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Using natural gas generation to improve power system efficiency in China
Energy Policy 60 (2013) 116–121
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Using natural gas generation to improve power system efficiency in China Junfeng Hu a,b, Gabe Kwok c, Wang Xuan d, James H. Williams c, Fredrich Kahrl c,n a
Economics and Management School, North China Electric Power University, 2 Beinong Road, Changping District, Beijing 102206, China China Research Center for Public Policy, China Society of Economic Reform, 4 Zaojunmiao Road, Haidian District, Beijing 100081, China c Energy and Environmental Economics, Inc., 101 Montgomery Street, Suite 1600, San Francisco, CA 94104, USA d Regulatory Assistance Project, 50 State Street, Suite 3, Montpelier, VT 05602, USA b
H I G H L I G H T S
Using gas generation as a “capacity resource” in China could have multiple benefits. Benefits include lower total costs, improved efficiency for coal generators. Price reforms needed to support low capacity factor generation in China.
art ic l e i nf o
a b s t r a c t
Article history: Received 6 April 2013 Accepted 27 April 2013 Available online 29 May 2013
China's electricity sector faces the challenge of managing cost increases, improving reliability, and reducing its environmental footprint even as operating conditions become more complex due to increasing renewable penetration, growing peak demand, and falling system load factors. Addressing these challenges will require changes in how power generation is planned, priced, and dispatched in China. This is especially true for natural gas generation, which is likely to play an important role in power systems worldwide as a flexible generation resource. Although natural gas is commonly perceived to be economically uncompetitive with coal in China, these perceptions are based on analysis that fails to account for the different roles that natural gas generation plays in power systems—baseload, load following, and peaking generation. Our analysis shows that natural gas generation is already costeffective for meeting peak demand in China, resulting in improved capacity factors and heat rates for coal-fired generators and lower system costs. We find that the largest barrier to using natural gas for peaking generation in China is generation pricing, which could be addressed through modest reforms to support low capacity factor generation. & 2013 Elsevier Ltd. All rights reserved.
Keywords: Energy efficiency Electricity reform China
1. Introduction China's electricity sector will face three main challenges over the coming decades: (1) managing cost increases, (2) improving reliability, and (3) reducing its environmental footprint. At the same time, China's electricity system is undergoing major changes in operating conditions, including higher penetration of intermittent renewables, growth in peak demand, and declining system load factors (Kahrl et al., 2011). Meeting reliability and environmental goals for the sector at a reasonable cost, even as the system becomes more complex, will require a departure from the way that electricity generation has historically been planned, priced, and dispatched in China.
n
Corresponding author. Tel.: +1 4153915100. E-mail address: [email protected] (F. Kahrl).
0301-4215/$ - see front matter & 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.enpol.2013.04.066
Over the last two decades, the institutions governing generation planning, pricing, and dispatch in China have been very successful in encouraging investment in new power plants. From 2000 to 2011, China's installed generation capacity grew more than threefold (CEC, 2012), the most rapid expansion in history. However, these institutions have been less successful in encouraging least-cost operations and an economically efficient generation capacity mix. As a result, coal continues to dominate China's electricity system even when it is not economical. Focusing on natural gas generation, this paper shows how current approaches to generation planning and pricing in China result in inefficiencies in generation investment and operation. Although it is often argued that natural gas generation is not cost competitive in China (Skeer and Wang, 2006; CSEP, 2006; Li and Bai, 2010; Dong et al., 2012), these arguments are based on economic comparisons between natural gas and coal-fired generation that fail to account for the different roles that natural
H. Junfeng et al. / Energy Policy 60 (2013) 116–121
2. Background Current approaches to electricity generation planning, pricing, and dispatch in China, and the consequences of these for power system efficiency and costs, are best understood as historical legacies. From the beginning of China's economic reforms until the early 2000s, the electricity sector operated as a state-owned monopoly. Reforms in 2002 unbundled generation from transmission and distribution and were intended to create competitive markets for generation (Ma and He, 2008). However, rapid growth in electricity demand and persistent electricity shortages stalled the reform process (Williams and Kahrl, 2008). As a result, the organizational framework of China's electricity sector resembles a restructured electricity market, but generation planning, pricing, and dispatch have not substantively changed over the past three decades. Generation investment planning continues to be primarily done through centralized economic plans (Five-Year Plans) rather than through a local resource planning process (CEC, 2008, 2012). In the latter, a load serving entity determines a least-cost portfolio for reliably meeting forecasted demand with a combination of demand-side resources, transmission, and generation (CPUC, 2013). Generation prices in China are set administratively using a levelized cost approach that assumes a fixed number of fully loaded operating hours, as they have been for three decades (Kahrl et al., 2013). For instance, a coal unit priced on the basis of 5000 fully loaded hours with administratively set fixed costs of $85/kW-yr and variable costs of $0.060/kWh would have a wholesale generation price of $0.074/kWh (¼85/5000+0.06). If its actual operating hours are below 5000 h, then the fixed price of $0.074/kWh of output does not allow the unit to recover its investment costs. For natural gas units, which typically have their wholesale prices fixed using between 1000 and 2000 h, this approach does not support low capacity factor units, which may operate for significantly less than 1000 h at rated capacity. This approach to generation pricing leads to erroneous economic comparisons between coal and natural gas generation. Since 2004, China has used a benchmark (yuan/MWh) price for coal plants, based on the all-in cost of an advanced coal unit operating around 5000 h at rated capacity. Economic assessments of gas units, operating at 2000 h, are often done against this benchmark coal price (CSEP, 2006; Dong et al., 2012), which makes coal appear cost-effective for meeting demand in all hours, including for peak demand that only occurs for a few hundred hours a year. In the sections below we illustrate why this approach is incorrect. Since the 1980s, generator dispatch in China has been done through administrative allocation of operating hours across generators,
12,000 10,000
Load (MW)
gas generators can play in the power system. Using load duration and screening curves, we demonstrate how commonly used planning methods can better account for these roles. As a case study, we use these methods to estimate an optimal level of gasfired generation in one Chinese province. The paper concludes that natural gas generation is already costeffective for meeting peak demand in China. Using natural gas for peaking generation could improve capacity factors and heat rates for coal-fired generators, improving overall power system efficiency and reducing system costs. Currently, the largest barrier to using natural gas for peaking generation in China is wholesale generation pricing. The paper closes with a discussion of shortand longer-term options for reforming generation prices to support low capacity factor generation, drawing on international experience and considering political and economic constraints in China.
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Fig. 1. Estimated load duration curve for Guangxi Province, 2008.
rather than according to marginal cost (Kahrl et al., 2013). Under this administrative approach, dispatch organizations attempt to maintain a roughly equal number of hours across generators, which is intended to allow them to recover their investment costs. However, this also means that a new, advanced coal unit may be operated at the same capacity factor as an older, inefficient coal unit, or that hydropower generation may be curtailed to ensure sufficient operating hours for coal units. China's approach to generation planning, pricing, and dispatch leads to a number of inefficiencies, two of which are relevant here. First, coal generators are added to meet intermediate and peak demand, which means that some amount of coal capacity is needed for only a limited number of hours in the year. This practice reduces capacity factors for all coal units because of the equal hours approach to dispatch. The average capacity factor for coal units in China was just over 60% (5300 h at rated capacity) in 2011 (SERC, 2012). Second, without the ability to turn natural gas units on and off to follow load, most provinces in China ramp coal plants up and down to follow load, which reduces their efficiency and increases their emissions and maintenance costs (Kahrl et al., 2011).
3. Methods and data sources The methods used in this paper, load duration curves (LDCs) and screening curves, have long been employed for generation expansion planning, particularly in North America (Kahn, 1988; Stoft, 2002; Rothwell and Gómez, 2003), but as far as we know they have never been applied in China. 3.1. Load duration curves An LDC is an ordered ranking of load, from highest to lowest, typically over the course of a year. In many countries, hourly load data is publically available, but in China it is not and LDCs must be estimated. Fig. 1 shows an estimated LDC for southern China's Guangxi Province in 2008. This LDC was estimated using data on monthly peak and minimum loads and the empirically-based assumption that monthly LDCs in China tend to be approximately linear.1 An annual LDC can then be estimated by reordering the linear monthly LDCs over the year. To calculate load that must be met with thermal generation, our focus here, non-thermal generation must be subtracted from the LDC in Fig. 1. The Guangxi Power Grid Corporation's generation mix in 2008 comprised 49% coal and 51% hydropower (GPGC, 2008– 2009). Data on hourly and daily hydropower generation were not 1 This assumption was verified using non-publicly available 8760 h load data for two provinces in China.
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Fig. 2. Estimated net load duration curve for Guangxi Province, 2008.
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available; only monthly hydropower output data were published. The Guangxi Power Company reports that hydropower is used to provide baseload generation in high rainfall months (May–October) and used to follow load in drier months (November–April) (GPGC, 2008–2009). We estimate hourly hydropower output assuming that hydropower output is perfectly flat (i.e., is used as baseload) from May through October, and follows load perfectly from November to April. Subtracting estimated hourly hydropower output from the gross LDC in Fig. 1 gives the amount of load that must be met with coal generation in Guangxi. Reordering this curve from highest to lowest load hours produces a net LDC, shown in Fig. 2. The peak net load in Fig. 2 does not necessarily reflect the total amount of coal generation capacity required to reliably meet demand in Guangxi. China does not currently have a formal planning reserve requirement for grid companies, which would be set as a percentage above total system peak. For instance, Guangxi would have needed around 11.5 GW of qualified capacity in 2008 to meet a 15% planning reserve margin (PRM), a commonly used rule-of-thumb in North America (NERC, 2012).2 Assuming that 60% of Guangxi's 6.6 GW of hydropower could serve peak load,3 the total amount of coal capacity needed to satisfy the reserve requirement would have been 7.6 GW ( ¼11.5– 6.6 0.6). Guangxi's total coal capacity at the end of 2008 was 8.4 GW (GPGC, 2008–2009), equivalent to a PRM of 23%.
Fig. 3. Thermal generation screening curve for China (8760 h).
operating the technology. Crossover points between technologies show operating hour points in which one technology becomes more cost-effective than another, and the cost envelope along these points shows the least cost mix of resources. For instance, as shown in Fig. 4, which shows the cost envelope in the screening curve's first 1000 h, CTs are cost-effective as long as they are used to meet levels of thermal demand that occur for less than about 300 h out of the year. For levels of thermal demand that occur for more than 300 h, SPC units are cost-effective. Neither CCGTs nor SBC units are cost-competitive. The screening curve in Fig. 3 was developed using a detailed generation cost model for China that includes rigorous characterizations of fuel quality (heating value), technology parameters (gross and net heat rates), and non-capital and non-fuel costs (financing, taxes, insurance, labor, maintenance, pollution control and pollution fees).4 Table 1 shows the resulting capacity and energy costs for each of the four technologies in the screening curve. See Kahrl et al. (in press) for a more detailed discussion of these values and how and why they differ from values commonly seen in other countries.
4. Results 3.2. Screening curves Generation screening curves are used to examine generation investment decisions, by identifying the operating hour regions where different generation technologies are economical. Generation screening curves show the all-in (fixed plus variable) cost of owning and operating different generation technologies for a given number of hours in a year. Fig. 3 shows a generation screening curve for China that includes a simple cycle gas combustion turbine (CT), a combined cycle gas turbine (CCGT), a supercritical coal unit (SPC), and a subcritical coal unit (SBC). The screening curve's y-intercept is the total cost when the technology is used for zero hours, or the total fixed cost (yuan/ kW-yr). The slope of each line is the variable cost (yuan/kWh) of 2 For NERC regions without an explicit PRM, NERC applies a PRM of 15% to thermal systems and 10% to hydro systems to assess the region's resource adequacy (NERC, 2012). 3 In principle, hydropower is not capacity limited during peak demand periods and so would qualify for resource adequacy at its net capacity. In Guangxi's case, however, because hydropower is used as a baseload resource during months where system peak occurs it is likely less flexible. The 60% factor is approximately hydropower's average capacity factor (58%) in Guangxi during September 2008 (GPGC, 2008–2009).
In combination, LDCs and screening curves can be a useful tool for guiding investment decisions by approximating an optimal generation capacity mix, taking into account the tradeoff between fixed and variable costs among technology types and the system's load profile. By matching the cost envelope of generation technologies from the screening curve to its corresponding hours on a gross or net LDC, as in Fig. 5, the combined LDC–screening curve identifies the amount of capacity and energy that is optimally served by different generation technologies. Fig. 5 indicates that the least-cost mix of thermal generation capacity for Guangxi would have included 1.1 GW of CTs, or around 10% of estimated thermal peak. These CT units, however, would have been operated for 122 GWh, or 0.2% of the province's total MWh energy demand. If the implicit planning reserve margin was 23%, as described above, the optimal CT capacity would have been 3.0 GW, or nearly 30% of system peak. In reality, Guangxi likely had a surplus of coal capacity in 2008 due to poor planning and because its hydro-thermal operations were not optimized, but the 3.0 GW CT capacity estimate is a useful reference point because 4 The model is available online, in English and Chinese, and fully documented at http://ethree.com/public_projects/generation_cost_model_for_china.php. Many of the inputs to the model were drawn from Wang (2011).
H. Junfeng et al. / Energy Policy 60 (2013) 116–121
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Fig. 4. Thermal generation screening curve for China (first 1000 h).
Table 1 Estimated capacity and energy costs for four thermal generation technologies in China. Technology
Simple cycle gas combustion turbine (CT) Combined cycle gas turbine (CCGT) Supercritical coal (SPC) Subcritical coal (SBC)
Capacity cost
Energy cost
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$/kW h
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0.36 0.38
0.06 0.06
Fig. 5. Combined Net LDC and screening curve.
it reflects the amount of coal capacity that was effectively held as a planning reserve in 2008. The direct cost savings from shifting to a more optimal thermal capacity mix in Guangxi would, in the near term, be relatively modest. If Guangxi's total thermal generation mix were rebuilt anew to meet peak thermal demand in 2008, building a combination of CTs and SPC units rather than exclusively SPC units would lower total fixed costs by 5%, increase variable costs by 0.5%, and lower total costs (fixed+variable costs) by 0.5%.5 If capacity were built to meet the implicit 23% PRM, using CTs would lower fixed costs by 11%, increase variable costs by 0.5%, and lower total costs by 2%. A key reason that direct cost savings are relatively small is that the capacity cost ratio of natural gas units to advanced coal units in China, at around 0.7–0.8, is much higher than in other countries (Kahrl et al., in press). This ratio will fall as China begins to domestically manufacture gas turbines. An indirect benefit from using natural gas generation to provide capacity is its influence on capacity factors for coal-fired generators. The load factor of coal units — defined here as the ratio between average output and rated capacity — depends on the difference between maximum and minimum load. To follow load between its trough and peak, coal units must be ramped down to 50–70% of rated capacity in the evenings, then back to their rated capacity (or higher) in the afternoon. Because steam turbines have a fixed minimum heat requirement and a relatively constant parasitic load, heat rates (energy input per kWh output) increase nonlinearly as plant load factor decreases (IEA, 2010). At higher load factors (above 80%) this heat rate penalty is limited to a couple percent; at lower load factors (below 60%) this penalty can
5 This calculation uses capacity and energy prices from Table 1 and a generation-weighted average price for hydropower in Guangxi (154 yuan/MWh) to calculate hydropower costs, with prices from the Guigang Price Information Center, Online at: http://www.ggpi.gov.cn/shownews.asp?newsid=1276 (accessed 02/11) and hydropower generation data from GPGC (2008–2009).
rise to more than 10%.6 The thermal stress of ramping coal units to follow load also increases their maintenance costs and decreases their lifetimes (Kumar et al., 2012). Using gas units to provide capacity during periods of peak thermal demand reduces the maximum amount of coal capacity needed during those periods, and thus increases load factors. However, in Guangxi the largest peak-trough differences have generally not occurred in the same months as the system peak (GPGC, 2008–2009). This suggests that, while there will be some improvement in heat rates from reducing peak coal needs, reducing peak coal capacity would not increase the lowest load factors. The improvement in average heat rates is likely to be at most around 1–2%, which would lead to another 0.5–1% reduction in total system costs above the 0.5–2% reduction described above.7 A common argument against scaling up natural gas generation in China has been that China has limited natural gas reserves. For CTs used to meet peak demand, however, natural gas fuel requirements are relatively small because CTs only need to generate a limited amount of electricity. For instance, if gas peakers with 5% capacity factors (∼440 h fully loaded) accounted for 5% of China's total generation capacity in 2011 (CEC, 2012), total CT gas requirements would be around 6 billion m3, or around 7% of China's total natural gas consumption in 2009 (NBS, 2011).8 The Guangxi example is intended to be illustrative; the results apply generally. As long as there is a distinct thermal peak demand or as long as there is a thermal capacity reserve requirement, and as long as the fixed costs of natural gas units are lower than the fixed costs of coal units, building some amount of natural gas generation will lower total system costs. In China, actual benefits
6 These estimates are based on observations of heat input and electricity output from coal-fired power plants in the U.S. (EPA, 2012). 7 The percent reduction in total system costs from an improvement in coal generator heat rates is %ΔTC ¼ [(1−α)β−(1−β)], where TC is total system costs, α is the percentage reduction in heat rates, and β is the share of coal fuel costs in total system costs. 8 Assuming a gross heat rate of 10.8 GJ/kWh (368 kgce/MWh) and a 36 MJ/m3 lower heating value for gas.
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will vary across provinces, depending on factors such as the existing thermal and hydro capacity mix, load shape, and the level of reliability desired (e.g., through a PRM). The benefits of using natural gas generation to provide capacity and flexibility, thereby reducing coal capacity needs, would be particularly apparent in regions in China that do not have abundant hydropower resources. The results above only show short-run benefits. In the longrun, the benefits of using natural gas to provide capacity and flexibility will increase as demand becomes peakier (system load factors decrease) and variable generation, such as wind and solar, makes up a larger share of generation capacity. Natural gas generation is one of a number of complementary measures that could provide lower cost capacity and greater system flexibility in the longer term. Additional measures include hydro-thermal optimization, energy efficiency and demand response, and storage.
Fixed cost recovery mechanism Fixed cost payment
Energy-only
Capacity Payment
mechanism Administratively set
China
Argentina, Chile, Colombia, Peru, South Korea, Spain
Bilateral market
California ISO (CAISO), Southwest Power Pool (SPP)
Centralized market
Alberta, Australia, Electric
Brazil, PJM, ISO-New England
Reliability Council of Texas
(ISO-NE), New York ISO
(ERCOT), New Zealand,
(NYISO), Midwest ISO (MISO)
Norway, Ontario Independent Electricity System Operator
5. Discussion Supporting low capacity factor natural gas generation in China would require innovations in generation pricing to allow generators to recover their fixed costs. Under the current system, where wholesale generation prices for gas units are set on an energy-only (yuan/MWh) basis using a relatively high capacity factor, fixed cost recovery is not possible. Thus generators lack incentives to invest in natural gas generation even though, as we illustrate here, building a significant amount of gas generation would lower total system costs and increase system efficiency. Electricity price reforms in China lie at the politicized intersection of generator, grid company, and customer interests, and as a consequence have been stalled for more than a decade. Major changes in either wholesale or retail prices in the near term are unlikely. However, there are options for creating price mechanisms that would support low capacity factor gas units in the near term that would also be consistent with the direction of longer-term electricity price reforms. Making incremental improvements in the efficiency of China's power system need not be held captive to delays in implementing broader electricity sector reforms. For natural gas pricing, one such option would be to use the existing mechanism for compensating generators for providing ancillary services. The term ‘load following’ has a different connotation in China than in most countries, because in the former most load following is done by ramping coal units up and down. Load following is thus considered an ancillary service in China. In keeping with that definition, one avenue for allowing fixed cost recovery for low capacity factor gas units would be to establish a two-part price as a new category under the ancillary services tariff, paying gas generators an energy price tied to a base year and price index and a capacity price tied to their availability. This approach has the benefit of being easier to implement and would not adversely affect dispatch incentives because the variable costs of natural gas plants are higher than the current benchmark price for coal plants. A two-part capacity and energy price for gas units would also be consistent with the nearer-term direction for China's reforms to generation prices. Fig. 6 shows a typology of the six main approaches to fixed cost recovery in a number of electricity jurisdictions around the world. Centralized energy-only markets are not a suitable near-term option for a high-growth economy like China because they lead to volatile prices, cyclical and inadequate generation investment, and require sophisticated regulatory institutions to mitigate market power (Joskow, 2008; Tishler et al., 2008; Pfeifenberger et al., 2009). Bilateral and centralized capacity markets require a capacity reserve requirement on load serving entities to determine competitive prices, but China does not currently have a resource adequacy process that
(IESO), UK
Fig. 6. Six main price discovery and payment mechanisms for generator fixed cost recovery.
sets reserve requirements on grid companies. The most feasible reform option for China in the near term would be an administratively set capacity and energy price for all generating units, as a transition to competitive generation pricing in the longer term. 6. Conclusions The institutions governing generation planning, pricing, and dispatch in China have been very successful in encouraging investment in new generation, but less successful in encouraging an efficient capacity mix and efficient operations. As a result, China currently has too much coal capacity, relative to economically optimal levels, and low capacity factors for those coal units. This paper examined how using natural gas generation could improve power system efficiency in China, by providing a capacity resource during peak demand periods and reducing the amount of coal generation implicitly carried as a capacity reserve. Using an illustrative example that used a load duration curve from Guangxi Province and screening curves based on a generation cost model for China, we showed that using natural gas generation as a capacity resource would lower total system costs. This conclusion challenges the conventional wisdom that natural gas generation is currently not cost-effective in China. We argued that the optimal level of natural gas capacity in China is likely to be significant, depending on province, but the actual natural gas fuel requirements are not significant because these gas “peakers” would only operate in a limited number of hours. China's current pricing system does not support low capacity factor natural gas units. Encouraging investment in these units requires a strategy to allow them to recover their fixed costs. Since generation price reform in China is political, and broader reforms will take time, a nearer-term solution would be to implement a two-part capacity and energy price for low capacity factor gas units under the existing ancillary services mechanism. This approach would be consistent with the nearer- and longer-term direction for reforms in China's power sector.
Acknowledgments This paper was supported through funding from the Regulatory Assistance Project and the Humanity and Social Science Foundation of the Ministry of Education of China.
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Contents lists available at SciVerse ScienceDirect
Energy Policy journal homepage: www.elsevier.com/locate/enpol
Using natural gas generation to improve power system efficiency in China Junfeng Hu a,b, Gabe Kwok c, Wang Xuan d, James H. Williams c, Fredrich Kahrl c,n a
Economics and Management School, North China Electric Power University, 2 Beinong Road, Changping District, Beijing 102206, China China Research Center for Public Policy, China Society of Economic Reform, 4 Zaojunmiao Road, Haidian District, Beijing 100081, China c Energy and Environmental Economics, Inc., 101 Montgomery Street, Suite 1600, San Francisco, CA 94104, USA d Regulatory Assistance Project, 50 State Street, Suite 3, Montpelier, VT 05602, USA b
H I G H L I G H T S
Using gas generation as a “capacity resource” in China could have multiple benefits. Benefits include lower total costs, improved efficiency for coal generators. Price reforms needed to support low capacity factor generation in China.
art ic l e i nf o
a b s t r a c t
Article history: Received 6 April 2013 Accepted 27 April 2013 Available online 29 May 2013
China's electricity sector faces the challenge of managing cost increases, improving reliability, and reducing its environmental footprint even as operating conditions become more complex due to increasing renewable penetration, growing peak demand, and falling system load factors. Addressing these challenges will require changes in how power generation is planned, priced, and dispatched in China. This is especially true for natural gas generation, which is likely to play an important role in power systems worldwide as a flexible generation resource. Although natural gas is commonly perceived to be economically uncompetitive with coal in China, these perceptions are based on analysis that fails to account for the different roles that natural gas generation plays in power systems—baseload, load following, and peaking generation. Our analysis shows that natural gas generation is already costeffective for meeting peak demand in China, resulting in improved capacity factors and heat rates for coal-fired generators and lower system costs. We find that the largest barrier to using natural gas for peaking generation in China is generation pricing, which could be addressed through modest reforms to support low capacity factor generation. & 2013 Elsevier Ltd. All rights reserved.
Keywords: Energy efficiency Electricity reform China
1. Introduction China's electricity sector will face three main challenges over the coming decades: (1) managing cost increases, (2) improving reliability, and (3) reducing its environmental footprint. At the same time, China's electricity system is undergoing major changes in operating conditions, including higher penetration of intermittent renewables, growth in peak demand, and declining system load factors (Kahrl et al., 2011). Meeting reliability and environmental goals for the sector at a reasonable cost, even as the system becomes more complex, will require a departure from the way that electricity generation has historically been planned, priced, and dispatched in China.
n
Corresponding author. Tel.: +1 4153915100. E-mail address: [email protected] (F. Kahrl).
0301-4215/$ - see front matter & 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.enpol.2013.04.066
Over the last two decades, the institutions governing generation planning, pricing, and dispatch in China have been very successful in encouraging investment in new power plants. From 2000 to 2011, China's installed generation capacity grew more than threefold (CEC, 2012), the most rapid expansion in history. However, these institutions have been less successful in encouraging least-cost operations and an economically efficient generation capacity mix. As a result, coal continues to dominate China's electricity system even when it is not economical. Focusing on natural gas generation, this paper shows how current approaches to generation planning and pricing in China result in inefficiencies in generation investment and operation. Although it is often argued that natural gas generation is not cost competitive in China (Skeer and Wang, 2006; CSEP, 2006; Li and Bai, 2010; Dong et al., 2012), these arguments are based on economic comparisons between natural gas and coal-fired generation that fail to account for the different roles that natural
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2. Background Current approaches to electricity generation planning, pricing, and dispatch in China, and the consequences of these for power system efficiency and costs, are best understood as historical legacies. From the beginning of China's economic reforms until the early 2000s, the electricity sector operated as a state-owned monopoly. Reforms in 2002 unbundled generation from transmission and distribution and were intended to create competitive markets for generation (Ma and He, 2008). However, rapid growth in electricity demand and persistent electricity shortages stalled the reform process (Williams and Kahrl, 2008). As a result, the organizational framework of China's electricity sector resembles a restructured electricity market, but generation planning, pricing, and dispatch have not substantively changed over the past three decades. Generation investment planning continues to be primarily done through centralized economic plans (Five-Year Plans) rather than through a local resource planning process (CEC, 2008, 2012). In the latter, a load serving entity determines a least-cost portfolio for reliably meeting forecasted demand with a combination of demand-side resources, transmission, and generation (CPUC, 2013). Generation prices in China are set administratively using a levelized cost approach that assumes a fixed number of fully loaded operating hours, as they have been for three decades (Kahrl et al., 2013). For instance, a coal unit priced on the basis of 5000 fully loaded hours with administratively set fixed costs of $85/kW-yr and variable costs of $0.060/kWh would have a wholesale generation price of $0.074/kWh (¼85/5000+0.06). If its actual operating hours are below 5000 h, then the fixed price of $0.074/kWh of output does not allow the unit to recover its investment costs. For natural gas units, which typically have their wholesale prices fixed using between 1000 and 2000 h, this approach does not support low capacity factor units, which may operate for significantly less than 1000 h at rated capacity. This approach to generation pricing leads to erroneous economic comparisons between coal and natural gas generation. Since 2004, China has used a benchmark (yuan/MWh) price for coal plants, based on the all-in cost of an advanced coal unit operating around 5000 h at rated capacity. Economic assessments of gas units, operating at 2000 h, are often done against this benchmark coal price (CSEP, 2006; Dong et al., 2012), which makes coal appear cost-effective for meeting demand in all hours, including for peak demand that only occurs for a few hundred hours a year. In the sections below we illustrate why this approach is incorrect. Since the 1980s, generator dispatch in China has been done through administrative allocation of operating hours across generators,
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gas generators can play in the power system. Using load duration and screening curves, we demonstrate how commonly used planning methods can better account for these roles. As a case study, we use these methods to estimate an optimal level of gasfired generation in one Chinese province. The paper concludes that natural gas generation is already costeffective for meeting peak demand in China. Using natural gas for peaking generation could improve capacity factors and heat rates for coal-fired generators, improving overall power system efficiency and reducing system costs. Currently, the largest barrier to using natural gas for peaking generation in China is wholesale generation pricing. The paper closes with a discussion of shortand longer-term options for reforming generation prices to support low capacity factor generation, drawing on international experience and considering political and economic constraints in China.
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Fig. 1. Estimated load duration curve for Guangxi Province, 2008.
rather than according to marginal cost (Kahrl et al., 2013). Under this administrative approach, dispatch organizations attempt to maintain a roughly equal number of hours across generators, which is intended to allow them to recover their investment costs. However, this also means that a new, advanced coal unit may be operated at the same capacity factor as an older, inefficient coal unit, or that hydropower generation may be curtailed to ensure sufficient operating hours for coal units. China's approach to generation planning, pricing, and dispatch leads to a number of inefficiencies, two of which are relevant here. First, coal generators are added to meet intermediate and peak demand, which means that some amount of coal capacity is needed for only a limited number of hours in the year. This practice reduces capacity factors for all coal units because of the equal hours approach to dispatch. The average capacity factor for coal units in China was just over 60% (5300 h at rated capacity) in 2011 (SERC, 2012). Second, without the ability to turn natural gas units on and off to follow load, most provinces in China ramp coal plants up and down to follow load, which reduces their efficiency and increases their emissions and maintenance costs (Kahrl et al., 2011).
3. Methods and data sources The methods used in this paper, load duration curves (LDCs) and screening curves, have long been employed for generation expansion planning, particularly in North America (Kahn, 1988; Stoft, 2002; Rothwell and Gómez, 2003), but as far as we know they have never been applied in China. 3.1. Load duration curves An LDC is an ordered ranking of load, from highest to lowest, typically over the course of a year. In many countries, hourly load data is publically available, but in China it is not and LDCs must be estimated. Fig. 1 shows an estimated LDC for southern China's Guangxi Province in 2008. This LDC was estimated using data on monthly peak and minimum loads and the empirically-based assumption that monthly LDCs in China tend to be approximately linear.1 An annual LDC can then be estimated by reordering the linear monthly LDCs over the year. To calculate load that must be met with thermal generation, our focus here, non-thermal generation must be subtracted from the LDC in Fig. 1. The Guangxi Power Grid Corporation's generation mix in 2008 comprised 49% coal and 51% hydropower (GPGC, 2008– 2009). Data on hourly and daily hydropower generation were not 1 This assumption was verified using non-publicly available 8760 h load data for two provinces in China.
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Fig. 2. Estimated net load duration curve for Guangxi Province, 2008.
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available; only monthly hydropower output data were published. The Guangxi Power Company reports that hydropower is used to provide baseload generation in high rainfall months (May–October) and used to follow load in drier months (November–April) (GPGC, 2008–2009). We estimate hourly hydropower output assuming that hydropower output is perfectly flat (i.e., is used as baseload) from May through October, and follows load perfectly from November to April. Subtracting estimated hourly hydropower output from the gross LDC in Fig. 1 gives the amount of load that must be met with coal generation in Guangxi. Reordering this curve from highest to lowest load hours produces a net LDC, shown in Fig. 2. The peak net load in Fig. 2 does not necessarily reflect the total amount of coal generation capacity required to reliably meet demand in Guangxi. China does not currently have a formal planning reserve requirement for grid companies, which would be set as a percentage above total system peak. For instance, Guangxi would have needed around 11.5 GW of qualified capacity in 2008 to meet a 15% planning reserve margin (PRM), a commonly used rule-of-thumb in North America (NERC, 2012).2 Assuming that 60% of Guangxi's 6.6 GW of hydropower could serve peak load,3 the total amount of coal capacity needed to satisfy the reserve requirement would have been 7.6 GW ( ¼11.5– 6.6 0.6). Guangxi's total coal capacity at the end of 2008 was 8.4 GW (GPGC, 2008–2009), equivalent to a PRM of 23%.
Fig. 3. Thermal generation screening curve for China (8760 h).
operating the technology. Crossover points between technologies show operating hour points in which one technology becomes more cost-effective than another, and the cost envelope along these points shows the least cost mix of resources. For instance, as shown in Fig. 4, which shows the cost envelope in the screening curve's first 1000 h, CTs are cost-effective as long as they are used to meet levels of thermal demand that occur for less than about 300 h out of the year. For levels of thermal demand that occur for more than 300 h, SPC units are cost-effective. Neither CCGTs nor SBC units are cost-competitive. The screening curve in Fig. 3 was developed using a detailed generation cost model for China that includes rigorous characterizations of fuel quality (heating value), technology parameters (gross and net heat rates), and non-capital and non-fuel costs (financing, taxes, insurance, labor, maintenance, pollution control and pollution fees).4 Table 1 shows the resulting capacity and energy costs for each of the four technologies in the screening curve. See Kahrl et al. (in press) for a more detailed discussion of these values and how and why they differ from values commonly seen in other countries.
4. Results 3.2. Screening curves Generation screening curves are used to examine generation investment decisions, by identifying the operating hour regions where different generation technologies are economical. Generation screening curves show the all-in (fixed plus variable) cost of owning and operating different generation technologies for a given number of hours in a year. Fig. 3 shows a generation screening curve for China that includes a simple cycle gas combustion turbine (CT), a combined cycle gas turbine (CCGT), a supercritical coal unit (SPC), and a subcritical coal unit (SBC). The screening curve's y-intercept is the total cost when the technology is used for zero hours, or the total fixed cost (yuan/ kW-yr). The slope of each line is the variable cost (yuan/kWh) of 2 For NERC regions without an explicit PRM, NERC applies a PRM of 15% to thermal systems and 10% to hydro systems to assess the region's resource adequacy (NERC, 2012). 3 In principle, hydropower is not capacity limited during peak demand periods and so would qualify for resource adequacy at its net capacity. In Guangxi's case, however, because hydropower is used as a baseload resource during months where system peak occurs it is likely less flexible. The 60% factor is approximately hydropower's average capacity factor (58%) in Guangxi during September 2008 (GPGC, 2008–2009).
In combination, LDCs and screening curves can be a useful tool for guiding investment decisions by approximating an optimal generation capacity mix, taking into account the tradeoff between fixed and variable costs among technology types and the system's load profile. By matching the cost envelope of generation technologies from the screening curve to its corresponding hours on a gross or net LDC, as in Fig. 5, the combined LDC–screening curve identifies the amount of capacity and energy that is optimally served by different generation technologies. Fig. 5 indicates that the least-cost mix of thermal generation capacity for Guangxi would have included 1.1 GW of CTs, or around 10% of estimated thermal peak. These CT units, however, would have been operated for 122 GWh, or 0.2% of the province's total MWh energy demand. If the implicit planning reserve margin was 23%, as described above, the optimal CT capacity would have been 3.0 GW, or nearly 30% of system peak. In reality, Guangxi likely had a surplus of coal capacity in 2008 due to poor planning and because its hydro-thermal operations were not optimized, but the 3.0 GW CT capacity estimate is a useful reference point because 4 The model is available online, in English and Chinese, and fully documented at http://ethree.com/public_projects/generation_cost_model_for_china.php. Many of the inputs to the model were drawn from Wang (2011).
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Fig. 4. Thermal generation screening curve for China (first 1000 h).
Table 1 Estimated capacity and energy costs for four thermal generation technologies in China. Technology
Simple cycle gas combustion turbine (CT) Combined cycle gas turbine (CCGT) Supercritical coal (SPC) Subcritical coal (SBC)
Capacity cost
Energy cost
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$/kW h
405
64
0.79
0.13
489
78
0.53
0.08
530 623
84 99
0.36 0.38
0.06 0.06
Fig. 5. Combined Net LDC and screening curve.
it reflects the amount of coal capacity that was effectively held as a planning reserve in 2008. The direct cost savings from shifting to a more optimal thermal capacity mix in Guangxi would, in the near term, be relatively modest. If Guangxi's total thermal generation mix were rebuilt anew to meet peak thermal demand in 2008, building a combination of CTs and SPC units rather than exclusively SPC units would lower total fixed costs by 5%, increase variable costs by 0.5%, and lower total costs (fixed+variable costs) by 0.5%.5 If capacity were built to meet the implicit 23% PRM, using CTs would lower fixed costs by 11%, increase variable costs by 0.5%, and lower total costs by 2%. A key reason that direct cost savings are relatively small is that the capacity cost ratio of natural gas units to advanced coal units in China, at around 0.7–0.8, is much higher than in other countries (Kahrl et al., in press). This ratio will fall as China begins to domestically manufacture gas turbines. An indirect benefit from using natural gas generation to provide capacity is its influence on capacity factors for coal-fired generators. The load factor of coal units — defined here as the ratio between average output and rated capacity — depends on the difference between maximum and minimum load. To follow load between its trough and peak, coal units must be ramped down to 50–70% of rated capacity in the evenings, then back to their rated capacity (or higher) in the afternoon. Because steam turbines have a fixed minimum heat requirement and a relatively constant parasitic load, heat rates (energy input per kWh output) increase nonlinearly as plant load factor decreases (IEA, 2010). At higher load factors (above 80%) this heat rate penalty is limited to a couple percent; at lower load factors (below 60%) this penalty can
5 This calculation uses capacity and energy prices from Table 1 and a generation-weighted average price for hydropower in Guangxi (154 yuan/MWh) to calculate hydropower costs, with prices from the Guigang Price Information Center, Online at: http://www.ggpi.gov.cn/shownews.asp?newsid=1276 (accessed 02/11) and hydropower generation data from GPGC (2008–2009).
rise to more than 10%.6 The thermal stress of ramping coal units to follow load also increases their maintenance costs and decreases their lifetimes (Kumar et al., 2012). Using gas units to provide capacity during periods of peak thermal demand reduces the maximum amount of coal capacity needed during those periods, and thus increases load factors. However, in Guangxi the largest peak-trough differences have generally not occurred in the same months as the system peak (GPGC, 2008–2009). This suggests that, while there will be some improvement in heat rates from reducing peak coal needs, reducing peak coal capacity would not increase the lowest load factors. The improvement in average heat rates is likely to be at most around 1–2%, which would lead to another 0.5–1% reduction in total system costs above the 0.5–2% reduction described above.7 A common argument against scaling up natural gas generation in China has been that China has limited natural gas reserves. For CTs used to meet peak demand, however, natural gas fuel requirements are relatively small because CTs only need to generate a limited amount of electricity. For instance, if gas peakers with 5% capacity factors (∼440 h fully loaded) accounted for 5% of China's total generation capacity in 2011 (CEC, 2012), total CT gas requirements would be around 6 billion m3, or around 7% of China's total natural gas consumption in 2009 (NBS, 2011).8 The Guangxi example is intended to be illustrative; the results apply generally. As long as there is a distinct thermal peak demand or as long as there is a thermal capacity reserve requirement, and as long as the fixed costs of natural gas units are lower than the fixed costs of coal units, building some amount of natural gas generation will lower total system costs. In China, actual benefits
6 These estimates are based on observations of heat input and electricity output from coal-fired power plants in the U.S. (EPA, 2012). 7 The percent reduction in total system costs from an improvement in coal generator heat rates is %ΔTC ¼ [(1−α)β−(1−β)], where TC is total system costs, α is the percentage reduction in heat rates, and β is the share of coal fuel costs in total system costs. 8 Assuming a gross heat rate of 10.8 GJ/kWh (368 kgce/MWh) and a 36 MJ/m3 lower heating value for gas.
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will vary across provinces, depending on factors such as the existing thermal and hydro capacity mix, load shape, and the level of reliability desired (e.g., through a PRM). The benefits of using natural gas generation to provide capacity and flexibility, thereby reducing coal capacity needs, would be particularly apparent in regions in China that do not have abundant hydropower resources. The results above only show short-run benefits. In the longrun, the benefits of using natural gas to provide capacity and flexibility will increase as demand becomes peakier (system load factors decrease) and variable generation, such as wind and solar, makes up a larger share of generation capacity. Natural gas generation is one of a number of complementary measures that could provide lower cost capacity and greater system flexibility in the longer term. Additional measures include hydro-thermal optimization, energy efficiency and demand response, and storage.
Fixed cost recovery mechanism Fixed cost payment
Energy-only
Capacity Payment
mechanism Administratively set
China
Argentina, Chile, Colombia, Peru, South Korea, Spain
Bilateral market
California ISO (CAISO), Southwest Power Pool (SPP)
Centralized market
Alberta, Australia, Electric
Brazil, PJM, ISO-New England
Reliability Council of Texas
(ISO-NE), New York ISO
(ERCOT), New Zealand,
(NYISO), Midwest ISO (MISO)
Norway, Ontario Independent Electricity System Operator
5. Discussion Supporting low capacity factor natural gas generation in China would require innovations in generation pricing to allow generators to recover their fixed costs. Under the current system, where wholesale generation prices for gas units are set on an energy-only (yuan/MWh) basis using a relatively high capacity factor, fixed cost recovery is not possible. Thus generators lack incentives to invest in natural gas generation even though, as we illustrate here, building a significant amount of gas generation would lower total system costs and increase system efficiency. Electricity price reforms in China lie at the politicized intersection of generator, grid company, and customer interests, and as a consequence have been stalled for more than a decade. Major changes in either wholesale or retail prices in the near term are unlikely. However, there are options for creating price mechanisms that would support low capacity factor gas units in the near term that would also be consistent with the direction of longer-term electricity price reforms. Making incremental improvements in the efficiency of China's power system need not be held captive to delays in implementing broader electricity sector reforms. For natural gas pricing, one such option would be to use the existing mechanism for compensating generators for providing ancillary services. The term ‘load following’ has a different connotation in China than in most countries, because in the former most load following is done by ramping coal units up and down. Load following is thus considered an ancillary service in China. In keeping with that definition, one avenue for allowing fixed cost recovery for low capacity factor gas units would be to establish a two-part price as a new category under the ancillary services tariff, paying gas generators an energy price tied to a base year and price index and a capacity price tied to their availability. This approach has the benefit of being easier to implement and would not adversely affect dispatch incentives because the variable costs of natural gas plants are higher than the current benchmark price for coal plants. A two-part capacity and energy price for gas units would also be consistent with the nearer-term direction for China's reforms to generation prices. Fig. 6 shows a typology of the six main approaches to fixed cost recovery in a number of electricity jurisdictions around the world. Centralized energy-only markets are not a suitable near-term option for a high-growth economy like China because they lead to volatile prices, cyclical and inadequate generation investment, and require sophisticated regulatory institutions to mitigate market power (Joskow, 2008; Tishler et al., 2008; Pfeifenberger et al., 2009). Bilateral and centralized capacity markets require a capacity reserve requirement on load serving entities to determine competitive prices, but China does not currently have a resource adequacy process that
(IESO), UK
Fig. 6. Six main price discovery and payment mechanisms for generator fixed cost recovery.
sets reserve requirements on grid companies. The most feasible reform option for China in the near term would be an administratively set capacity and energy price for all generating units, as a transition to competitive generation pricing in the longer term. 6. Conclusions The institutions governing generation planning, pricing, and dispatch in China have been very successful in encouraging investment in new generation, but less successful in encouraging an efficient capacity mix and efficient operations. As a result, China currently has too much coal capacity, relative to economically optimal levels, and low capacity factors for those coal units. This paper examined how using natural gas generation could improve power system efficiency in China, by providing a capacity resource during peak demand periods and reducing the amount of coal generation implicitly carried as a capacity reserve. Using an illustrative example that used a load duration curve from Guangxi Province and screening curves based on a generation cost model for China, we showed that using natural gas generation as a capacity resource would lower total system costs. This conclusion challenges the conventional wisdom that natural gas generation is currently not cost-effective in China. We argued that the optimal level of natural gas capacity in China is likely to be significant, depending on province, but the actual natural gas fuel requirements are not significant because these gas “peakers” would only operate in a limited number of hours. China's current pricing system does not support low capacity factor natural gas units. Encouraging investment in these units requires a strategy to allow them to recover their fixed costs. Since generation price reform in China is political, and broader reforms will take time, a nearer-term solution would be to implement a two-part capacity and energy price for low capacity factor gas units under the existing ancillary services mechanism. This approach would be consistent with the nearer- and longer-term direction for reforms in China's power sector.
Acknowledgments This paper was supported through funding from the Regulatory Assistance Project and the Humanity and Social Science Foundation of the Ministry of Education of China.
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