Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

TOPIC PAPER #4

ELECTRIC GENERATION

EFFICIENCY

On July 18, 2007, The National Petroleum Council (NPC) in approving its

report, Facing the Hard Truths about Energy, also approved the making

available of certain materials used in the study process, including detailed,

specific subject matter papers prepared or used by the Task Groups and

their Subgroups. These Topic Papers were working documents that were

part of the analyses that led to development of the summary results

presented in the report’s Executive Summary and Chapters.

These Topic Papers represent the views and conclusions of the

authors. The National Petroleum Council has not endorsed or

approved the statements and conclusions contained in these

documents but approved the publication of these materials as part of

the study process.

The NPC believes that these papers will be of interest to the readers of the

report and will help them better understand the results. These materials

are being made available in the interest of transparency.

The attached Topic Paper is one of 38 such working document used in the

study analyses. Also included is a roster of the Subgroup that developed

or submitted this paper. Appendix E of the final NPC report provides a

complete list of the 38 Topic Papers and an abstract for each. The printed

final report volume contains a CD that includes pdf files of all papers.

These papers also can be viewed and downloaded from the report section 

of the NPC website (www.npc.org).
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

NATIONAL PETROLEUM COUNCIL

POWER GENERATION EFFICIENCY SUBGROUP

OF THE

DEMAND TASK GROUP

OF THE

NPC COMMITTEE ON GLOBAL OIL AND GAS

TEAM LEADER

David K. Bellman

Director of Fundamental Analysis

Corporate Planning & Budgeting

American Electric Power Co., Inc.

MEMBERS

Brett D. Blankenship

Analyst - Power and Emissions

American Electric Power Co., Inc.

Joseph Philip DiPietro

Lead General Engineer

Office of Systems, Analysis and Planning

National Energy Technology Laboratory

U.S. Department of Energy

Carl H. Imhoff

Manager, Energy Products and

Operations Product Line

Pacific Northwest National Laboratory

U.S. Department of Energy

Barry Rederstorff

Staff Engineer

Engineering Services

American Electric Power Co., Inc.

Xuejin Zheng

Senior Analyst - Coal

American Electric Power Co., Inc.
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

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Power Plant Efficiency Outlook

Power Plant Efficiency

Team leader: David K. Bellman

Date submitted: May 8, 2007 

Executive Summary

Power plant efficiencies are typically defined as the amount of heat content in 

(Btu) per the amount of electric energy out (kWh), commonly called a heat rate 

(Btu/kWh). In the EIA and IEA outlooks both show power plant efficiencies 

improvements over time. These expected improvements mainly come from the 

substitution of old plants with new plants that have better efficiencies. The existing unit 

efficiency is flat. This indicates some efficiency improvement since many of the existing 

units will likely install environmental controls. Installation of environmental control 

systems will add internal energy requirements reducing the efficiency of the plant. There 

are a few changes one can make to make an existing unit more efficient. However these 

changes typically will only result in a few percentage point improvements to efficiency. 

The efficiency of a new power plant is largely a function of economic choice. The 

technology is well understood in order to produce a highly efficient plant. In order to 

produce higher efficiencies, higher pressure and temperatures are required. This increases 

the cost of the plant as special alloy materials will be needed. Technology improvements 

could assist by lowering the cost of these special materials through discovery and better 

manufacturing process. 

Coal efficiency merit much focus since coal represents over 50% of current 

generation in the US. Many countries in the world from Germany to Japan have 

demonstrated coal plants with heat rates of less than 9,000 Btu/kWh. The US has also 

demonstrated such technology since the 1950’s. However the US coal fleet current 

operating heat rate is nowhere near those levels, 10,400 Btu/kWh. The US fuel diversity, 

relative abundance of various fuels, competitive landscape, the age of industry, and focus 

on reliability has lead to less efficiency in our coal fleet relative to other countries.

In the developing countries there is an opportunity to introduce much higher 

efficient units in the beginning. Power plants can have lifetimes greater than 40 years, so 

it becomes important to introduce the efficient units early in the development of the 

infrastructure. According to the EIA, China is expected to have slightly better coal power 

plant fleet efficiency as in the US by 2030.

Power plant efficiency can add value by reducing the amount of fuel used and 

thereby the amount of CO2 emitted. With the increased efficiency in the EIA forecast the 

US fleet reduced CO2 emissions by 261 million tons in the year 2030 versus holding 

current heat rates.
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

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Power Plant Efficiency Outlook

1. Overview of Methodology

Information was generated from publicly available reports on power generation 

efficiency. The reports used herein are (in order as they appear):

1. Developments in Pulverized Coal-Fired Boiler Technology J.B. Kitto Babcock & Wilcox April 

10-12, 1996Energy Information Agency International Energy Outlook

2. GT World, Handbook 2006

3. Black & Veatch, Supercritical Technology Overview, February 2004, presented at the CSX Coal 

Forum

4. National Energy Technology Laboratory, 2006 Cost and Performance Baseline for Fossil Energy 

Plants, February 5, 2007

5. Energy Information Administration, Assumptions to the Annual Energy Outlook 2006, March 

2006, Table 38 http://www.eia.doe.gov/oiaf/aeo/assumption/index.html

6. Coal Utilization Research Council, CURC/EPRI Technology Roadmap Update, September 20, 

2006, page 10 http://coal.org/PDFs/jointroadmap2006.pdf

7. Electric Light and Power Magazine, November/December 2005, page 44

8. Coal Utilization Research Council, CURC/EPRI Technology Roadmap Update, September 20, 

2006, page 10 http://coal.org/PDFs/jointroadmap2006.pdf

9. US EPA Integrated Planning Model, http://www.epa.gov/airmarkets/progsregs/epa-ipm/

10. Lange, Ian and Allen Bellas. Policy Innovation Impacts on Scrubber Electricity Usage. US EPA, 

National Center for Environmental Economics.

11. Braitsch, Jay. DOE/Fossil Energy Carbon Sequestration Program. September 20, 2005. 

http://www.ostp.gov/PCAST/agenda_9_20_05_files/Braitsch_DOECsequest_PCAST_20Sep05.pdf

12. IEA Greenhouse Gas R&D Programme, http://www.co2captureandstorage.info/whatisccs.htm

13. US Geological Survey. http://ga.water.usgs.gov/edu/wupt.html

14. US Department of Energy, NETL. Energy Penalty Analysis of Possible Cooling Water Intake 

Structure Requirements on Existing Coal-Fired Power Plants. October 2002

15. General Electric GER- 3696D, Upgradable Opportunities for Steam Turbines, 1996

16. Electric Light & Power, Operating Performance Rankings Showcase Big Plants Running Full 

Time Nancy Spring, managing editor November, 2005

17. The Energy Development Report of China, Edited by M. Cui, etc., Social Sciences Academic 

Press of China, 2006

18. Energy Information Administration/International Energy Outlook 2006, Appendix F - Reference 

Case Projections for Electricity Capacity and Generation by Fuel

19. Energy Information Administration Report #:DOE/EIA-0484(2006), Release Date: June 2006, 

Figure 52 Coal Consumption in China by Sector, 2003, 2015, and 2030
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2. Background

Stationary efficiency is an important topic as it relates to power generation for many 

reasons. By definition high efficiency creates less waste, yielding higher output for any 

given input. Much of the discussion surrounding power plant efficiency will focus on the 

heat rate (Btu/kWh). This is an ideal measure of efficiency since it defines the ratio of the 

input as fuel (Btu) to output as power (kWh). 

Efficiency improvements can have broader impacts than simple monetary gains for the 

plant operator. Improvements can be viewed as a fuel supply. By increasing efficiency 

(i.e. decreasing the heat rate), less fuel is required to generate each kWh. In effect, more 

fuel supply is now available than would be otherwise. In large enough volumes, this 

could have market impacts to fuel costs. Likewise an increase in efficiency has an impact 

on the level of emissions a plant releases. Since less fuel is required to generate a given 

kWh, fewer emissions are released for that given kWh. Again, in large enough quantities 

this could impact emissions markets. However, the reasons for not adopting higher 

efficiency technologies are that they are not necessarily comparable to existing 

technology. As an example, the ultra-supercritical plant has unique characteristics from 

higher capital cost to the unit not being able to cycle as sub-criticals historically have 

been able to.

The discussion will focus on current and future factors affecting stationary efficiency. 

Both efficiency increases and decreases and their impacts will be examined as they 

pertain to the future of US, world and Chinese power markets.

3. Discussion

Factors Affecting Efficiency

The following factors affect the efficiency of a given power plant.

Design choices. Designs for natural gas and coal-fired power plants represent a 

trade off between capital cost, efficiency, operational requirements, and 

availability. For example, a steam turbine system that operates at a higher 

temperature and pressure can achieve a higher efficiency (see figure 1). 
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Figure 11: Efficiency as a function of temperature and pressure

The higher temperatures and pressures, however, require more exotic materials of 

construction for both the boiler and turbine, thus the capital cost goes up. The 

technology has been proven and demonstrated since the 1950s. The problems 

were severe superheater material wastage, unacceptable creep, and thermal 

fatigue cracking experienced when metal temperatures exceeded

approximately 1,025 ̊F.1 The issue was corrosion and strength at these extreme 

conditions. Heat integration represents another trade off. Rather than transferring 

cooling water to a process stream that needs to be cooled down and steam to 

another process stream that needs to be heated up, the work can be partially 

accomplished by bringing the two streams into thermal contact via a heat 

exchanger. There is a significant efficiency benefit, but process-process heat 

exchangers can cause operational problems, especially during transient phases and 

in the event of fouling or fluid leakage across the exchanger. Thus heat integration 

represents a trade off between efficiency and availability. Unit role, peaking, base 

loading, etc, affect design and operational practices of using units for a role other 

than which they were designed. Old base load design units are often used for 

cycling duty. The supercritical to ultra-supercritical units are not capable of 

cycling without reducing longevity and ultimately the efficiency for which was 

the ultimate purpose of additional investment.

 1

 Developments in Pulverized Coal-Fired Boiler Technology J.B. Kitto Babcock & Wilcox April 10-12, 

1996
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Operational Practices. Efficiency can be improved by pressing over fire air to the 

minimum, fully utilizing heat integration systems, staying after steam leaks and 

exchanger fouling, and a large number of other practices. Operating at full load 

capacity continuously will enhance efficiency. However the reality is that load is 

ever changing and the requirements of market based systems focus on reliability 

and leads to the inability to always run at full load.

Fuel. Among coals the higher ranking coals enable higher efficiency because they 

contain less ash and less water. However additional coal production is largely 

focused on the Powder River Basin which is sub-bituminous.

Pollutant control. The level of pollutant emission control (including thermal) 

effects efficiency. NOx reduction units and SOx scrubbers represent parasitic loads 

that decrease net generation and thus reduce efficiency. This issue is further 

discussed in latter parts of the report.

Ambient conditions. Colder water and ambient air achieves higher efficiency. 

Additionally, higher altitudes have lower ambient pressure which affects 

compression and expansion. For example, gas turbines produce lower power at 

elevations above sea level. The power output loss is a function of the loss in 

ambient pressure. All else equal, lower altitude enables higher efficiency.

The actual operating efficiency of a power plant is the summation of a lot of factors. The 

numbers presented for various types of power plants represent typical performance.

Table 1 presents data on the efficiency of commercially available power plant technology 

at full load and normal temperatures. 

This does not account for operational 

issues as discussed above. Estimates for 

coal technology range from 7,757 –

9,275 btu/kWh (44% - 37% efficient 

HHV). This range offers significant 

improvement over the existing coal 

plants, if units could actually run at full 

load, without maintenance or outage 

situations and standard ambient

conditions. 

Natural gas combined cycle (NGCC) 

power plant efficiency estimates range 

from 6,333 – 6,800 btu/kWh (50-54% 

efficient HHV, see box at right) at full 

load. Typical combustion turbine (CT) 

heat rates are 9,650 – 10,400 btu/kWh 

(33-35% efficient HHV).2 The CT plants 

 2

 GT World, Handbook 2006

Definition: LHV and HHV Efficiencies

It is important to define the efficiency terms higher 

heating value (HHV) and lower heating value (LHV). 

HHV assumes H2O is in liquid state and contains the 

energy of vaporization. LHV assumes gas state for all 

combustion products. The efficiencies of coal-fired 

power systems are most often reported in HHV in the 

U.S., much of the rest of the world uses LHV. Tthe 

efficiencies of natural gas-fired power systems are 

most often reported in LHV. We report all efficiencies 

here in HHV for consistency.

The difference can be estimated by 1055Btu/Lb * w, 

where w is the lbs of water after combustion per lb of 

fuel. To convert the HHV of natural gas, which is 

23875 Btu/lb, to an LHV (methane is 25% hydrogen) 

would be: 23875 – (1055*0.25*18/2) = 21500. 

Because the efficiency is determined by dividing the 

energy output by the input, and the input on an LHV 

basis is smaller than the HHV basis, the overall 

efficiency on an LHV basis is higher.

So using the ratio: 23875/21500 = 1.11 you can 

convert the HHV to an LHV. So the the range of 50-

54% translates to 56 – 60% LHV.
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do have a very necessary role in the US. The CC and Coal plants cannot cycle – meaning 

they cannot turn off and on within a few hours. The load shape and reliability require the 

use of CT units throughout the year. However typically they will have very low capacity 

factors. Over the past few years, depending on plant location, gas plants were not 

competitive with coal units and even combined cycle units. As a result, more cycling was 

required than anticipated.

Three conclusions can be drawn from the data in Table 1. 

• Utility companies and other electricity suppliers can choose from a wide range of 

efficiencies when deploying a coal or natural gas-fired power plant.

• The average efficiency of U.S. power plants will improve as new units come 

online. The impact of fleet efficiency, as in cars but much longer due to longer 

operating lifetime, will take many years before any significant change is seen. 

Significant improvements in the average efficiency of U.S. power plants could be 

achieved via incentives to accelerate capital stock turnover. However, the 

ramifications of such incentives do not necessarily result in replacing the retired 

plant with a particular fuel and technology. 

• The current stock of U.S. generation assets is not operating as efficiently as they 

could be, due largely to operational and economical issues. For example, the 

existing stock of coal plants is operating well below the efficiency of a new subcritical plant (10,410 versus 9,276 btu/kWh). If efficiency was the goal gas plants 

should run over coal plants (8,000 vs 10,400 Btu/kWh). An industry-wide review 

of operational procedures and audit of lingering maintenance issues could produce 

a significant, near-term step change in average heat rate.

Collaborative industry/government research and development efforts seek to improve the 

efficiency of natural gas and coal-fired power plants above the level of commercially 

available systems. The goals of the U.S. Department of Energy are to demonstrate by 

2012 at the pilot scale a coal-fired power plant with a heat rate of 6,824 btu/kWh (50% 

efficiency HHV). The technologies that enable that performance include H2S removal 

from syngas at ‘warm’ temperatures (500-700 ̊F), membrane-based oxygen supply, 

advanced turbine materials, and electrochemical synthesis gas combustion. A subset of 

these technologies can be adopted for natural gas systems to enable a NGCC heat rate of 

5,785 (59% efficiency HHV). Such systems could be online commercially in the 2015-

2020 timeframe. 
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

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Table 1: Coal and Natural Gas Power Plant Efficiency at Full Load, Current Technology 

and Existing Plants

Description Order 

year

Capital 

cost 

($/kW)*

Heat rate 

(btu/kWh)

Source

COAL

PC, Ultra sc (5500 psig, 1300F) 2006 7,757 B&V3

PC, Adv sc (4710 psig, 1130F) 2006 8,126 B&V2

IGCC, Shell, F class 2006 8,304 NETL4

IGCC 2005 $1,443 8,309 EIA5

IGCC, E-gas, F class 2006 8,681 NETL3

PC, super (3500 psig, 1,100 F) 2006 8,712 NETL3

PC/IGCC range 2005 8,750 – 9,000 CURC6

PC 2005 $1,249 8,844 EIA4

IGCC, GE, F class 2006 8,922 NETL3

PC, sub (2,400 psif, 1,050 F) 2006 9,276 NETL3

Median, Top 20 efficient U.S. coal power plants, 2004 9,400 ELP7

Average, all U.S. coal power plants, 2005 10,410 EIA8

NATURAL GAS

Advanced NGCC 2005 $575 6,333 EIA4

NGCC, F class 2006 6,719 NETL3

Conventional NGCC 2005 $584 6,800 EIA4

Conventional CT 2005 $407 10,842 EIA4

Average Gas Plant 2005 7,920 EIA7

Average, all U.S. NGCC, 2004 not available EIA7

*Overnight capital cost including contingency. Does not include regional multipliers or interest expense.

Parasitic Load

Beginning with the Clear Air Act of 1970, the number of power generating units that 

have flue gas desulphurization (FGD or scrubber) and selective catalytic reduction (SCR) 

units has been increasing. Recent legislation such as the Clean Air Interstate Rule (CAIR) 

and Clean Air Mercury Rule (CAMR) has lead to a rapid increase of capacity with a 

scrubber or SCR. With cap-and-trade programs in place for SOx, NOx, and mercury the 

number of units with scrubbers and/or SCRs is expected to rapidly increasing over the 

 3

 Black & Veatch, Supercritical Technology Overview, February 2004, presented at the CSX Coal Forum

4

 National Energy Technology Laboratory, 2006 Cost and Performance Baseline for Fossil Energy Plants, 

February 5, 2007 5

 Energy Information Administration, Assumptions to the Annual Energy Outlook 2006, March 2006, 

Table 38 http://www.eia.doe.gov/oiaf/aeo/assumption/index.html 6

 Coal Utilization Research Council, CURC/EPRI Technology Roadmap Update, September 20, 2006, page 

10 http://coal.org/PDFs/jointroadmap2006.pdf 7

 Electric Light and Power Magazine, November/December 2005, page 44

8

 Coal Utilization Research Council, CURC/EPRI Technology Roadmap Update, September 20, 2006, page 

10 http://coal.org/PDFs/jointroadmap2006.pdf
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

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next 10-15 years. The obvious environmental benefits of these emission abatement 

programs come at the detriment of power efficiency. Scrubbers and SCRs, like any 

auxiliary equipment in a power plant, require electricity to run. This electricity is 

obtained from the generating unit that is being controlled. This power loss is known as 

parasitic load. Just as heat rate is a measure of efficiency by calculating the amount of 

fuel needed for each kWh of power, parasitic load is an efficiency loss because a certain 

number of kWhs generated must be used for internal power plant use and cannot be sent 

to the grid to meet consumer demand.

Figure 2 shows the current and forecasted capacity (GW) that will have either a scrubber 

or SCR installed according to the EPA Integrated Planning Model 2006.9 Scrubbed 

capacity is forecasted to increase from 100 GW currently to over 250 GW by 2020. 

Likewise, SCR installations are expected to rise from 85 GW to 220 GW over the same 

timeframe.

EPA Capacity with Scrubber/SCR Installed (GW)

*Committed/Planned = contracts currently in place or ground already broken

0

50

100

150

200

250

300

Through 2006 Committed/Planned

through 2009*

Forecasted through

2010

Forecasted through

2020

Scrubbed SCR

Figure 2: EPA Forecasted Capacities Installing Scrubber/SCR

Of course with parasitic load, each scrubber or SCR installation will, in effect, lower the 

amount of realizable capacity that can be used to meet consumer demand. Most 

documentation cites a 2% parasitic load for scrubber installations.10 Similar 

documentation and anecdotal evidence suggests SCRs require about 1% parasitic load. 

Figure 3 shows the amount of capacity lost due to parasitic load based upon the EPA’s 

projected installations and 2% loss for scrubbers and 1% loss for SCRs. By 2020, over 5 

 9

 US EPA Integrated Planning Model, http://www.epa.gov/airmarkets/progsregs/epa-ipm/ 10 Lange, Ian and Allen Bellas. Policy Innovation Impacts on Scrubber Electricity Usage. US EPA, 

National Center for Environmental Economics.
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GW and 2 GW of capacity are lost due to scrubber and SCR installations respectively. 

Emission control installations can be viewed as a load growth of 1-3% (3% if BOTH 

scrubber and SCR installed) or directly as efficiency loss to those units. The net effect is 

that new generation will be required to meet any given demand as the number of 

emission controls increases. Figure 3 includes current scrubber and SCR installations. 

Current parasitic load is being accounted for such that companies or ISOs meet reserve 

margins, etc. By subtracting current (through 2006) capacities from the 2020 forecasted 

capacities, we obtain the capacity that will be either retrofitted or new build capacity with 

control equipment. Assuming 2% loss for scrubbers and 1% loss for SCRs, these values 

come to 2.0 GW and 0.85 GW lost due to parasitic load for scrubber and SCR 

installations respectively. Nearly 3 GW of total new capacity will be required to meet 

parasitic load from scrubber and SCR installations through 2020.

Installed Capacity Lost Due to Parasitic Srubber/SCR Power Consumption

*Committed/Planned = contracts currently in place or ground already broken

0

1

2

3

4

5

6

Through 2006 Committed/Planned

through 2009*

Forecasted through

2010

Forecasted through

2020

Scrubbed (2% loss) SCR (1% loss)

Figure 3: Calculated Total Capacity Loss from Parasitic Load (from EPA data)

Like SOx and NOx, carbon dioxide seems likely to be regulated at some point during the 

next decade. Carbon capture and sequestration has remained the focal point for reducing 

carbon emissions. This technology is still relatively new and remains very costly from a 

capital and energy perspective. According to the DOE, parasitic load for carbon capture 

currently ranges from 5-30%.11 The IEA Greenhouse Gas R&D Programme estimates a 

10-15% reduction in efficiency from carbon capture.12 These values are ONLY 

associated with carbon capture. No public data is available on the load required for 

sequestration. These would include transportation (pipeline, etc) and 

compression/underground pumping. The sequestration portion would be expected to be 

 11 Braitsch, Jay. DOE/Fossil Energy Carbon Sequestration Program. September 20, 2005. 

http://www.ostp.gov/PCAST/agenda_9_20_05_files/Braitsch_DOE-Csequest_PCAST_20Sep05.pdf 12 IEA Greenhouse Gas R&D Programme, http://www.co2captureandstorage.info/whatisccs.htm
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very costly for parasitic load since transportation and compression are relatively energy 

intensive processes.

Assuming a 15% efficiency loss for carbon capture, this would cause a typical 10,500 

Btu/kWh steam cycle plant to perform as a 12,000 Btu/kWh plant. A typical combined 

cycle unit with a 7,000 Btu/kWh heat rate would now operate as an 8,000 Btu/kWh unit. 

With over 70% of US power generation coming from coal and natural gas (i.e. the 

primary CO2 emitters), any significant amount of carbon capture retrofits on existing 

plants could have a major impact to the overall system heat rate. Likewise, new plants 

with carbon capture technology will not reach their full efficiency potential due to 

significant losses required for carbon capture.

Overall, as emission control installations continue to increase, less power is available to 

meet consumer demand from the same amount of Btu fuel consumption, leading to an 

overall efficiency loss. This will require the installation of more capacity to meet this 

parasitic load.

Water Utilization Energy Penalty

The Clean Water Act amendments of 1977 placed certain limitations on water intake and 

discharge at certain facilities which included steam power plants. Water is used in large 

amounts as the method to cool the effluent steam from the steam turbine. Cooling water 

is used from an external source such as a river or lake to condense this exiting steam. In 

2000 approximately 195,000 million gallons per day (MGD) were used to produce 

electricity in thermal plants alone (i.e. excluding hydroelectric facilities).13 There are 

currently three major methods of cooling steam turbine effluent (in order of most to least 

water consumed): 

(1) once-through cooling systems which intake water, pump it through the 

condenser and directly back into the environment. 

(2) wet cooling tower in which the cooling water is constantly re-circulated from 

the condenser to a cooling tower where it cools by evaporation and convection; 

makeup water is added to account for water loss due to evaporation

(3) indirect dry cooling tower in which cooling water is constantly re-circulated 

from the condenser to a cooling tower where it cools by forced air convection via 

metal fins

The National Energy Technology Laboratory (NETL) at the Department of Energy 

studied the effects of cooling water systems on power generation.14 The temperature of 

the cooling water as it enters the condenser can have significant impacts on turbine 

performance by changing the vacuum at discharge from the steam turbine. In general 

terms, cooler water will create a larger vacuum allowing more energy to be generated. 

Conversely, warmer water creates lower vacuum and impedes generation. This effect is 

known as the energy penalty.

 13 US Geological Survey. http://ga.water.usgs.gov/edu/wupt.html

14 US Department of Energy, NETL. Energy Penalty Analysis of Possible Cooling Water Intake Structure 

Requirements on Existing Coal-Fired Power Plants. October 2002
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The NETL modeled a retrofit of a once-through cooling system to both wet and dry 

cooling tower systems for a 400 MW unit. The annual average energy penalty for 

conversion to a wet cooling tower ranged from 0.8-1.5%, while the penalty was 4.2-8.8% 

with a dry cooling tower. Additional simulations were run for peak ambient temperatures, 

which also coincide with peak power demand. For the peak case the energy penalties 

range from 2.4-4.0% and 8.9-16.0% respectively. This is a significant amount of capacity 

loss during peak demand, when generating capacity is most critical. 

It is important to note the potential impacts of water cooling systems on new builds, 

particularly west of the Mississippi. Many of future coal new builds will be built in this 

region due to the rise of Powder River Basin coal. Due to the arid climate, this western 

region is expected to have strict limitations on cooling water systems, with dry cooling 

towers likely being the system required. As shown above these systems can demonstrate 

significant efficiency losses. It is important to note that the proposed efficiencies 

provided in the subsequent sections may not be achievable due to the cooling water 

system requirements.

Efficiency Improvement Possible From Refurbishing and Upgrading Existing CoalFired Power Plants.

Existing coal-fired power plants worldwide do not achieve the highest efficiency possible 

based on their design. The loss of efficiency can be categorized as controllable or noncontrollable. Controllable losses are generally due to poor operation and maintenance 

practices. Non-controllable losses are due to environmental conditions (i.e. cooling water 

temperature, etc), dispatching requirements (i.e. customer demand) and normal 

deterioration.

Deterioration naturally occurs, and if left unchecked it can become substantial. Therefore, 

some amount of deterioration, normal deterioration, will always be present and noncontrollable. Most of the normal deterioration can be recovered with regularly scheduled 

maintenance intervals, the frequency of which determines the average based on the 

resulting saw-tooth curve shown in figure 4. 15 There is a gradual increase in the 

unrecoverable portion as the unit ages which would require a replacement rather than a 

refurbishment to eliminate. Poor maintenance practices regarding the timing of the 

intervals and the amount of refurbishment may result in excessive deterioration and is 

controllable. 

 15 General Electric GER- 3696D, Upgradable Opportunities for Steam Turbines, 1996
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Figure 415: Change in heat rate over time

Poor operation is a controllable loss. It includes operating off-design (i.e. temperatures 

too low), running redundant equipment, particularly at part load, excessive startups due to 

poor reliability, unit controls not properly tuned and off role operation. Off role operation 

may be using a unit designed for load following (with a control stage) for base load or 

one designed for base load (without a control stage) for load following.

Dispatching requirements determine the generation level of the unit and is not 

controllable. Since efficiency drops with load, this loss can be substantial (5-10% at half 

load). 

To summarize, starting from the unit’s full load design heat rate, add in the typical losses 

to get to the operational (or reported) heat rate as follows

Design Full Load Heat Rate +

Environmental Conditions [loss or gain] [non-controllable] +

Loading [loss] [non-controllable] +

Normal Deterioration [loss] [non-controllable] +

Excessive Deterioration [loss] [controllable] +

Poor O&M practices [loss] [controllable] =

Operational Heat Rate

The last two items on the list are recoverable through routine refurbishment and 

correction of poor O&M practices. These categories are generally acknowledged to be on 

the order of 500 Btu/kWh for an average plant and can reach 1000+ in some of the more 

poorly run plants.

Beyond refurbishment, replacement in kind is the next step. This resets normal 

deterioration loss to ‘as-new’ values and addresses maintenance reliability problems that 

can impact heat rate. Replacement opens up the possibility of upgrade. Why not replace a 
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part that may be 20 to 60 years old with today’s technology and end up better than the 

original design? Turbine upgrades are prime examples. Controls, condensers and air 

heaters are other popular upgrades. Table 2 quantifies typical turbine upgrades and breaks 

the gains down between recovery (in-kind replacement) and that due to the advanced 

design.15 Table 3 shows typical improvements for non-turbine equipment.

Table 215: Efficiency gains for turbines

Table 3: Efficiency gains on various plant equipment

Equipment 

(other than 

Turbines)

Description of 

Efficiency Loss

Cycle 

Efficiency 

Impact

Type of 

Change

Source

Pulverizers Fly ash carbon 

content of 1% -

30%, Impact of 

30%

0.2% to 0.5% Recovery APEC 

document

Air Heaters Excessive 

leakage, High 

delta P

0.2%– 1.5% Recovery & 

upgrade of 

seals

APEC 

document

Forced Draft, 

Primary Air, 

and Induced 

Draft Fans

Does not match 

current system 

design.

2% - 8%* Up-grade to 

match current 

system design

APEC 

document

Condenser Air in leakage, 

Fouling, 

Original design 

2% Recovery & 

up-grade of 

design

Intek, Inc 

abstract for 

January 2007 
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

14

of air removal 

equipment

EPRI Heat Rate 

Improvement 

Conference

Control and 

Instrumentation

Overall Unit Controllable 

Losses

5%-10% Storm 

Technologies 

abstract for 

January 2007 

EPRI Heat Rate 

Improvement 

Conference

* This range of values is predominately capacity rather than heat rate. The cause is most 

likely higher pressure drops caused by scrubber and/or SCR retrofits. Only what is lost 

can be recovered, so it should not be assumed that the maximum value can be applied to 

more than a small number of units. There may be some heat rate improvement due to 

advanced design replacement fans, but that is relatively small compared to the capacity 

recovery.

The text below is taken directly from a report, Costs And Effectiveness Of Upgrading 

And Refurbishing Older Coal-Fired Power Plants In Developing Apec Economies, 

published in June of 2005 by APEC (Asia Pacific Economic Cooperation) Energy 

Working Group. It describes a number of unit operations in a power plant that typically 

contribute to sub-standard efficiency. A given power plant generally will not have one 

big issue affecting efficiency, but rather several big issues and a large number of small 

refinements.

For the past ten years, U.S. AID has been conducting efficiency audits at power 

plants in India and China. An audit requires the purchase of several hundred 

thousand dollars worth of diagnostic equipment and evaluation of 4-6 experienced 

professionals working onsite at the power plant for up to six months. It is a 

significant undertaking, but based on the experiences of AID, well worth the 

effort.

Beginning in 2007 the Asia-Pacific partnership plans to initiate a 6-country peer 

review of power plant efficiency practices. The participating countries are the 

U.S., China, India, Australia, Japan, and Korea. The effort is being coordinated by 

EEI (Edison Electric Institute). 

Equipment Refurbishing and Upgrading Options (taken from APEC document, 

June 2005)

Air Heaters
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

15

Air heaters heat combustion air and cool boiler exit flue gas. Boiler efficiency is 

improved and the hot air needed for drying coal and obtaining proper combustion 

is provided to the pulverizers and burners. The two types of air heaters used most 

often are the regenerative and tubular air heaters.

Air heater operating deficiencies include excessive leakage of combustion air into 

the boiler exit flue gas flow, low air temperatures to the pulverizers and burners, 

excessive air and flue gas pressure loss. These problems cause lower boiler 

efficiency, reduced gas and air flows, reduced air temperatures, and reduced coal 

input that can limit boiler output. Pollutant emissions often increase because 

lower boiler efficiency requires increased coal consumption. Air leakage results in 

increased flue gas flows that consequently reduce precipitator collection 

efficiency.

Performance improvement depends on the design and the current performance of 

the existing air heater. Flue gas leaving some operating air heaters has exceeded 

the design value by 5 oC to 20 oC and air leakage to into the flue gas flow may 

reach 40%. As a result of these conditions, boiler efficiencies can decrease in the 

range of 0.2% to 1.5%. These deficiencies can be corrected by air heater 

improved surface cleaning, air to gas path seal improvements, and other 

upgrading and refurbishment.

Pulverizers

Pulverizers dry and process coal to a fine powder that is required in the burners. 

Improved and refurbished pulverizers often reduce unburned carbon, which is 

wasted fuel. Fly ash carbon content in the range from 1% to over 30% has been 

encountered. A 30% fly ash carbon content will cause a loss of boiler efficiency 

in the range of 0.2% to 0.5%.

Pulverizer upgrading and refurbishment can also reduce the amount of ash slag 

(iron, silica, calcium and other coal ash constituents) that collects on furnace 

walls, superheaters, and reheaters, thereby improving heat transfer and boiler 

efficiency. These ash accumulations may also cause overheating and corrosion of 

boiler tubes, causing failures that require boiler shutdown for repairs.

Burners

Burners mix coal and primary air with secondary air for injection into the furnace. 

With improved burners and instrumentation more complete combustion of the 

coal with lower NOx emissions is possible. In addition, with new burners and 

instrumentation, operators can adjust air and coal flow for complete combustion 

and lower unburned carbon, and reduce water wall slagging and 

superheater/reheater slagging and fouling. These improvements result in better 

heat transfer within the furnace and improved boiler efficiency. Improved coal 

feeders and pulverizers may also be needed to achieve the benefits of improved 

boiler efficiency. As noted above for improved pulverizers, the impact on boiler 

efficiency can be significant.
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

16

Burner Furnace Sootblowing Upgrades

Improved or additional sootblowers increase furnace, superheater, and reheater 

heat absorption leading to increased boiler efficiency, reduced coal consumption, 

and lower emissions by maintaining these tube surfaces reasonable clear of ash 

accumulations that reduce heat transfer.

Steam Turbines

Steam turbines convert the boiler steam energy into rotating energy for turning the 

generator.

Improving steam turbine performance by refurbishing will result in significant 

performance improvements. Refurbishments include removing deposits that cause 

a reduction in blade aerodynamic performance, repairing or replacing the first 

stage turbine blades that have been damaged by boiler tube scale, replacing or 

adjusting blade and shaft seals, and other activities. In addition, major 

performance improvements can be implemented on many turbines with newer, 

more efficient turbine blades and other components. These improvements are 

possible because current turbine designs perform more efficiently than the designs 

that were available ten to twenty years ago.

Condensers

Condensers receive steam from the steam turbines where cooling water flowing 

through tubes cools and condenses the steam. Condensing lowers steam turbine 

exhaust pressure and increases turbine efficiency. Also, condensing the steam 

allows pumping and recycling the high quality water to the boiler.

Scaling on the water-side of the condenser tubes decreases the heat transfer 

coefficient and higher condenser pressures result. Increased condenser pressure 

will significantly reduce steam turbine output and efficiency. Air leakage into the 

condenser can also increase condenser pressure and will lower the quality of the 

recycled water.

Forced Draft, Primary Air, and Induced Draft Fans

Forced draft (FD) fans supply air to the burners and in some systems to the 

pulverizers. With a pressurized furnace, the forced draft fans provide sufficient 

pressure for the flue gas flow through the furnace, air heater and flue gas cleanup 

equipment to the chimney. Some boilers have primary air fans that supply air to 

the pulverizers, whereas some boilers have blowers or exhausters on each 

pulverizer. Induced draft (ID) fans move flue gas from the furnace through the air 

heaters and flue gas cleanup equipment to the chimney.

Increased fan flow and pressure are required for various reasons:

• Changes in the coal quality and moisture.

• Air heater and other equipment pressure losses have increased.
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

17

• Air pollution control or burner modifications have increased air and flue gas 

pressure losses.

• The original design pressures and flows for the fans were not adequate for 

the current actual operating situation.

Unit output reductions from fan performance deficiencies have been encountered 

that have reduced unit output in the range of 2% to 8%.

Control and Instrumentation

Control and instrumentation improvements can reduce total fuel consumption due 

to quicker and more coordinated startups, and provide better control of fuel and 

air during normal operation. The main impacts of improved controls are improved 

operating efficiency due to better control of excess air and steam pressure and 

temperature, as well as faster load changes in response to the generating system 

requirements. In addition, boiler and turbine stresses are reduced because startup 

and load changing is coordinated to reduce temperature and pressure variations. 

This often provides higher unit availability because of the decrease in thermal 

stresses and inadvertent unit trips during generating system transients, which, in 

turn, lead to turbine, boiler and other equipment failures. (end of APEC 

document)

Advancement in design opens up another possibility, modifying the original 

design of a unit. This can be as “simple” as resizing the backend of the turbine to 

increase flow capability or reduce losses due to being undersized in the original 

economic analysis (low fuel prices) or as complicated as totally replacing major 

pieces of equipment and modifying the cycle. In some cases, such as turbine 

nozzles, the replacements can be designed to have a lower rate of deterioration. In 

the extreme, this type of upgrade can become a repowering option where the 

boiler is replaced by combustion turbines, a new boiler or converted (CFB). 

Significant efficiency and fuel changes are possible. To summarize, deterioration 

can be addressed as follows:

• Refurbishment

• Replacement in kind

• Upgrade with advanced design

• Modify original design

• Repowering

• Retirement with replacement by new construction

Given the large aggregate capacity of existing coal-fired power plants and their long 

useful life, efforts to improve the average efficiency of the existing stock by one or two 

percent could have a significant near term impact on fuel consumption rates and 

greenhouse gas emissions. Every plant, based on age, condition and economics will fall at 

one of the levels on the above list, with most of them in the top 3 categories. Different 

pieces of equipment might be at different levels for the same plant. The amount of gain is 

also a function of the plant’s design and situation. Finally, when all is considered, most 
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

18

plants will fall in the 3-6% range of possible improvement. The practical or economic 

values will be lower. The newer plants might be in the 2-4% range and a certain 

population might be 2% or less because they were already upgraded.
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

19

Forecasted Efficiency

Two primary sources for analyzing the past and the future of power generation efficiency 

are the Energy Information Administration’s (EIA) Annual Energy Outlook 2007 and the 

International Energy Agency’s (IEA) World Energy Outlook. The overall measure of 

power plant efficiency comes from the heat rate (Btu/kWh). This accounts for the total 

heat (i.e. fuel) required to generate each kWh. Highly efficient units will require less 

heat/fuel to generate each kWh. Heat rates were calculated from the provided data for 

each report to develop trends in power plant efficiency. This analysis is centered on fossil 

fuel generation. General consensus is that petroleum generation will continue to decline, 

so we will further focus our discussion on only natural gas and coal-fired generation. 

United States

Figure 5 shows historical and forecasted heat rates from US natural gas and coal-fired 

power plants. Historical calculations are based upon EIA data. The post-war boom of the 

late 1940s and 1950s saw a large increase in new power plants. However, these were, by 

today’s standards, highly inefficient plants, with the overall fleet heat rate starting in 

1949 at nearly 15,000 Btu/kWh. By the end of the 1950s, more efficient plant 

constructions drove the fleet heat rate to approximately 10,300 Btu/kWh, where it 

remained relatively unchanged until the end of the century. 

US Historical and Forecasted Operating Heat Rates (Btu/kWh)

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

1940 1950 1960 1970 1980 1990 2000 2010 2020 2030 2040

EIA Coal EIA Gas EIA Total IEA Coal IEA Gas

Figure 5: Historical and forecasted heat rates from EIA and IEA

The overbuild of natural gas combined cycle units in the late 1990s decreased the natural 

gas fleet heat rate below 9,000 Btu/kWh, where it currently resides. However with the 

recent higher natural gas prices, coal generation still represents over 50% of current US 
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

20

power generation. Therefore overall US fleet heat rate was not impacted by the large 

combined cycle build since coal-fired heat rates remain around 10,400 Btu/kWh.

The EIA is projecting the natural gas fleet heat rate to continue to decline. Around 2023, 

generation from gas units decreases faster than consumption, resulting in a slight increase 

to 8,300 Btu/kWh. Currently, best technology combined cycle units can achieve ~5,700 

Btu/kWh [General Electric H-System]. The gas heat rate includes CT plants which could 

have heat rates as high as 13,000 and as low as 8,550 Btu/kWh in the future according to 

the EIA. These types of units will continue to be needed as they have the ability to turn 

on and off over a small time period leading to increase system stability. 

The EIA is forecasting moderate improvements in the coal fleet heat rate, achieving 

9,700 Btu/kWh by 2030. In terms of percentage improvement it is approximately the 

same trend as gas units. This indicates many more new coal plants as compared to new 

gas plants in the projection. To see any appreciable improvement in fleet heat rate, a 

large number of new, efficient units would need to replace a large number of old, 

inefficient units and/or existing units would have to be retrofitted. With 40 year life spans 

and high capital costs (vs. gas plants) to construct, and risk of a CO2 constrained 

environment, this is not achieved very quickly. The difference in fuel price (coal vs. gas) 

is another major driver for increased efficiencies in gas plants compared to coal plants. 

Major increases in combined cycle efficiencies will make those units more competitive 

with coal in dispatch. With coal’s current fuel pricing advantage, there is less incentive to 

make wholesale improvements in efficiency versus focusing on availability. Table 4 

shows the EIA assumptions for new build heat rates for 2005, nth-of-a-kind in the future 

and the best observed heat rates to date. Observed data for combustion turbines is not 

provided since efficiency is not their primary role in the supply stack. These units are 

used primarily as peakers, where efficiency is not of utmost concern.

Table 4: EIA heat rate assumptions (all values Btu/kWh)

Technology Heat 

Rate in 

2005

Heat Rate nth-of-akind (% improvement 

from 2005)

Best Current 

(2004)16

Scrubbed Coal 8,844 8,600 (2.8%) 8,842*

IGCC 8,309 7,200 (13.3%) N/A

IGCC w/ carbon sequestration 9,713 7,920 (18.5%) N/A

Conv. CC 7,196 6,800 (5.5%) 6,335*

Adv. CC 6,752 6,333 (6.2%) N/A

Adv. CC w/ carbon sequestration 8,613 7,493 (13.0%) N/A

Conv. CT 10,842 10,450 (3.6%) N/A

Adv. CT 9,227 8,550 (7.3%) N/A

* Coal = TVA, Bull Run Plant; CC = Sempra, Elk Hills Power

 16 Electric Light & Power, Operating Performance Rankings Showcase Big Plants Running Full Time 

Nancy Spring, managing editor November, 2005
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

21

The EIA forecasted heat rates for new builds seem reasonable when compared to the best 

operational CCs and coal units in 2004. In fact, the forecasted CC heat rate may be a bit 

conservative, considering new technology (GE H-System) has exhibited heat rates around 

5,700 btu/kWh. The forecasted coal heat rate is slightly less than current operational 

technology, so the EIA is assuming technology advances. In light of the cooling water 

system requirements (especially in the west), the forecasted heat rate may not be 

achievable without future technology advances.

Historical EIA and IEA generation and fuel consumption varied slightly for the US, while 

the IEA provides fuel consumption for combined power and heat plants. To mitigate this 

discrepancy, it was assumed that historical EIA data for the US was correct. The 1990 

IEA data was then normalized to the EIA data. Each normalization factor was used to 

scale the forecasted IEA data, so it could be directly compared with the EIA forecasted 

data. Figure 5 shows the IEA forecasted heat rates for both coal and gas-fired plants. The 

IEA and EIA forecast very similar coal-fired heat rates, but differ slightly in 2030 with 

EIA forecasting 9,700 Btu/kWh and IEA projecting 9,400 Btu/kWh. The forecasts 

slightly diverge in gas-fired heat rates, with the EIA having the anomaly decrease (rise of 

heat rate) in efficiency starting in 2023.

According to the EIA Annual Energy Outlook, the coal-fired fleet heat rate shows 

improvement over the forecast horizon. To determine how much of this improvement 

comes from new generation versus improvements to existing units, the heat hates for each 

were back calculated. Table 5 shows the methodology used in calculating the heat rate of 

existing units. Equation 1 shows the calculation used for determining weighted-average 

heat rates for existing and new units. Total generation, total coal heat rates and the 

mixture of pulverized/IGCC new builds are all available from the EIA Annual Energy 

Outlook. From those given values, all other values necessary to derive future heat rates 

for units existing in 2007 can be obtained. Solving Equation 1 for HRexist yields the value 

we are seeking. New build capacity by year is available in the Annual Energy Outlook. 

The EIA assumed new pulverized coal units have a heat rate of 8,600 Btu/kWh, while 

new IGCC units have a heat rate of 7,200 Btu/kWh. Assuming a capacity factor of 80% 

for all new coal generation, the amount of total generation from existing and new units 

can be calculated. According to the Annual Energy Outlook 2006, coal new builds in 

2015 were 72% pulverized and 28% IGCC. The mixture in 2030 was 40% and 60% 

respectively. This data is not yet available for the 2007 report, so the new build mixture is 

assumed unchanged from the 2006 report. For the years 2015-2030, the ratio of 

pulverized and IGCC new builds was linearly interpolated to get a curve for new 

pulverized and IGCC generation. Using a weighted-average heat rate calculation based 

on the above information, the heat rate for existing units was calculated and is shown in 

Figure 6. Heat rates remain relatively flat through 2030.

Table 5: Methodology for back calculation of existing unit heat rates
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

22

ID Value Formula Notes

[1] Total Generation (MWh) given Provided EIA AEO

[2] Cumulative New Build Generation - 80% CapFact =NewBuildCoalCapacity*8760*0.80 NewBuildCoalCapacityProvided EIA AEO

[3] % New Coal Pulverized linearly interpolated over 2015-2030 Provided EIA AEO 2006

[4] % New Coal IGCC linearly interpolated over 2015-2030 Provided EIA AEO 2006

[5] New Pulverized Generation =[3]*[2]

[6] New IGCC Generation =[4]*[2]

[7] Existing Unit Generation =[1]-([5]+[6])

[8] Total Heat Rate given Calculated EIA AEO

[9] New Heat Rate see Eq. 1

[10] Existing Unit Heat Rate see Eq. 1

( ) ( )

total

exist new

exist exist new new HR

Gen Gen

HR Gen HR Gen

=

+

! + !

Eq. 1

Existing Unit Heat Rates (Btu/kWh)

9,000

9,500

10,000

10,500

11,000

11,500

12,000

201520162017

2018

20192020202120222023202420252026202720282029

2030

Figure 6: Heat rate at existing coal units according to EIA

According to the EPA, as discussed above, nearly 270 GW will be scrubbed by 2020. 

This amounts to nearly 90% of all coal units, including new builds which are all assumed 

to be built with scrubbers and SCRs. By 2020 about 18% of existing coal units will be 

retrofitted with a scrubber (this does not include units that currently have scrubbers in 

2006). The net change in heat rates through 2030 is nearly 0%. This means that any loss 

due to parasitic load must be identically offset by improvements in efficiency through 

other retrofits or refurbishing. Based on scrubber retrofits alone, (18%*2% parasitic load) 

this means that the coal fleet efficiency improvement is 0.36% for existing units. SCRs 

are not taken into account in this analysis since they are installed on gas units as well. 

Also, SCR and scrubber installations are not mutually exclusive, as many coal units will 

install both. Assuming the fleet heat rate would still remain flat with SCR installations, an 

even larger improvement would be required to identically offset the parasitic load losses. 

This value is between 2-3% (scrubber = 2%, SCR = 1%). The improvement to existing 

unit heat rates is not attributed to the retirement of less efficient units (i.e. “addition by 
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

23

subtraction”). By 2030, retired coal capacity is only 1.29% of the entire coal fleet 

capacity. Considering this 1.29% would have lower capacity factors than the units 

replacing them, their impact is considered negligible to the observed efficiency 

improvement.

CO2 Impact in United States

Using the EIA forecasted heat rates, CO2 emissions were calculated using standard 

emission rates of 205 lb/mmtbu and 115 lb/mmbtu for coal and gas units respectively. 

Five scenarios were compared:

1. CO2 Locked at Current HR – 2007 HRs are used in perpetuity

2. CO2 at EIA Forecasted HR – forecasted decrease in HR is used

3. CO2 If 1/2 Coal Goes to Gas – 50% of coal generation goes to gas generation

4. CO2 with 2x Coal Turnover – the percentage of coal fleet that is new build is 

doubled (i.e. by 2030 65% is new build as opposed to the EIA base of 32.5%)

5. CO2 with 5% Improvement to Current HR – current heat rates improved 5%

Figure 7 shows the 2030 CO2 emissions for each case. As might be expected the scenario 

in which 50% of coal generation goes to gas generation yields the lowest CO2 emissions. 

This is accounted for by the double reduction effect of heat rate and emission rate. Coal 

units have higher heat rates and emissions rates. Reducing 50% of that generation by both

heat rate and emission rate has a multiplicative effect on total CO2 emissions. Below is a 

simple illustration of the effect on CO2 by replacing coal generation with gas generation

Coal: MWh

1.08 ton CO

2000 lb CO

ton CO

MWh

10.5 mmbtu

mmbtu

205 lb CO 2

2

2 2 ! ! =

Gas: MWh

0.40 ton CO

2000 lb CO

ton CO

MWh

7.0 mmbtu

mmbtu

115 lb CO 2

2

2 2 ! ! =

By replacing 1 MWh of coal generation with gas, only 37% as much CO2 is emitted. 

Figure 8 shows the total CO2 emission savings for the timeframe 2007-2030. As 

expected, replacement of coal generation with gas generation has the largest impact 

followed by replacement of old coal generation with new coal generation.
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

24

CO2 Emissions in 2030 for HR Scenarios

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

CO2 Locked at

Current HR

CO2 at EIA

Forecasted HR

CO2 If 1/2 Coal

Goes to Gas

CO2 with 2x Coal

Turnover

CO2 with 5%

Improvement

Million Tons

Figure 7: CO2 emissions in 2030 for various scenarios calculated from EIA Annual 

Energy Outlook

As always, there are trade-offs. In a carbon constrained world it would be easy to suggest 

the ‘1/2 Coal Goes to Gas’ scenario. However, the amount of natural gas consumption 

jumps dramatically to meet this excess demand. With coal accounting for 50% of power 

generation, this is a significant shift – 25% of total generation moving to gas. Figure 9 

shows gas consumption for power generation in 2030 for the given scenarios. With over 

3 times the gas consumption for the ‘1/2 Coal Goes to Gas’ scenario as the EIA base 

forecast, significant price changes in natural gas would occur. This would make coal 

more attractive, thus increasing CO2 emissions until a final equilibrium is obtained. The 

above scenarios are simply illustrations of the potential impacts that efficiency can have 

on CO2 emissions and gas consumption. In reality, market forces will act to temper 

extremes toward equilibrium.
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

25

Total CO2 Savings vs. CO2 Locked at Current HR

[2007-2030]

-

5

10

15

20

25

CO2 at EIA Forecasted HR CO2 If 1/2 Coal Goes to Gas CO2 with 2x Coal Turnover

Billion Tons

Figure 8: Total CO2 emission savings vs. the total emitted if 2007 HRs locked in 

perpetuity

Gas Consumption for Power Generation 2030 [BCF]

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

CO2 Locked at

Current HR

CO2 at EIA

Forecasted HR

CO2 If 1/2 Coal Goes

to Gas

CO2 with 2x Coal

Turnover

Current US

consumption =

5900 BCF in 2006

Figure 9: Gas consumption in 2030 for various scenarios calculated from EIA Annual 

Energy Outlook

World and China

Since historical data does not align properly between EIA and IEA, heat rate 

improvements were examined for the world and China, as opposed to absolute heat rate 
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

26

values. Figures 10-12 show the percentage improvements in heat rate for EIA and IEA 

from each agency’s base year. As one might expect, heat rate improvements in China are 

expected to outpace worldwide improvements. Rapidly growing power demand is 

expected to drive a large increase in the number of new builds. With a larger percentage 

of fleet capacity coming from newer, efficient units, it is expected that overall 

improvements would increase rapidly in China. Worldwide heat rate improvements are 

forecasted to increase moderately for both gas and coal plants according to both EIA and 

IEA. Again, this is the result of gradual replacement of older, inefficient units with new, 

efficient ones. The slower pace of this replacement leads to the slower increase in 

efficiency when compared with China alone.

An important distinction to note between the EIA and IEA forecasts is the heat rate 

improvements of coal vs. gas. The EIA forecasts gas improvements for the world and 

China to greatly outpace improvements to coal-fired generation. Inversely, the IEA 

forecasts coal to improve more rapidly than gas-fired plants. There are two schools of 

Gas Heat Rate Improvements

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

2000 2005 2010 2015 2020 2025 2030 2035

EIA Gas China EIA Gas World IEA Gas World IEA Gas China

Figure 10: Gas heat rate improvements
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

27

Coal Heat Rate Improvements

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

2000 2005 2010 2015 2020 2025 2030 2035

EIA Coal China EIA Coal World IEA Coal World IEA Coal China

Figure 11: Coal heat rate improvements

Total Heat Rate Improvements

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

2000 2005 2010 2015 2020 2025 2030 2035

EIA Total China EIA Total World IEA Total World IEA Total China

Figure 12: Total heat rate improvements

thought that can justify either scenario. One could argue that gas heat rates are expected 

to rapidly improve due to a large buildup of highly efficient combined cycle units. This is
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

28

the same phenomenon that was seen in the United States during the 1990s. With a rapid 

increase of combined cycle units, the gas heat rate quickly declines. The large 

improvements in coal-fired heat rates could be justified by determining that gas-fired heat 

rates are asymptotically approaching their maximum achievable efficiency (though not 

achievable, 100% efficiency is 3,412 Btu/kWh). Steam cycle coal units theoretically have 

more room for improvement since they are less efficient from the start.

Thermal Electricity Generation Fuel Mix in China, U.S., and Japan

from IEAWorld Energy Outlook 2006

90.1%

76.8%

21.8%

95.0%

70.6%

43.8%

96.4%

70.6%

44.1%

96.4%

74.8%

37.4%

9.4% 5.9%

47.1%

3.9% 4.7%

19.8%

1.6% 3.9%

15.0%

0.9% 2.4%

8.1%

0.6%

17.3%

31.1%

1.0%

24.7%

36.4%

2.0%

25.5%

40.9%

2.7%

22.8%

54.5%

0%

20%

40%

60%

80%

100%

120%

China US Japan China US Japan China US Japan China US Japan

1990 2004 2015 2030

COAL OIL GAS

Figure 13: Fuel mix for thermal power plants in China, U.S., and Japan

Recently, a blue book of energy of China17 reported historical heat rates for Chinese 

power plants. The blue book data on Chinese coal-fired power plant efficiencies are not 

consistent with those forecasted by the Energy Information Administration. In its 

reference case, EIA forecasted electricity generation, coal consumption and coal-fired 

generation in China, as listed in Table 6. Based on the EIA data, the heat rates for coalfired power plants in China are calculated and listed in Table 6, and the calculated heat 

rates for 2003 and 2015 are much higher than those for 2002 reported by the blue book, 

as shown in Table 7. From Table 6, coal-fired generation in 2015 almost doubles that of 

2003, which indicates that about 50% of electricity will be generated from new coal-fired 

plants built after 2003. However, the average heat rate only decreases 0.4% from 2003 to 

2015. These new-builds will have an average heat rate of 11,426 Btu/kWh with 

assumptions of no retirement of old plants and constant capacity factor for all plants. If 

the retirement of old plants and higher capacity factors for the new builds are taken into 

consideration, the new builds’ average heat rate will be higher than 11,426 Btu/kWh. 

This value seems much too high considering US new builds are currently achieving heat 

rates lower than 9,000 Btu/kWh. As a comparison, the average heat rates of U.S. coalfired power plants from EIA are listed in Table 6. Because of scarcity of reliable data, the 

 17 The Energy Development Report of China, Edited by M. Cui, etc., Social Sciences Academic Press of 

China, 2006
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

29

uncertainty of the efficiencies of coal-fired power plants in China exists and is not ready 

to be solved at present. Also, this uncertainty has a huge impact on estimating CO2

emissions from Chinese coal-fired plants. The CO2 emissions from Chinese coal-fired 

plants for 2003 will be 8.2%, or 137 million tons, less if the average heat rate of 10,580 

Btu/kWh in Chinese coal-fired plants from the Blue book is used, than that calculated 

from average heat rate of 11,530 Btu/kWh from the EIA. In a less-conservative way, if 

17.1% decrease in the average heat rate from 11,530 Btu/kWh in 2003 to 9,560 Btu/kWh 

in 2030 for Chinese coal-fired power plants from the EIA is applied to the derived 

average heat rate of 10,580 Btu/kWh from the Blue book, there are 422 million tons of 

CO2 emissions less than that based on the EIA forecasted 9,560 Btu/kWh. These 

calculations indicate that it is important to improve the data collection on CO2 emissions 

issue before a reliable conclusion should be made.

Changes in efficiency and electricity generated

0%

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Increase in electricity generated (%)

Figure 14: Historical efficiency improvements according to The Energy Development 

Table 6: Electricity generation coal consumption and coal-fired generation in China

Year 2003 2015 2030

Generation (Billion kwh)18 1414 2788 5243

Coal consumption (Quadrillion Btu)

19 16.3 32 50.1

Calculated average heat rate (Btu/kWh) 11,530 11,480 9,560

U.S. average heat rate (Btu/kWh) 10,310 10,370 9,670

 18 Energy Information Administration/International Energy Outlook 2006, Appendix F - Reference Case 

Projections for Electricity Capacity and Generation by Fuel

19 Energy Information Administration Report #:DOE/EIA-0484(2006), Release Date: June 2006, Figure 52 

Coal Consumption in China by Sector, 2003, 2015, and 2030
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

30

Table 7: Comparison of coal-fired heat rates in Btu/kwh from different sources

Year 2002 2003

The Blue Book17 10,580

EIA 11,530

Improvement in coal-fired power plant efficiency in China has a great impact on the CO2

emissions. If the coal-fired power plants in China kept their efficiency unchanged at the 

2003 level, Chinese coal-fired power plants would emit 1 billion tons more CO2 in 2030 

under an assumption of 205 lb CO2/mmBtu than it would if it had the 2030 forecasted 

heat rate of 9,560 Btu/kWh. To yield the Chinese forecasted heat rate of 9,560 Btu/kWh, 

all new coal plants built after 2003 would need to average 8,830 Btu/kWh. This 

highlights the imperative nature of the need to start installing more advanced coal plants 

in China versus their historically installed plant technology.

Overall, the EIA and IEA are forecasting fleet improvements to power plant efficiencies. 

The need for more efficient gas units in addition to technology improvements requires 

market influence. With gas prices at much higher levels relative to coal prices the need to 

increase efficiency becomes greater for a gas plant to make up the fuel price difference to 

a coal plant in dispatch. With an increasing amount of generation coming from coal-fired 

plants, the overall system fleet heat rate decreases at a slower rate than is seen for gas 

units alone. This is the weighted-average effect of coal-dominated generation. 
Working Document of the NPC Global Oil & Gas Study Made Available July 18, 2007

31

4. Policy Recommendation

Promoting efficiency seems to be an obvious choice, but the implementation of a policy 

needs to be cognizant of the cost and operational sensitivity of the utility industry. Over 

50% of current US power generation comes from coal, which shows the most room for 

efficiency improvement. However, reliability will continue to be important over 

efficiency. Retrofitting and refurbishing of the aging US fleet will likely yield only 

minimal efficiency improvements (5-10%). Counteracting this, emission control retrofits 

will lead to a decrease in efficiency due to their parasitic load. 

• Technology research in advanced materials will be required to lower the capital 

costs of higher efficient units that require exotic materials of construction 

• Increasing fleet turnover will yield the greater efficiency improvements by 

replacing older, less efficient units with newer, more efficient ones. However, 

without considering a balanced generation mix, a larger dependence on foreign 

fuel will occur, in particular LNG 

• For the world and China, it is imperative that better data be obtained to 

understand the ramification of future power markets

• Construction of highly efficient plants is critical particularly in developing 

countries where the fleets have large room to grow. With 40+ year lifespans, it is 

important that new units be as efficient as possible with balancing the reliability 

concerns.