to the stock of depreciable assets.25 With nodramatic variation in the mix of assets or in the rules governing depreciation,26 abrupt shifts in

24

Coal purchases account for approximately 70 percent of variable costs for thermal plants, which in turn supply
roughly 70 percent of China’s overall electricity output. Coal-fired generating plants absorbed 1.84 billion tons ofcoal in 2012 (Energy Statistics 2015, p. 109). Prices of thermal coal declined by RMB 150 during the course of
2013. A price decline averaging RMB 100 would have reduced 2013 production costs by RMB 184 billion, anamount equal to nearly two-thirds of the entire power industry’s reported 2012 profits. See Wang 2014, Yearbook
2014, p. 264 and Table 6.
25“Net” additions to the asset stock refer to newly added assets less the sum of current depreciation expenses andthe undepreciated value of facilities and equipment removed from service.
26

Successive depreciation guidelines for the power sector show no major changes since 1985 (Depreciation 1985;
Depreciation 1994; Depreciation 2015).

23

the scale of depreciation allowances or their relation to broad measures of assets or capitalstock are highly improbable.
Table 7 about here
Sudden declines in annual depreciation allowances in 2008-2009, 2011-2012 and 2014-2015, as
well as the near-stagnation of depreciation expenses in 2012-2013 and the sudden leap in2014, seem unlikely to reflect actual operating conditions. These improbable sequences appear
to confirm claims that China’s large power-generating conglomerates (and other listedcompanies) periodically reduce depreciation allowances to embellish reported profits: a 2014
account quotes an industry specialist’s view that China’s big-5 power generating firms, which
reported combined 2013 profits of RMB 74 billion, would have earned little or no profit hadthey employed the depreciation rates in place 10 years earlier (Wang 2014). Another study
claims that depreciation reported by China’s grid companies during 2007-2011 was at least fivetimes the permissible amount (Power Prices 2014).
The following discussion focuses on officially reported data, ignoring possible overstatement of
profits.
China: a high-cost electricity producer. Despite operating under a regime of high sales prices
and low costs, China’s power sector delivered consistently weak financial results during thedecade beginning in 2005. Results in Table 6 shows that financial results for Chinese electricutilities generally lag behind similar measures for U.S. power companies. Domestic
comparisons reinforce the impression of weak financial performance: ROA for the electricity
sector lagged considerably behind the average for centrally-administered state-controlled firms
operating under China’s State-owned Assets Supervisory and Administration Commission(SASAC) throughout 2005-2012 (Table 6 and Lardy 2014, p. 56).
Low profitability combined with retail prices that, beginning in 2012, have matched or
exceeded the U.S. average imply that, beginning in 2012 if not earlier, and despite multiple costadvantages, the unit cost of generating, transmitting and delivering Chinese electricity, whenconverted to U.S. dollar terms, is higher than comparable costs for U.S. electric utilities.
What is the scale of excess costs? China is the world’s leading producer of electrical equipment,
construction materials and many other manufactures needed to erect power plants, build grid
systems, and generate and deliver electricity. The term “China price” reflects the reputation ofChinese industry for delivering serviceable products at low prices. Immense recent expansion of
capacity means that the average age of equipment is far lower in China’s power sector than in
America’s. This should translate into lower maintenance costs. Low wages provide Chinese firms
with a further cost advantage (Table 5).
With the exception of coal, the chief variable cost item for China’s power sector, for whichdomestic prices increasingly reflect international values, major cost elements endow China’s
electricity sector with a considerable cost advantage over U.S. utilities. Lean and efficient24

operations should translate this advantage into distinctly lower costs than the U.S. utility
system can achieve. The discovery that production costs for Chinese electricity are higher thanin the U.S. indicates the presence of substantial excess costs – expenses that could be
eliminated if Chinese electric utilities could match levels of operational efficiency observed in
the U.S.
These observations suggest a trio of benchmarks for appraising the magnitude of excess costsin China’s power system during 2005-2015:
 Excess costs [A] measure the cost reductions required to enable China’s electric power
sector to match the observed financial performance of U.S. utilities without changing
the electricity prices charged to Chinese end-users.
 Excess costs [B] measure the cost reductions required to enable China’s electric power
sector to match the observed financial performance of U.S. utilities following anassumed 40 percent reduction in the price charged to industrial electricity users.
 Excess costs [C] measure the cost reductions required to enable China’s electric power
sector to match the observed financial performance of U.S. utilities following anassumed 33 percent across-the-board reduction in Chinese electricity prices.
Each calculation determines the magnitude of cost reduction – in renminbi and as a percentage ofreported sales costs (adjusted sales revenue minus profits, see Table 6) – needed for each year’s Chinese
financial outcomes to match average U.S. performance during 2005-2015.
These performance targets reflect observations in Table 6. The target for the profit-sales ratio is 11
percent – slightly below the 11.35 percent average and 11.47 median of annual results for U.S. utilities
during 2005-15. The target ROA is 4.0 percent, which is 40 percent above the average Chinese ROA of
2.95 percent during 2005-2015 and slightly below the comparable U.S. average ROA of 4.09 percent(Table 6).
Table 8 compiles excess cost outcomes under the three sets of assumptions noted above.

Table 8 about here
Version [A] calls for sufficient cost reduction to match average U.S. financial metrics with no change tohistoric Chinese power prices. The results show that modest cost reductions averaging no more than
3.8 percent could have permitted actual results to match both the 11 percent profit-sales target and the
4 percent ROA benchmark during the decade ending in 2015.
Version [B], which requires cost reductions that elevate financial outcomes to the target levels in theface of a hypothetical 40 percent reduction in industrial power charges, is far more demanding. Results

25
in Table 8 show that meeting either benchmark would require cost reductions of in the neighborhood of
one-third.27
Version [C] investigates the magnitude of cost reductions needed to match recent financial outcomesfor U.S. electric utilities under the assumption of a 33 percent across-the-board reduction in Chinese
electricity prices. This approach avoids excessive focus on high prices imposed on industrial users, whicharise from administrative choices rather than cost considerations.
Early reports following the recent wave of electricity reforms, discussed in greater detail below, include
instances in which expansion of direct trading alone reduced prices by more than 30 percent inGuangdong, Anhui and Yunnan (Yao Jinnan 2016; May 2016 interviews); elsewhere, direct trading hasdelivered much smaller cost savings (e.g. Jiangsu Power Exchange 2016; LU Zheng 2016). Wide variationin the price consequences of direct trading and the paucity of information about the likely outcome ofcontinuing changes in grid charges and in the organization of retail sales make it difficult to anticipate
the eventual result. The assumed 33 percent price reduction embodied in Version [C], however, surely
falls within the range of possible outcomes.
Results in Table 8 show that matching historic U.S. financial performance during 2005-2015 under anassumed 33 percent across-the-board price reduction in electricity prices would have required Chinese
electricity firms to lower costs by approximately 35 percent.
The right-hand columns of Table 8 summarize the actual amount of cost reduction needed to attain anassumed ROA of 4 percent during the decade 2005-2015 under alternative assumptions. Averageannual cost reductions range from RMB 73 billion for Version [A] (no price change) to much higher
figures of RMB 770 billion for Version [B] (40 percent reduction in prices for industrial users). Imposing a
33 percent across-the-board price reduction (Version [C]) would require annual cost reductions
averaging RMB 865 billion. Beginning in 2011, attaining a 4 percent ROA following either a 40 percent
reduction in industrial power prices or a 33 percent sector-wide price cut would require annual cost
reductions approaching or surpassing RMB 1 trillion.
The central role of industrial electricity use, which consistently accounts for 70 percent or more ofoverall Chinese power consumption (Table 8), offers a natural focus for appraising the magnitude ofpossible excess costs. Firms classified in the tariff category “large industry” (大工业 dagongye), which
absorb the largest portion of industrial electricity sales, face tariffs that, when converted to U.S. dollars,
exceed prices charged to U.S. industrial electricity users throughout the decade 2005-14; during 2011-27

The assumed 40 percent price reduction for industrial users reflects inconsistencies in the data underlying thisessay. Data for 2014 indicate that the overall average of U.S. and Chinese power prices was virtually identical, that
average prices for large-scale industrial users were 50 percent above the overall average (Table 1); that smallerindustrial users paid 30 percent more for electricity than large users (State Energy Administration 2015), and thatindustrial users absorbed 70.7 percent of overall electricity supplies (Table 8). This combination is mathematically
impossible. Sales of 70.7 percent of available electricity to industrial users at 50 percent above the overall average
price would imply revenue from industrial sales amounting to 70.7 * 1.5 = 106.5 percent of the total – whichcannot exceed 100 percent. Excess costs [B] limits the hypothetical reduction in industrial power charges to avoid
this inconsistency, which is not limited to 2014.

26
2014, the price gap is 50 percent or higher (Table 1). An noted above, industrial users outside the scopeof “large industry” pay even more.
U.S. electricity prices are neither artificially reduced to benefit industrial users nor artificially inflated toensure outsized financial returns to electric utilities. With the benefit of multiple cost advantages, awell-managed Chinese electricity system should be capable of matching U.S. financial outcomes if theprice charged to industrial users, who absorb the bulk of Chinese electricity (Table 8) were the same in
China as in the U.S.
Excess cost estimates based on Version [B], which imposes a 40 percent reduction on electricity prices
charged to Chinese industrial users, provide a plausible lower bound answer to the question “What is
the magnitude of cost reductions needed to enable financial outcomes in China’s electricity system tomatch the performance benchmark represented by the U.S. electricity system?”Why is the excess cost figure associated with Version [B] a plausible lower bound?
 The assumed 40 percent reduction in prices charged to industrial users is considerably smaller
than the actual gap between Chinese and U.S. industrial electricity prices in recent years. Table
1 shows that, on average, electricity prices paid by “large industry” in China exceeded average
U.S. industrial electricity prices by 50 percent during 2009-2015. Higher prices charged to small
and medium industrial users raise the industry-wide average: in 2014, the Chinese industry-wide
average was perhaps 60 percent higher than average U.S. industrial power prices.28
 Bank lending rates are far higher in China, where the average rate on one-year loans during
2005-14 was 6.30 percent, than in the U.S., where, on average, the banks’ prime lending rate
was 4.68 percent during the same period.29 Changing the financial performance benchmark
underlying the calculations in Table 8 from matching U.S. utilities’ average ROA (4.16 percent) tomatching the U.S, utilities’ ratio of ROA to cost of capital (4.09/4.68 or 0.87) would increase themagnitude of estimated excess costs because the Chinese ratio of ROA to capital cost, 2.95/6.30= 0.47, is only 54 percent of the U.S. figure, whereas the Chinese ROA is 69 percent of thecomparable U.S. figure (2.95/4.16 = 0.687).
 High prices charged to Chinese industrial electricity users conceal cost-shifting intended tounderwrite low prices offered to households and to agricultural power users. This sort of crosssubsidy represents a politically-motivated financial transfer rather than any sort of cost overrun.
These cross-subsidies, however, are far smaller than the amounts shown in the right-handcolumns of Table 8.
28

Based on fragmentary data for 2016 showing that “large industry” absorbed 50.3 percent of Hubei power sales
during the first two quarters (Hubei electricity 2016) and that “ordinary industry and commerce” (一般工商业
yiban gongshangye) absorbed 17.8 percent of total first-quarter sales in Jiangsu (Jiangsu electricity 2016). If sales
to industry account for 70 percent of the total, with 50 percent going to “large industry” at a price 50 percent
above the economy-wide average and 20 percent going to “ordinary industry and commerce” at a price 30 percent
higher than the price for “large industry,” the average power price for the two categories combined works out to62.8 percent above the economy-wide average.
29

Chinese lending rates for 2005-2014 courtesy of Nicholas R. Lardy; for 2015, calculated from Abstract 2016, p.
165. U.S. rates from http://www.federalreserve.gov/releases/H15/data.htm, accessed September 22, 2016.

27

oTang (2014) estimates the combined subsidy for household (RMB 49.3 billion) and for
agricultural (RMB 14.1 billion) electricity users at RMB 63.4 billion for 2010.

Chinese households used 698.9 billion KWh of power in 2013 (Yearbook 2015, Table 9-12),
when the average power price was RMB 0.55748 per KWh for households and RMB 0.63549
for all Chinese users (State Administration of Energy 2015).
Taking the U.S., where residential electricity prices were 18.5 percent above the overall
average in July 2015 and 18.4 percent higher than the average for July 2016, as abenchmark, we can crudely approximate the 2013 subsidy enjoyed by Chinese households
as the difference between an assumed price of RMB 0.7498 (18% above the 2013 economywide average) and the actual household unit price, multiplied by 2013 household power
consumption:2013 subsidy ≈ 698.9 * [(0.63549 * 1.18) – 0.55748] = 698.9 * 0.1924 = RMB 134.5 billion
Assuming no change in the ratio between subsidies for household and for agricultural power use
between 2010 and 2013, our crude projection of combined 2013 subsidies for these sectors is
RMB 134.5 billion * (63.4/49.3) = RMB 173 billion
Raising the assumed reduction in industrial power prices from 40 to 50 percent, a change that is entirelycompatible with available information on electricity pricing, would increase the estimate of cost
reduction required to attain a 4 percent ROA in 2013 by RMB 247.7 billion – far larger than the crosssubsidy amount for that year.
We conclude that the scale of cost reductions needed for China’s electric power system to attain aprofit/sales ratio of 11 percent or average ROA of 4.0 percent following an assumed 40 percent
reduction in industrial power prices during 2005-2015 does indeed provide a plausible lowerbound measure of excess costs within China’s electricity sector.
The scale of cost reductions required to match U.S. financial outcomes following a hypothetical
40 percent reduction in prices for industrial electricity shown in Table 8 ranges from 29.5
percent (to attain an 11 percent profit-sales ratio) to 3.95 percent (to reach an average ROA of
4.0 percent). We focus on the lower of these results, and propose 30 percent as a plausible
lower bound estimate of excess costs in China’s electricity industry.
We make no claim of precision. Inconsistencies within the Chinese data underlying our
calculations and also between Chinese and U.S. statistical compilations create the expectationof large error margins in our results.
As noted earlier, only big conclusions retain credence in the presence of large error margins.
The findings summarized in Table 8 represent just such an outcome. Investigation of the simple
relation Cost = Revenue – Profit shows that, notwithstanding the presence of multiple favorable

28

circumstances, the unit cost of producing, transmitting and delivering electricity is substantiallyhigher in China than in the U.S. While the exact measure of the cost gap, which we place at aminimum of 30 percent, may be disputed, the analysis presented here, which builds on
quantitative materials distributed by Chinese industry and official sources, leaves no room toquestion the surprising conclusion that unit costs of delivering electricity to end users aresubstantially higher in China than in the U.S.

Where do excess costs cluster? What follows is an initial foray into the structure of Chinese
electricity costs.
High rail freight and logistics expenses? Movement of goods in China is expensive. Coal, thelargest single cargo in China’s transport system, is no exception. The cost of shipping coal attracts
vociferous complaints, which often repeat the claim that “According to statistics, the logistics cost of
shipping coal over 1,000 km in China is 10-15 times the cost in the United States and 15-20 times that inJapan“ (Coal Logistics 2015).

Following the cessation of Japanese coal mining in 2002, rail carriage of coal has all but
disappeared, rendering the Japan comparison irrelevant. Rail freight costs for shipping coal areindeed higher in China than in the U.S. Conversion of cost figures at prevailing exchange rates
shows that average rail freight per ton-km for Chinese coal shipments was 21-29 percent higher
than comparable U.S. costs during 2003-2008; thereafter, the cost gap increased, in part
because of the increased value of China’s renminbi currency, so that by 2015, unit rail freightcosts for Chinese coal exceeded comparable U.S. figures by 78 percent (Rawski 2015).
Commodity shipments attract numerous taxes and fees, many imposed by local authorities that
resist Beijing’s efforts at systematization and control. Again, coal is no exception: one survey
reported 109 varieties of taxes and fees (Coal Costs 2015).
The potential for cost savings in the shipment of coal is considerable. China’s power plants
burned an average of 1.78 billion tons of coal annually during 2010-2015 (Energy Statistics
2015, p. 109), most delivered by rail. In 2012, when power plants consumed 1.84 billion tons
(ibid.), average length of haul for railway shipments of coal was 645 km and average rail fees
per ton-km were RMB 0.131 (Rawski 2015). Thus the cost of rail shipment was roughly 645 *0.131 * 1.84 or RMB 155 billion. With fees reportedly occupying the same share of delivered
coal costs as rail freight – 20 percent for each – and adding additional costs for short-haultrucking (8%) and port charges (5%) (Coal Logistics 2015), the 2012 data imply that costs ofmoving coal from the mines to China’s power plants are in the neighborhood of RMB 155 billion* 49/20 or RMB 380 billion.
Chen Deming, China’s Minister of Commerce, noted in 2012 that imposition of fees accounted
for over half of logistics costs, and indicated that suitable reforms might halve the cost of
moving goods (Yu 2012). Using 2012 figures, a 50 percent reduction in logistics costs would

29

amount to RMB 190 billion. But even this large number, which amounts to 6.2 percent of 2012
(adjusted) sales costs for China’s electricity sector (Table 6), would provide only a modest
contribution to the cost reductions linked to Version [B] in Table 8.

Overbuilding? Beginning in the early 1980s, China experienced repeated episodes of severe
power shortage. This stimulated a strong, and eventually successful effort to accelerate supply
growth and eliminate the economic damage arising from electricity-related production
stoppages. Given the long history of shortage, it is hardly surprising that supply growthovershot demand, leading to growing reports of falling utilization and idle generating facilities
beginning in 2013.
The ongoing response to the recent demand slowdown, which has seen the annual growth ofelectricity consumption plunge from double-digits as recently as 2011 to less than 1 percent in2015 before rebounding to 5.6 percent in 2016, demonstrates that excess investment is a longterm structural issue rather than a short-term adjustment problem. Building of new plants andrequests for approval of additional projects continue even as utilization rates plunge
dramatically (Table 3), estimates of excess generation capacity reach 38 percent (Lin, Liu and Ke
2016) and forecasts for future demand growth cluster in the low single digits: Lu Bin (2016d),
for example, cites experts’ expectations of “no quick rebound” in the pace of demand growth.
Critics blame power firms and regional governments for pursuing “blind investments” (盲目投资 mangmu touzi) that aggregate into “Great Leap Forward-style” expansion of coal-fired generation
facilities – referring to a period of recklessly wasteful investment during the late 1950s (Yuan Jiahai
2016; Li Beiling 2016).

Since construction costs do not enter into the calculation of annual profits, the direct impact ofoverbuilding on profits is limited to increased interest costs associated with the financing of
new facilities. The indirect effect of excess capacity – growing difficulty in covering fixed costs
following a general reduction in utilization rates – represents a greater threat to profitability,
particularly for power generation firms, some of which have high ratios of debt to assets. Thus a2016 report noted double-digit declines in operating cash flow for four of China’s five largest
power generation companies and commented that their businesses face “increasing pressure”
and “increasingly urgent cash flow needs” (Working Capital 2016).

Pursuit of uneconomic technology? Field interviews raise the possibility of ill-advised outlays
that produce only marginal efficiency gains. One plant manager reported that improvements
costing RMB 260 million at two 300 MW thermal plants lowered coal consumption per KWh by
about 20 grams; increasing utilization rates from 60 to 90 percent would reduce unit coal use
by 11 grams and also lower power consumption within the plants – with zero investment

30

expense.30 Domestic critics complain that the productivity of State Grid Corporation’s
investment spending is falling and that efforts to develop long-distance high-voltage AC powertransmission have encumbered China’s grid system with high cost, underutilized facilities (Fu2014; He 2015b; Jia 2015c). Others pillory efforts to pursue offshore wind farms as “floating
white elephants” (Gao 2014). Loren Brandt and Luhang Wang find that Chinese wind turbine
producers rush to produce high-capacity models while neglecting quality issues that plague thesmaller models that dominate market sales.

Trapped power? As the share of power from intermittent sources (hydro, wind, solar) in total
power generation increases, the likelihood of “spillage” or “curtailment”– electricity that neverenters the grid and is therefore wasted – increases. Spillage can arise from technical conflicts
or from economic choices – for example if grid companies resist pressure to pay high prices or
to build expensive links to absorb “clean” power. China has the unfortunate distinction of theworld’s highest wind power curtailment rates – 17 percent in 2016 – more than double thehighest reported elsewhere (Davidson 2016, Bai 2017). Unexpectedly low demand growth has
encouraged Guangdong and other provinces to prioritize local thermal plants (and build newones) while rejecting incoming power transfers from hydroelectric facilities in western
provinces, leading to considerable spillage in the hydroelectric sector (Fu 2015). There aremany reports of expanding curtailment: Xiao (2016) focuses on wind power, but others notesimilar phenomena affecting hydro, solar, and even nuclear generation (Zhu 2017).

Too many workers? 2011 data assembled in Table 5 show that, compared with its U.S.
counterpart, China’s electricity sector had slightly less installed capacity, generated 15 percent
more power, and employed more than 6.5 times as many workers. Part of this gap arises fromthe need to provide services to a far larger number of (especially household) consumers. A
portion may represent a sensible response to China’s relatively low labor costs. Even so, rapid
progress of equipment modernization and automation – for example, using drones to inspectelectricity facilities (Yao Haitang 2016), makes it difficult to believe that, on average, efficient
operation of each unit of Chinese generating, transmission and distribution capacity requires
more than six times the number of workers associated with comparable (and typically older)
U.S. equipment. The combination of increasing automation and declining growth of laborproductivity, which rose by 70 percent during 2000-2005, by 54 percent during 2005-2010 andby 20.7 percent between 2011 and 2015, points to substantial opportunities to pare the costs –30

June 2013 interview. In addition to reducing coal use, the improvements enabled these plants to meet specificenvironmental regulations.

31

not just wages, but equipment, vehicles, office space, and housing outlays - associated withovermanning.31
Of these potentially quantifiable cost items, only rail freight and logistics offers potential cost
reductions that can even partially march the excess cost estimates associated with substantial
price reductions (Table 8). Neither wages, which amounted to 3.1 percent of sales in theelectric power sector during 2011 (Table 5) nor interest payments, which absorbed 0.12
percent of 2012 sales revenue for generating companies and even less for grid companies(Industrial Statistics 2013, i: 117, 226-227), are large enough to support even the small cost
reductions needed to attain U.S.-style profit/sales or ROA outcomes under existing Chinese
prices (Table 8, Version [A]), let alone the larger figures associated with Versions [B] or [C].
Plausible cost reductions associated with overmanning, excess investment, trapped power,
pursuit of uneconomic technical advances and logistics could not deliver the savings required toapproach either the profit-sales or ROA metric if electricity charges to industrial users werelowered by 40 percent to approximate the U.S. level (Version [B]).
System costs? Our inability to attribute China’s surprisingly high electricity costs to specific,
quantifiable causes directs attention to possible excess costs arising from the institutional
matrix within which this sector operates. Three areas stand out: Managerial complexity. “General fragmentation of authority” in China’s
administrative system means that “policy-making is. . . characterized by anenormous amount of discussion and bargaining. . . (Lieberthal 1995, 173, withemphasis added). While this description refers to governmental processes, themultiplicity of official and corporate actors involved in decisions about siting,building and operating power plants, about the construction and operation of gridfacilities, about the dispatch, allocation and pricing of power flows, and about theremediation of effluents associated with electricity production ensure theexpenditure of “enormous” resources in everyday decision-making surrounding
China’s power sector.
Since “discussion and bargaining” are the function of managers, rather than ordinary
workers, it is not surprising to find in Table 9 that managers at 16 large Chinese
power-related firms account for 17.76 percent of 2014 employment at thesecompanies, 11 percentage points above the U.S. figure of 6.77 percent for electricity
generation and transmission.

31

Labor productivity is measured as the quotient of overall power generation and sector-wide employment. See
author’s file Electricity cost data 032616, Tab Output per worker.

32

Table 9 about here
Applying the proportion of managers in 16 firms to the entire Chinese power sector– note that these firms employ 80 percent of China’s electricity work force - andtaking the U.S. proportion of managers as a benchmark, we conclude that theunusual complexity of business arrangements may require the employment of 0.11 *2600.1 = 286,000 additional managers, a figure equivalent to nearly three-quartersof the entire U.S. electricity industry work force! This calculation vividly illustrates
the potential magnitude of system costs in one segment of China’s economy.
 Institutional conflicts. Many examples can illustrate the frequency andpervasiveness of costly outcomes arising from conflicting interests within China’s
power system.
o Critics excoriate the “Great Leap Forward-style” rush to build new thermal
power plants even as utilization of existing coal-fired facilities plunges (Li2016; State Energy Administration 2016). Even as proposed expansion ofcoal-fired power plants encounters “strict and even punitive policy
constraints,” a report that coal-fired co-generation, combining generation ofheat and power, faces “more lenient” approval and construction
requirements (Lu Bin 2016c) may offer a new outlet for the investment
hunger of local governments even though 70 percent of cogeneration plants
run by the Big 5 generating companies lost money in 2013 (Yu 2015).
o Numerous reports describe the construction and operation of power facilities
in the absence of official approval. One account cites government estimatesthat “One fifth of the power plants in China are illegal” (Oster 2006).
o Local protectionism motivates efforts to build duplicative (but locallycontrolled) power plants to channel demand to locally controlled generation
facilities, or to prevent “imported” power from underselling local producers.
This may explain Michael Davidson’s (2016) observation that newly
commissioned, technologically sophisticated, clean, low-cost generating
plants may run far below optimum capacity – as reported in He (2015b),
while higher-cost facilities continue to receive substantial operating hours.
o Prior to recent reform initiatives, China’s major grid companies werenotorious for concealing detailed cost information. An official of the former
State Electricity Regulatory Commission explained that key cost items related
to grid management are “intentionally hidden from outside view” (May 17,
2012 interview).

33

 Resource extraction. China’s electricity system is dominated by massive stateowned firms whose politically potent leaders, labyrinthine organization, andmultiple layers of subsidiaries offer considerable shelter from external scrutiny.
These firms’ involvement in large numbers of construction projects, no-bid
contracts, and related party transactions creates ample opportunities for leaders at
all levels to obtain private benefits at the expense of corporate financial outcomes.32
One regulatory official sees these firms as “cradles for corruption” (Huang and Yu
2015). While the recent anti-corruption campaign seeks to diminish actual or
potential political opposition as well as financial malpractice, continuing focus on theenergy sector, including major electricity firms, leaves no doubt that various formsof resource extraction are deeply embedded in the structure of China’s power
sector. The resulting excess costs, while not subject to even the crudest estimation,
could be very large.

RETROSPECT AND PROSPECTThe experience of China’s electric power sector during the past several decades is, first andforemost, a story of remarkable success. Formerly dominated by small, antiquated, fuelgobbling generating plants and bypassing vast rural areas while scrambling to satisfy urban
demand, China’s power system now comprises a nationwide network of modern generation
facilities linked to regional grid networks. Important metrics such as unit coal consumption,
self-consumption of power by generating facilities, and transmission losses resemble the values
observed in advanced nations. Theft of power and payment arrears, phenomena thatdestabilize electricity operations in many low- and middle-income nations, are notably absent:
State Grid Corp. reportedly collected over 99.9 percent of electricity charges in 2011, in part
because “improved risk control” including legal actions that recovered RMB 2.62 million in
unpaid bills during that year (State Grid 2012, p. 164).33
This impressive transformation coexists with a regime of surprisingly high costs and prices.
China’s unexpected combination of high electricity prices, low prices for materials, equipment
and labor used to generate, transmit and deliver power, and low profits signals the presence of32

Gezhouba Dam Group (葛洲坝集团), ranked 48 and 36 in 2012 and 2014 among China’s 100+ central SOEs for“rule of law,” illustrates these difficulties. During 2012-2014, the firm worked to “establish contract management”
and “standardized management.” During 2015, “the company reviewed a total of 62,091 contracts valued at
RMB431 billion” – evidently a new development. Although “building a legal system is not easy,” integrity amongsubsidiary enterprises “improved.” See Duan Guiheng (2016).
33

Lu Bin (2016e) cites an exception – residents stealing steam from a troubled Jiangsu plant.

34

large-scale inefficiency. A lean and efficient power system should have the capacity to deliverelectricity to China’s firms and households at substantially reduced costs.
Our finding that attaining financial outcomes similar to those achieved by U.S. electric utilities
while lowering industrial electricity charges toward the prevailing U.S. level would require cost
reductions in the neighborhood of 30 percent represents a lower-bound estimate of thepotential for cost reduction within China’s electricity system. Alternative calculations usingpurchasing-power parity (PPP) exchange rates rather than market rates to convert Chinese
electricity prices to U.S. dollars, a plausible approach in cross-national comparisons involving
economies at different levels of development, would raise our estimate of potential cost
reduction.
Since readily quantifiable sources of excess costs, including rail freight charges for coal – themain source of energy for China’s power sector – cannot provide more than a fraction of thesavings needed to match U.S. utilities’ financial outcomes if industrial power prices were shifted
toward the U.S. level, we conclude that elevated costs are deeply embedded within the
structure of China’s power system. Major reductions will not be a matter of lopping off obvious
cost overruns, but seem likely to require far-ranging reform of current business and regulatory
practices.
This diagnosis exactly matches recent Chinese policy initiatives. Following a decade-long hiatus,
far-ranging electricity reform reappeared on Beijing’s policy horizon in 2015. The new reformpush employs transparency as a lever to extend market pressures and thus reduce power costs.
Beginning with Shenzhen, regulators have conducted audits of formerly concealed grid costs.
In place of opaque negotiations between the grid companies and government agencies, we see
the gradual emergence of a system conforming to international regulatory standards describedin Irene Wu’s chapter: regulators determine authorized grid charges by adding a specified profit
markup to a roster of approved costs (Shenzhen Grid Reform 2015); published accounts suggestthat regulators typically allow profit margins in the neighborhood of 8 percent above approved
costs.34 Standardization of grid charges smooths the path for a second innovation: rapid
expansion of direct sales agreements between generating companies and large industrial users.
Although the financial impact of initial grid pricing reforms is small when compared to 2015 grid
revenues of RMB 3653 billion (China Industrial Statistics 2016, i: 99), consequences havemounted as the reform unfolds. The Shenzhen reforms anticipated reductions in grid feesamounting to RMB 700 million during 2015-2017 (Shenzhen Grid Price 2015). Subsequent
reforms covering five provinces anticipate reduced grid revenues of RMB 5.6 billion during
2016-2018 (Yao Jinnan 2016). According to State Grid’s president, pricing reforms trimmed his
firm’s revenues by RMB 56 billion during the first half of 2017 (Huang and Song 2017).
34

Cheng (2016) cites a range of 8-10 percent for solar projects; Zhang Zirui (2016a) interviews an industry specialist
who uses 7.38 percent in analyzing prospects for offshore wind projects; Pipeline (2016) cites 8 percent as theprospective rate of return for natural gas pipelines.

35

The potential impact of direct sales is far greater. In Yunnan, direct sales surpassed 45 percent
of industrial power consumption in early 2016, with average prices declining by RMB 0.18 per
kilowatt-hour (Yao Jinnan 2016). A nationwide reduction of this magnitude in 2015, whenindustry absorbed 70.9 percent of China’s 5,550 billion kwh of power use, would have lowered
electricity charges by RMB 708.3 billion, a substantial fraction of even the largest excess costestimates derived in Table 8. Direct sales amounted to 19 percent of overall power
consumption in 2016 (Fan and Li 2017) – amounting to 27 percent of industrial power use.
Policy announcements projected that direct sales would reach 30 percent of industrial use in2016, with full liberalization of industrial and of commercial sales anticipated for 2018 and 2020
respectively (Jia 2016).
The impact of expanded entry into retail electricity sales, the third leg of the current reform
agenda, remains unclear. However with the number of power sales firms rising from “over300” to 6,387 between March 2016 and February 2017, and with entry open to newcomers,
including private firms, from outside the power sector, implementation of this initiative opens
the door to further reduction of electricity charges (Lu Bin 2016b; Power Sales 2017).
Reforms that reduce costs to electricity users represent identical revenue reductions for thecompanies that generate and deliver electricity. Opposition by representatives of thegenerating and grid companies (Jia 2015b; Lu Binggen 2016) cannot withstand the pressurearising from China’s current combination of high power prices, massive overbuilding of power
plants, declining operating hours and financial exigencies among power users, many sufferingfrom the consequences of their own past investment excesses. The inevitable result: increased
pressure on firms that enter the latest round of reform initiatives with a history of weakfinancial results (Table 6) will magnify an already formidable array of challenges.
Slowing demand growth is the central reality confronting China’s entire electricity supply chain:coal mining, generation and grid companies, equipment manufacturers, design institutes andconstruction firms. Nationwide growth of electricity consumption, which raced ahead for
decades at or near double-digit rates, has slowed. Following near-stagnation in 2015, China’s
National Energy Agency projects annual demand growth during 2016-2020 in the range of 3.64.8 percent (Electricity Plan 2016). Reflecting the impact of this growth slowdown, an executiveof Shanghai Electric, a leading supplier of power plant equipment, commented in 2014 thatdemand for thermal power equipment had dropped by 50 percent during the previous five
years, and, with government officials blacklisting coal, could see a similar decline during thefollowing five years (Mu and Shu 2014).
Interaction between the unexpected slowdown of demand expansion and massive capacity
growth (Figure 1) has produced a steep drop-off in utilization rates (Table 3). Average
operating hours for China’s vast fleet of coal-fired generating plants, which typically face
breakeven points (at which revenues suffice to cover loan repayments as well as operating
costs) of 5,000-5,500 annual hours, plunged to 4,165 hours in 2016, the lowest since 1964, with

36

further reductions anticipated (May 17, 2012 interview; China Electricity Council 2016; Li 2016;
Table 3).
At the same time, generating firms, which are major sources of airborne effluents, faceescalating cost pressures arising from the government’s increasingly forceful response towidespread public concern over urban air pollution. Officials have ordered power plants toretrofit effluent-reducing devices; offsetting increments to on-grid prices offer only partial
compensation for the resulting cost increases; promised subsidy payments are often in arrears(Yu Chunping 2015; Zhang Zirui 2016b). In some instances, particularly in the largest cities,
authorities have banned new coal-fired plants – ignoring industry assurances regarding thebenefits of “clean coal” (Jia 2014ab) and forced existing plants to shut down or convert fromcoal to natural gas.
Three additional developments may escalate financial pressure: Growth of power from intermittent sources is driving up costs for both grid
operators and for the (typically coal-based) back-up operations that supply power
when wind and sun are not available (Xie 2016); Kahrl and Wang (2014, p. 7) present
2011 provincial data showing a steep rise in wind curtailment once wind power
exceeds 4-5 percent of provincial electricity output.
 Proposed use of demand management aimed at reducing peak power requirements,for example through the extension of time-of-day power pricing, could further
reduce operating hours.
 Plans to raise deposit rates paid by China’s banks, if fully implemented, could lead tohigher lending rates, and thus impose cost increases, especially on the heavily
indebted generating sector.
These circumstances have spawned mounting financial uncertainty, especially for the five big
generating companies, which entered the recent round of reforms with debt-asset ratios
approaching 90 percent – among the highest for China’s centrally-managed state enterprises(China Electricity Yearbook 2012, p. 144). Reduced cash flow among the five large generatingcompanies (Working Capital 2016) may push cost cutting ahead of capacity expansion among
the priorities of electricity executives, especially in the generation sector.

Looking Forward
The central finding of this study, summarized in Table 8, is that advances in technology andservice provision conceal massive opportunities to lower costs. While downward price pressure
affects all segments of the industry, cost reduction of the order suggested by the figures inTable 8 can only occur in the production and distribution of electricity from coal-fired

37

generating facilities. Fixed costs predominate at both hydroelectric and nuclear plants; chancesof finding substantial opportunities for reducing operational costs appear slight, particularly inthe nuclear sector, where post-Fukushima escalation of safety measures has imposed layers of
unexpected expenses. Wind and solar, with a combined output share of 4.5 percent in 2015,
have small operating costs and are in any case too small to deliver cost reductions that would
meaningfully affect industry-wide totals.
The intensification of market forces inherent in ongoing electricity reforms will direct demand
toward low-cost sources of electricity. Successful pursuit of cost reduction has the potential tolower the absolute and relative cost of coal-fired power. Institutional arrangements and policy
structures that routinely tilt toward long-dominant coal interests (Zhang Shuwei 2016),
illustrated by the November 2016 announcement of long-term contract arrangements that will
provide electricity producers with thermal coal at a 25 percent discount to the current market
price, reinforce this prospect (Zheng 2016).
Substantial reductions in nuclear plant operating hours (e.g. Nuclear Facilities 2016) show how
the interaction among excess capacity, latent cost reduction potential and market deepening
may spark a reversal of recent declines in the volume and share of coal-fired power generation– the exact opposite of Beijing’s declared policy objectives and of the international
community’s expectations following the 2016 Paris accord. Massive expansion of thermal
power generation envisioned in the November 2016 announcement of 13th Five-Year Plan
(2016-2020) targets for electricity, along with the likelihood of additional growth inherent in
the repeated proviso that Beijing would “strive to limit” 2020 thermal capacity to the targeted
figure, highlights the formidable resilience of China’s coal interests.
Can the current revival of reform momentum overcome a tangled web of circumstances thathas allowed institutional legacies, inchoate policies, ineffectual regulation and large-scale
misappropriation of resources to transform this technically progressive sector’s brightprospects into a latent financial nightmare? And can ongoing reform efforts limit or reduce theenvironmental costs associated with Chinese electricity production?
Although the obstacles to thoroughgoing reform appear formidable, so too are the capabilities
available to China’s electric power system. Individual segments have avoided the accumulationof excess costs that plagues the system as a whole: power output per unit of installed capacity
exceeds performance in the U.S. (Table 5) and the trajectory of new plant costs demonstrates
an exceptional capacity for cost control (Figure 2). China leads the world in erecting wind andsolar generation facilities, and boasts a large and rapidly growing fleet of nuclear power plants.
The threatened transformation of a crucial economic sector into a long-term fiscal burden andenvironmental incubus may elicit a determined effort to mobilize the resources responsible forthe power sector’s many achievements to create institutional systems surrounding the
production and distribution of Chinese electricity that can match the system’s technicalexcellence.

38

APPENDIXCALCULATION OF PROFIT-SALES RATIOAnnual yearbooks of Chinese industrial statistics provide information on sales revenue (S), assets (A) andprofits (π) of the electricity industry. We use this information to calculate the ratio of profits to sales aswell as the return on assets.
The yearbook figures on sales revenue, however, do not match comparable information regarding U.S.
investor-owned utilities. Chinese grid companies purchase electricity from power plants, then resell theelectricity to end-users. This means that amounts paid to generating companies are counted twice incompiling data on industry-wide sales: once when the generating companies sell electricity to the grid,and a second time when the grid resells this power (less transmission losses) to end users.
Under U.S. institutional arrangements, when separate companies generate and transmit electricity, endusers are billed separately for electric power and for transmission and delivery services, so thatsumming the sales of various companies counts generating company revenues only once.
Using reported data to compare the profit/sales ratio for Chinese and U.S. electric utilities will thus
exaggerate the relative profitability of U.S. firms because total sales of generating firms will appear oncein the denominator of the formula 100* π/S for the U.S. industry but twice in a similar calculation on the
Chinese side.
To avoid this distortion, Table A-1 derives adjusted sales figures for Chinese electric utilities thateliminate this double counting. The adjusted sales figures, denoted by S’, are comparable with reported
sales for U.S. investor-owned electric utilities.
The adjustment is shown in Table A-1.
Adjusted revenue S’, measured in billion RMB, is derived from
reported sales S – measured in billion RMB
reported power production Q – measured in billion KWh
the percentage of gross electricity output consumed within generation facilities cand the average wholesale or on-grid price received by the generating companies P – RMB per MWh.
The derivation is:
S’ = S – [(.001P) * (.01Q*(1-c))]We thus obtain a revised sales total by subtracting the grid’s payment to generating companies forincoming power flows from reported industry-wide sales.
.001*P is the wholesale electricity price expressed in RMB per KWh (1 MWh = 1000 KWh)
.01*Q*(1-c) is the total of electricity supplied to the grid. Q measures gross power output, including
electricity consumed within generating plants.

39
For example, If c=5%, then (100-c) is 95%, .01*95 = 0.95, which is the share of power output thatreaches the grid; more generally, .01*Q*(1-c) is the actual power flow to the grid.

ROA FOR U.S. ELECTRICITY FIRMS, 2005-2015
Profit figures for China’s electricity sector appear in Table 6; these are pre-tax figures.
Table A-2 tabulates our estimate of the pre-tax return on assets (ROA) for investor-owned U.S. utilities.
John Hanson of Riverstone Advisers LLC compiled annual after-tax ROA data for 25 U.S. electric utilities
covering the years 2005-2014. I eliminated one firm for which the data series was incomplete andcalculated industry-wide ROA for each year in two versions: the unweighted average of 24 firm-level
ROAs, and a weighted average using 2014 sales figures as weights. After-tax ROA data for 2015 are fromcsimarkets.com. The 2015 figure for one firm, CMS, is the average of figures for Q1 and Q4.
The right-hand columns of Table A-2 derive actual 2014 income tax rates for each firm. The unweighted
and sales-weighted average tax rates for that year are 29 and 28 percent respectively.
I apply the 2014 sales-weighted average tax rate of 28 percent to the entire period 2005-2014 to obtaina series of estimated pre-tax ROA for the U.S. electric utility sector. Results appear in Tables A-1 andTable 6.
The list of firms, annual ROA and 2014 sales appear in Table A-2.

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Table 1

China and U.S. Electricity Price Comparison: Economy-wide and for Industrial Users, 2003-2014
2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

price for large-scale industry

434.69 455.09 484.98 499.04 508.51
426
457
485
516
523

532.1
536

530.72 571.22 583.16 625.2 635.49 647.05 643.33
555.32 617.72 718.61 770.41 652.47 655.86 643.97

Average On-grid Price

308.46

T&D Cost: RMB per MWH*

126.23 142.59 166.19 168.51 172.23 171.76 148.73 186.66 186.66 184.00
29.0
31.3
34.3
33.8
33.9
32.3
28.0
32.7
32.0
29.4

Unit prices and costs RMB per MWH
Retail price economy-wide average

Percent of retail priceExchange rate RMB/$ - MARKET

PPP

312.5

318.79 330.53 336.28 360.34 381.99 384.56

396.5

441.20 442.79 438.94 388.25
192.7
30.3

208.11 216.48
32.2
32.2

8.277

8.2768 8.1917 7.9718

7.604

6.9451

6.831

6.7695 6.4588 6.3125 6.1932 6.1581

6.228

2.695

2.804

2.988

3.159

3.132

3.309

3.506

3.466

2.822

2.844

3.524

3.545

3.517

China retail price ($ per MWH)

52.52
51.47

54.98
55.21

59.20
59.21

62.60
64.73

66.87
68.78

76.62
77.18

77.69
81.29

84.38
91.25

90.29 99.04 102.61 105.07 105.07
111.26 122.05 105.35 106.50 106.50

161.29158.07162.30162.98171.86171.86175.47181.43

170.18175.03168.44169.67169.45177.31

172.63186.68166.33204.97177.41218.62

179.26184.05183.98186.48185.61185.80

74.4
51.1

76.1
52.5

81.4
57.3

89
61.6

91.3
63.9

97.4
69.6

98.2
68.3

98.3
68.2

99
66.7

98.4
66.7

100.7
68.9

104.4
71

104.1
69.1

70.6

72.3

72.7

70.3

73.2

78.7

79.1

85.8

91.2

100.7

101.9

100.6

100.7 105.2 103.3 105.1 107.6 110.9 119.0 133.8 166.8 183.0 152.9 150.0

100.9
154.1

PPP Economy-wide

216.8

213.3

211.1

197.2

186.4

172.9

172.6

175.6

168.0

180.3

178.0

176.2

178.3

PPP large-scale industry

309.3

310.4

299.9

294.5

273.9

243.8

259.6

273.7

307.3

327.8

267.1

262.7

268.9

82.5
59.1

85.6
117.1

100.0
100.0

105.0
91.3

109.0
136.8

116.5
239.4

110.2
127.4

118.8
170.5

125.9
203.3

123.7
170.6

121.4
147.0

108.0
126.0

92.2
102.7

Economy-widelarge-scale industry
PPP Economy-wide
PPP large-scale industry
US retail price ($ per MWH)
Economy-wide
Industrial users

China average price, US=100
Economy-wide
Industrial
US industr
users**
price=100

Coal price indexes (2005=100)
China mine-mouth price
Asian market price*T&D Cost refers to unit cost for transmission and delivery of electricity.
** ratio of Chinese price for large industrial users to U.S. average for industrial users
Sources: U.S. data from U.S. EIA 2012 and 2014, Table 2.7 and 2015a, Table 2.4. Chinese price data for 2003-11 from Tang 2014, for 2013-2014 from State Energy Administration 2015.
for 2012: Chinese retail price and T&D cost from Chen 2015. Average on-grid price calculated as a residual. 2011/2012 price change for large-scaleindustry is assumed to be the same in percentage terms as the change in overall average retail prices.
for 2015: Chinese prices and T&D cost from Price Competition 2 2016, Price Competition 4 2016 and Price Competition 5 2016.
Exchange rates: Abstract 2014, p. 143; Abstract 2016, p. 167.
Coal prices: for Asian markets, from BP 2015, p. 30; 2015 figure based on price decline from US$77.89 to $63.52 between Dec. 2014 and Dec. 2015
See https://ww.quandl.com/data/BP/COAL_PRICES-Coal-Prices , accessed June 19, 2017.
For China, see Yearbook 2007, p. 333 (for 2003-2006); Price Yearbook 2011, p. 548 (for 2007-2010); Price Yearbook 2014, p. 573 (for 2010-2013);
information for 2014-2015 from www.stats.gov.cn, accessed March 23, 2016.
Source for China PPP conversions: https://data.oecd.org/conversion/purchasing-power-parities-ppp.htm, accessed February 6, 2017.

Table 2
China Electricity - Rising Scale of Plant and Equipment, 2000-2014
A. Thermal Power Generation Facilities (MW)

Category

Thermal Generation Facilities 2000
Number
Generating Capacityof Units
GW
Share (%)

Thermal Generation Facilities 2013
Number
Generating Capacityof Units
GW*
Share (%)

Thermal Generation Facilities 2015
Number
Generating Capacityof Units
GW
Share (%)

Total
600 MW and above
300-599200-299
100-199
Under 100

5235
22
291
232
376
4314

7223
529
919
246
468
5068

7526
609
1051
254
467
5145

282.9
13.2
96.8
47.4
43.6
81.9

100.0
4.7
34.2
16.8
15.4
29.0

851.6
349.2
298.1
51.8
65.2
87.4

100.0
41.0
35.0
6.1
7.7
10.3

970.3
416.4
346.0
54.9
64.0
89.0

B. Length of Power Transmission Lines 35 kv and higher (1000 km)
Transmission Lines 2000
LengthShare of(1000 km)Total %

Transmission Lines 2013
LengthShare of(1000 km)Total %

Transmission Lines 2015
LengthShare of(1000 km)Total %

Total

726.2

100.0

1554.0100.0

1696.8100.0

Under 220 kv

562.6

77.5

1010.065.01087.764.1

220 kv and up
of which: 1000 kv
±800
750
±600
500
330
220

163.6

22.5

26.8
8.7
128.1

3.7
1.2
17.6

544.0
1.9
6.9
12.7
1.4
146.2
24.1
339.1

35.0
0.1
0.4
0.8
0.1
9.4
1.6
21.8

609.1
3.1
10.6
15.7
1.3
169.8
26.8
380.1

35.9
0.2
0.6
0.9
0.1
10.0
1.6
22.4

* Total shown is sum of components; source showed a total of 848.9 GW
Sources: for 2000: China Electricity Yearbook 2001, pp. 668, 676.
for 2013: China Electricity Report 2014, pp. 53, 55.
for 2014: China Electricity Report 2015, pp. 61, 63.
for 2015: China Electricity Report 2016, pp. 67, 69.

100.0
42.9
35.7
5.7
6.6
9.2

Table 3

Technical Indicators for China's Electricity Sector, National Averages, 1965-2016
Generating Plants
Year

1965
1975
1985
1995
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016

Annual Operating Hours
All
ThermalPlantsPlants
n.a.
4920
n.a.
5197
5308
n.a.
5216
n.a.
5425
5865
5198
5612
5020
5344
4648
4885
4546
4865
4650
5031
4730
5294
4579
4965
4521
5012
4318
4739
3969
4329
3785
4165

Internal
Power use
All plants %Transmission &Distribution
Loss
%

6.98
6.23
6.42
6.78
5.87
5.93
5.83
5.90
5.76
5.43
5.39
5.10
5.05
4.83
5.90
n.a.

7.31
10.21
8.18
8.77
7.21
7.04
6.97
6.79
6.72
6.53
6.52
6.74
6.69
6.64
6.41
6.47

Standard Coal Consumption
grams per kWhGenerated
Delivered

477
450
398
379
343
342
332
322
320
312
308
305
302
300
297
n.a.

518
489
431
412
370
367
356
345
340
333
329
325
321
319
315
312

Aggregate Power Use
Share Shipped Across
Provinces
Districts(percent)
n.a.
n.a.
n.a.
n.a.
n.a.
n.a.
n.a.
n.a.
13.6
3.3
n.a.
2.9
11.8
3.0
12.9
3.1
14.3
3.3
14.0
3.5
13.3
3.6
14.4
4.1
14.8
4.6
15.6
5.4
15.3
5.6
15.3
5.7

Sources:
Except as noted, data for 1965-2014 are fromhttp://www.cec.org.cn/guihuayutongji/tongjxinxi/niandushuju/2015-11-30/146012.html , accessed December 19, 2015.

Thermal plant operating hours for 2005-2012 from Zhang Weirong (2016, p. 48); for 2013-2015 from Han 2016.
Data in the two right-hand columns calculated from information in Electricity Yearbook 2006, p. 39 and 2010, p. 34;
China Electricity Report 2015, pp. 74, 93; Electricity Databook 2011, p. 64; 2012, p. 58; 2014, p. 50
and 2015, pp. 41, 48, 50.
Data for 2015-2016 in the six left-hand columns are from Power Equipment Review 2017; Price Competition 1 2016;
Power Sector Preview 2016; Electricity Databook 2015, p. 6; and Electricity Outcome 2016.
n.a. indicates values for which the author has found no data.

Table 4

Power System Reliability and Access Compared: China, Brazil, India, Russian Federation, 2012-2014

Category

China
2012

Brazil
2009

India
2014

Russia2012

Number of outages in a typical monthDays to obtain an electricial connection
Percent of firms
Owning or sharing a generator

0.1
6.9

1.6
27.7

13.8
21.9

0.3
120.4

8.0

1.8

7.9
46.0

46.5
21.3

8.9
23.1

100.0

97.0

74.0

100.0

Identifying electricity supply as a major constraint
Rural electrification rate, 2013 (percent)

Sources: World Bank Enterprise Survey Data https://www.enterprisesurveys.org/data/exploreTopics/Infrastructure#all-countries--7
accessed March 31, 2016
Rural electrification: http://www.worldenergyoutlook.org/resources/energydevelopment/energyaccessdatabase/Russia access: http://data.worldbank.org/indicator/EG.ELC.ACCS.ZS

Table 5
China and U.S. Electricity Comparison for 2011
Unit

U.S.

Electricity Output

Bill. Kwh

4,100

China Power Sector
Value Index with
U.S. = 1
4,713
1.15

Power Generating Capacity

GW

1164.01062.50.91

Workers

1000s

395.7

2,589.0

6.54

Electricity output per man-year

MWH

10361

1820

0.18

Electricity output per GW of capacity

Bill. Kwh

3.5

4.4

1.26

Installed capacity per 1,000 workers

GW

2.94

0.41

0.14

66,8308,763
56,600

0.13

26.4

22.6
145.8

0.86

371.0

455.5
2941.8

1.23

7.1

5.0

0.70

Annual Average Wage

US$
RMB

Annual Wage Bill

Bill. US$Bill. RMB

Sales Revenue

Bill. US$Bill. RMB

Wages as percent of sales

percent

note: figures in italics converted at the average exchange rate for 2011 (Abstract 2016, p. 167):
US$1 = RMB
Sources:
output and installed capacity: see sources for Figure 1
labor and wages: Labor Yearbook 2012, Table 3.02b; U.S. Bureau of Labor Statistics 2011
sales revenue: Chinese data (adjusted to avoid double counting) from Table A-1;
U.S. data from U.S. EIA (2012), Table 1.1.

6.4588

Table 6

Profitability of Chinese and U.S. Electric Utilities Compared, 2005-2014
2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

China Electric Power Sector (Billion RMB)
Sales revenue - as reported [S]Sales revenue - net of double counting [S']Assets [A]Profit [π]Sales cost (= S' - π)
China sector profit margin (%) = 100*π/S'
Pre-tax return on assets (ROA, %) = 100*π/A

1774.61024.33937.5
115.8
908.6
11.30
2.94

2151.81260.84645.7168.9
1091.813.40
3.64

2636.81597.65348.5198.2
1399.412.41
3.71

2975.01799.46223.850.9
1748.62.83
0.82

3331.7
1994.46908.7
120.6
1873.86.05
1.75

4044.92514.97672.5196.8
2318.17.83
2.574716.52948.4
8382.1
192.7
2755.86.53
2.30

5127.43039.19207.3274.62764.59.03
2.98

5593.93310.410246.8
394.4
2916.011.91
3.85

5931.53510.810376.2
418.6
3092.2
11.92
4.03

5493.13396.111934.4457.4
2938.6
13.47
3.83

9.70
2.95

11.30
2.98

Major investor-owned U.S. electric utilities ($ Mill.)
Electric Utility Operating Revenues
Electric Utility Operating Costs
Electric Utility net operating income
U.S. electric utility profit margin (%)
U.S. pre-tax return on assets (ROA, %)*234,909
207,830
27,07911.53
3.60

246,736
218,445
28,291
11.47
4.43

240,864
213,076
27,78811.54
5.09

266,124
236,572
29,552
11.10
5.00

249,303219,544
29,75911.94
4.25

260,119
234,173
25,946
9.97
4.53

255,573
228,873
26,70010.45
4.56

249,166
220,722
28,444
11.42
3.05

257,718
227,483
30,235
11.73
3.38

271,832
240,643
31,18911.47
3.73

260,121228,366
31,755
12.21
3.37

11.35
4.09

11.47
4.25

Ratio: U.S. to Chinese electric utility profit margins
Ratio: U.S. to Chinese electric utility pretax ROA

1.02
1.22

0.86
1.22

0.93
1.37

3.93
6.12

1.97
2.43

1.27
1.77

1.60
1.98

1.26
1.02

0.98
0.88

0.96
0.93

0.91
0.88

1.43
1.89

1.02
1.30

Sources: Chinese data on sales revenue, assets and profits for 2005-2011 from Industrial Economy, various issues; for 2012 and 2013, from Industrial Statistics 2013 and 2014.
2014 data from China Electricity Report 2015, p. 136 (assets), p. 137 (profits)
2014 sales revenue S calculated from 2013 figure using annual change in retail price (Table 1) and 4.14% rise in nationwide power consumption (China Electricity Report 2015, p. 93).
2015 data for sales revenue （主营业务收入), assets and profits (营业利润）from Industrial Statistics 2015 i: 68, 99, and 129.
Adjusted sales [S'] to eliminate double counting from Appendix Table A-1.
U.S. data: ROA from Appendix Table A-2; other data from U.S. EIA 2015a, Table 8.3.
Note: the Chinese data exclude "below norm" firms with annual sales less than RMB 5 million (RMB 20 million beginning in 2011)
and, for some years, include firms that produce heat; both components are small.

Average MedianTable 7

Depreciation Allowances for China Electric Power Sector, 2005-2014(billion RMB and percent)Accumulated depreciation
Current year depreciation
Annual amount
Reported
Derived

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

1116.51324.21558.2

1927.92114.62517.22944.73324.03704.54284.34729.9

192.9

230.5
207.7

271.3
234.0

369.7

186.7

402.6

427.5

379.3

380.5

579.8

445.6

19.5

17.7
12.7

58.0

-49.5

115.7

6.2

-11.3

0.3

52.4

-23.1

14.7

11.1

10.3

14.0

6.6

7.9

8.8

9.0

10.6

Percent change from previous year
Depreciation
Reported
DerivedComparison: annual percent change inPower generating capacity
14.9

22.3

Sources:
Depreciation data for 2005-2011 from annual issues of Industrial Economy; for 2012-14, from Industrial Statistics 2013, 2014 and 2015, i: 79 in each case.
for 2015 from Industrial Statistics 2016, i: 69.
Annual change in capacity computed from sources underlying Figure 1; for 2015, from Electricity Databook 2015, p. 3.

Table 8

China Electricity Excess Cost Analysis, 2005-2014
Year
Industry
Share inElectricity
Use%

Percentage Cost Reduction Needed to Achieve
11 percent Profit/Sales Ratio
4.0 percent Return on Assets
Version [A] Version [B] Version [C] Version [A] Version [B] Version [C]Current
40% price
33% price
Current
40% price
33% price
Retailreduction
reduction
Retailreduction
reduction
Pricesforfor
Pricesforforindustry
all users
industry
all users

Cost Reduction to Attain 4.0% ROA(RMB billion)
Version [A] Version [B] Version [C]with
40% price
33% price
Current
reduction
reduction
Retailfor
for
Pricesindustry
all users

2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015

74.3
74.4
74.3
73.5
72.5
73.8
72.7
72.7
72.4
70.7
71.6

-0.3
-2.8
-1.6
8.4
5.3
3.4
4.8
2.2
-1.0
-1.1
-2.9

29.5
27.8
28.6
35.3
32.8
32.0
32.5
30.6
28.2
27.5
26.6

32.8
31.1
31.9
38.6
36.5
35.3
36.2
34.4
32.3
32.2
31.1

4.6
1.5
1.1
11.3
8.3
4.7
5.2
3.4
0.5
-0.1
0.7

38.1
35.9
35.0
41.6
39.2
36.8
36.3
35.4
33.4
32.0
33.8

41.8
39.7
38.8
45.3
43.4
40.5
40.5
39.7
38.0
37.4
38.8

41.7
16.9
15.7
198.1
155.8
110.1
142.6
93.7
15.5
-3.6
19.9

346.0
392.1
490.2
727.1
734.3
852.7
1000.5
978.0
973.6
983.8
992.1

379.8
432.9
542.9
791.9
813.9
940.0
1115.61096.61107.91148.61140.6

Average
Median

73.0
72.7

1.3
-0.3

30.1
29.5

33.9
32.8

3.8
3.4

36.1
35.9

40.4
39.7

73.3
41.7

770.0
852.7

864.6
940.0

Sources:
Calculated from data on adjusted sales S', profits ʋ͕ĂŶĚƐĂůĞƐĐŽƐƚƐ;с^ΖͲʋͿĨƌŽŵdĂďůĞϲ͘&ŽƌŝŶĚƵƐƚƌǇΖƐƐŚĂƌĞŝŶĞůĞĐƚƌŝĐŝƚǇƵƐĞ͕ƐĞĞEnergy Yearbook 2011, pp. 82-83 (for 2005-2010); China Electricity Report 2013, p. 79 (for 2011-2012); ibid. 2014, pp. 87-88 (for 2013)
Electricity Operations 2014 (for 2014); China Electricity Council 2015 (for 2015).

Table 9

China and U.S. Electricity Sectors: Employment and Proportion of Managers, 2014
Employment(1000s)Of which: managers
number(percent) (1000s)

China: Electric Power Sector

2600.1

Total for 16 large firms

2084.2

17.76

370.1

Five Big Generation Firms
Huaneng
DatangHuadian
Guodian
CPI

589.8
139.9
103.8
104.6
128.3
113.2

17.95
12.26
16.39
22.76
18.25
21.65

105.9
17.2
17.0
23.8
23.4
24.5

Two Major Grid Firms
State Grid
Southern Grid

1067.3
785.0
282.3

15.61
17.95
9.11

166.6
140.9
25.7

Regional Electricity Firms
Guangdong Power
Neimengu Power
Shaanxi Power

43.7
13.7
17.6
12.4

20.80
27.49
11.37
26.80

9.1
3.8
2.0
3.3

Construction Firms
China Electric Construction
China Energy Construction
Beijing Energy Investment

343.4
188.5
143.5
11.4

24.62
25.30
22.74
36.96

84.5
47.7
32.6
4.2

OthersChina National Nuclear
China General Nuclear
Shenhua Energy

40.0
8.9
29.8
1.3

9.79
14.24
7.69
27.49

3.9
1.3
2.3
0.4

U.S: Electricity Generation & Transmission

389.8

6.77

26.39

Sources:
China: sector-wide data: 2014 employment calculated from 2013 figure assuming the same percent change
for electric power as reported for combined employment in electricity-heat-water-gas on NBS web site,
consulted March 27, 2016.
Firm-level data from China Electricity Report 2015, p. 273.
U.S. data: U.S. Bureau of Labor Statistics 2014

Table A-1

Chinese Electricity Industry Sales Revenue Adjusted to Avoid Double Counting, 2005-2015
2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Reported Sales Revenue S (RMB Billion)

1774.62151.82636.82975.03331.74044.94716.55127.45593.95931.55493.1

Power output Q (Bill. KWh)

2,500.3

2,865.7

3,281.6

3,466.9

3,714.7

4,207.2

4,713.0

4,987.6

5,431.6

5,794.5

5739.9Self consumption share c (%)

5.87

5.93

5.83

5.90

5.76

5.43

5.39

5.10

5.05

4.83

5.9

Power supplied to Grid (Bill. KWh)
= .01*Q*(100-c)

2353.52695.83090.23262.3

3500.93978.54459.14733.25157.15514.75401.2On-grid price P (RMB per MWh)

318.79330.53336.28360.34381.99384.56396.5

441.20442.79438.94388.3

Double counting D (RMB Bill.)
D =.001*Q*(100-c)*P

750.3

891.0

1039.21175.61337.31530.01768.02088.32283.52420.62097.0Adjusted Sales Revenue S' without double counting
S' = S - D (RMB Billion)

1024.31260.81597.6

1799.4

1994.42514.92948.43039.13310.43510.83396.1

Reported industry-wide profit ʋ (RMB Bill)

115.8

168.9

198.2

50.9

120.6

196.8

192.7

274.6

394.4

418.6

457.4

Assets A (RMB billion)

3937.54645.75348.56223.86908.77672.58382.19207.310246.810376.2

11934.4

Profitability
Profit/Adjusted sales revenue (%) =100*ʋͬ^Ζ

11.30

13.40

12.41

2.83

6.05

7.83

6.53

9.03

11.91

11.92

13.47

2.94

3.64

3.71

0.82

1.75

2.57

2.30

2.98

3.85

4.03

3.83

ROA (%) = 100*ʋͬ^ŽƵƌĐĞƐ͗WŝƐƚŚĞĂǀĞƌĂŐĞŽŶͲŐƌŝĚƉƌŝĐĞĨƌŽŵdĂďůĞϭ͖ĨŽƌ^͕ĂŶĚʋ͕ƐĞĞdĂďůĞϲ͘
Q: Yearbook 2016, Table 13-13; for 2015, Electricity Databook 2015, p. 2.
c: Author's file "Basic Indicators" with data from http://www.cec.org.cn/guihuayutongji/tongjxinxi/niandushuju/2015-11-30/146012.html; for 2015, Price Competition 1 (2016).

Table A-2
Average Return on Assets (ROA) for U.S. Investor-owned Electric Utilities, 2005-2014
SymbolName

2014 Sales$ Billion

AEE
Ameren6.05
AEP
American Electric Power 17.02
CMS
CMS Energy
7.18
CNP
CenterPoint Energy
9.23
DDominion Resources
12.44
DTE
DTE Energy
12.3
DUK
Duke Energy
23.93
ED
Consolidated Edison
12.92
EIX
Edison International
13.41
ESEversource Energy
7.74
ETREntergy
12.49
EXC
Exelon27.43
FEFirstEnergy
15.05
LNT
Alliant Energy
3.35
NEE
NextEra Energy
17.02
PCG
PG&E
17.09
PEG
Public Service Enterprise 10.89
PNW
Pinnacle West Capital 3.49
PPL
PPL
11.5
SCG
SCANA
4.95
SO
Southern
18.47
SRE
Sempra Energy
11.04
WEC
WEC Energy Group5
XEL
Xcel Energy
11.69
SUM of 2014 Revenues
291.682014
revenueshare
0.02074191
0.05835162
0.02461602
0.03164427
0.04264948
0.0421695
0.08204196
0.04429512
0.04597504
0.02653593
0.0428209
0.09404142
0.05159764
0.01148519
0.05835162
0.05859161
0.03733544
0.01196517
0.03942677
0.01697065
0.06332282
0.0378497
0.01714207
0.04007817
1

Annual average ROA (%)
After-tax: unweighted

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Amounts in $1000s
2014 income
before tax
2015

3.40
2.30
-0.53
1.43
2.11
2.41
3.30
3.03
3.34
-2.05
3.04
2.16
2.74
-0.10
2.94
2.67
2.24
1.66
3.80
3.45
4.14
3.47
3.08
2.45

2.90
2.70
-0.50
2.49
2.71
1.84
3.02
2.86
3.32
3.99
3.66
3.65
3.98
4.26
3.72
2.88
2.53
2.87
4.39
3.21
3.80
4.83
2.93
2.63

3.07
2.78
-1.45
2.25
5.74
4.09
2.53
3.38
2.98
2.15
3.51
6.10
4.12
5.96
3.46
2.82
4.70
2.72
6.58
3.20
3.91
3.81
2.94
2.56

2.79
3.24
2.03
2.38
4.52
2.26
2.65
3.91
2.96
2.08
3.53
5.89
4.08
3.99
3.86
3.49
4.14
2.13
4.50
3.26
3.84
4.08
2.95
2.68

2.64
2.91
1.52
1.89
3.04
2.18
1.95
2.61
1.97
2.35
3.37
5.60
2.97
1.50
3.46
2.94
5.52
0.58
1.87
3.03
3.40
4.11
3.02
2.71

0.59
2.46
2.20
2.22
6.58
2.57
2.27
2.86
3.01
2.72
3.33
5.05
2.15
3.34
3.86
2.50
5.34
2.87
3.41
3.00
3.81
2.55
3.54
2.87

2.20
3.79
2.59
6.49
3.18
2.79
2.81
2.81
0.05
2.62
3.44
4.65
2.16
3.39
3.49
1.79
5.03
2.66
3.96
2.92
3.97
4.22
3.91
2.96

-4.25
2.36
2.28
1.87
0.65
2.33
2.00
2.84
-0.20
2.39
2.07
1.74
1.57
3.28
3.14
1.62
4.14
2.88
3.54
2.98
3.95
2.48
3.88
2.99

1.34
2.67
2.62
1.39
3.50
2.53
2.33
2.59
2.23
2.80
1.69
2.17
0.78
3.44
2.85
1.53
3.87
3.02
2.51
3.16
2.68
2.74
3.98
2.92

2.70
2.82
2.61
2.71
2.51
3.36
1.60
2.58
3.58
2.85
2.14
1.95
0.59
3.39
3.43
2.51
4.48
2.86
3.66
3.36
3.01
3.02
3.97
2.88

2.69
3.33
2.45
0.00
3.27
2.51
2.34
2.61
2.22
2.91
0.00
2.41
1.11
3.10
3.35
1.40
4.47
3.04
1.74
2.80
3.11
3.53
2.18
2.52

9700002490000
7290008850001780000
1280000
4130000
1660000
1980000
1300000
1550000
2490000
1710004400003650000
1800000
2460000
6444002130000
7860003010000
1520000
95000015500002014 incometax

2014 tax
rate

3770009420002500002740004520003640001670000
568000443000468300589600666000-4200044300
1180000
345000938000220700690000248000977000300000361700523820

0.39
0.38
0.34
0.31
0.25
0.28
0.40
0.34
0.22
0.36
0.38
0.27
-0.25
0.10
0.32
0.19
0.38
0.34
0.32
0.32
0.32
0.20
0.38
0.34

2.35

3.11

3.50

3.38

2.80

3.13

3.25

2.19

2.56

2.86

2.46

0.29

After tax: 2014 sales weights

2.59

3.19

3.67

3.60

3.06

3.26

3.28

2.19

2.43

2.69

2.43

0.28

Pre-tax ROA assuming 28% tax rate

3.60

4.43

5.09

5.00

4.25

4.53

4.56

3.05

3.38

3.73

3.37

Summary
After-tax ROA for 24 firms, 2005-2015
Average ROAMedian ROA
Coefficient of variation

Unweighted

Sales Wts

2.87
2.86
0.15

2.94
3.06
0.17

Figure 1. China Power Expansion in U.S. Perspective 1990-2016
300

250

200

150

100

50

0
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

China Power Use USA same year = 100
China Generating Capacity Increment - US Peak Year = 100

Figure 2

6000

Thermal Power Plant Construction Cost per KW vsNational Investment Cost Index, 1986-2012

400

350
5000
300
4000
250
3000

200
150

2000

1000

0

Unit Cost (RMB/Kw)

100

Investment Cost Index (Right axis)

50

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 20120

Map 1. China Energy Geography

Map 2. China’s Major Grid Systems

Source:https://www.google.com/imgres?imgurl=http://www.etransition.org/images/stategridmap.png&imgrefurl=http://www.etransition.org/images/programssmartgrid.h
tml&h=358&w=900&tbnid=wvwedD74z1wsLM:&docid=OGJWuLRExO8fcM&ei=7Br8VrVvzJiZAa3JrsAE&tbm=isch&ved=0ahUKEwi1laOhenLAhVMTCYKHa2kC0gQMwgdKAAwAA#h=358&w=900, accessed March 30, 2016