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CHAPTER 4

ELECTRIC POWER SECTOR PROFILE

4.1 Introduction

This chapter discusses important aspects of the power sector that relate to the 

proposed EGU GHG NSPS, including the types of power-sector sources affected by the proposal,

and provides background on the power sector and EGUs. In addition, this chapter provides 

some historical background on EPA regulation of and future projections for the power sector.

4.2 Power Sector Overview

The production and delivery of electricity to customers consists of three distinct 

segments: generation, transmission, and distribution.

4.2.1 Generation

Electricity generation is the first process in the delivery of electricity to consumers. Most 

of the existing capacity for generating electricity involves creating heat to rotate turbines 

which, in turn, create electricity. The power sector consists of over 17,000 generating units, 

comprising fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources 

dispersed throughout the country (see Table 4-1).

Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2009

Energy Source

Number of 

Generators

Generator 

Nameplate 

Capacity (MW)

Generator Net 

Summer 

Capacity (MW)

Average 

Capacity 

Factor

Coal 1,436 338,723 314,294 63.8%

Petroleum 3,757 63,254 56,781 7.8%

Natural Gas 5,470 459,803 401,272 42.2%

Other Gases 98 2,218 1,932 10.1%

Nuclear 104 106,618 101,004 90.3%

Hydroelectric Conventional 4,005 77,910 78,518 39.8%

Wind 620 34,683 34,296 N/A

Solar Thermal and Photovoltaic 110 640 619 N/A

Wood and Wood Derived Fuels 353 7,829 6,939 N/A

Geothermal 222 3,421 2,382 N/A

Other Biomass 1,502 5,007 4,317 N/A

Pumped Storage 151 20,538 22,160 N/A

Other 48 1,042 888 N/A

Total 17,876 1,121,686 1,025,400 44.9%
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Source: EIA 2009

Note: Average capacity factors not available for EIA’s 2010 Electric Power Annual. Additionally, EIA does not 

calculate average capacity factors for all energy sources presented in the table. This table presents generation 

capacity. Actual net generation is presented in Table 4-3.

These electric generating sources provide electricity for commercial, industrial, and 

residential uses, each of which consumes roughly a quarter to a third of the total electricity 

produced (see Table 4-2). Some of these uses are highly variable, such as heating and air 

conditioning in residential and commercial buildings, while others are relatively constant, such 

as industrial processes that operate 24 hours a day.

Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2010 (Billion kWh)

Sales/Direct Use 

(Billion kWh) Share of Total End Use

Retail Sales

Residential 1,445 37.2%

Commercial 1,330 34.2%

Industrial 971 25%

Transportation 8 0.2%

Direct Use 135 3.5%

Total End Use 3,889 100%

Source: EIA 2010a

In 2010, electric generating sources produced 4,125 billion kWh to meet electricity 

demand. Roughly 70 percent of this electricity was produced through the combustion of fossil 

fuels, primarily coal and natural gas, with coal accounting for the largest single share (see 

Table 4-3).

Table 4-3. Electricity Net Generation in 2010 (Billion kWh)

Net Generation (Billion kWh) Fuel Source Share

Coal 1,847 44.8%

Petroleum 37 0.90%

Natural Gas 988 23.9%

Other Gases 11 0.3%

Nuclear 807 19.6%

Hydroelectric 260 6.3%
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Other 175 4.2%

Total 4,125 100%

Source: EIA 2010a

Note: Retail sales are not equal to net generation because net generation includes net exported electricity and 

loss of electricity that occurs through transmission and distribution.

Coal-fired generating units have historically supplied “base-load” electricity, the portion 

of electricity loads which are continually present, and typically operate throughout the day.

Along with nuclear generation, these coal units meet the part of demand that is relatively 

constant. Although much of the coal fleet operates as base load, there can be notable 

differences across various facilities (see Table 4-4). For example, coal-fired units less than 100 

MW in size compose 37 percent of the total number of coal-fired units, but only 6 percent of 

total coal-fired capacity. Gas-fired generation is better able to vary output and is the primary 

option used to meet the variable portion of the electricity load and typically supplies “peak” 

power, when there is increased demand for electricity (for example, when businesses operate 

throughout the day or when people return home from work and run appliances and 

heating/air-conditioning), versus late at night or very early in the morning, when demand for 

electricity is reduced.

The evolving economics of the power sector, in particular the increased natural gas 

supply and relatively low natural gas prices, have resulted in more gas being utilized as base 

load energy. Projections of new capacity and the impact of this rule on these new sources are 

discussed in more detail in Chapter 5 of this RIA.

Table 4-4. Coal Steam Electricity Generating Units, by Size, Age, Capacity, and Thermal 

Efficiency (Heat Rate)

Unit Size Grouping 

(MW) No. Units % of All Units Avg. Age

Avg. Net 

Summer 

Capacity 

(MW)

Total Net 

Summer 

Capacity 

(MW)

% Total 

Capacity

Avg. Heat 

Rate 

(Btu/kWh)

0 to 25 193 15% 45 15 2,849 1% 11,154

>25 to 49 108 9% 42 38 4,081 1% 11,722

50 to 99 162 13% 47 75 12,132 4% 11,328

100 to 149 269 21% 49 141 38,051 12% 10,641

150 to 249 81 6% 43 224 18,184 6% 10,303

250 and up 453 36% 34 532 241,184 76% 10,193
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Totals 1,266

Source: National Electric Energy Data System (NEEDS) v.4.10

Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed 

to a generation-weighted or capacity

level of fuel efficiency. Table is limited to 

units with planned retirements.

Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size

Source: National Electric Energy Data System (NEEDS

Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capa

end of 2011. This includes planned new builds and planned retirements. In areas with a dense 

concentration of facilities, some facilities may be obscured.

4.2.2 Transmission

Transmission is the term used to describe the movement of electricity over a network of 

high voltage lines, from electric generators to substations where power is stepped down for 

local distribution. In the US and Canada, there are three separate i

high voltage transmission lines,

1

transmission networks, there are multiple areas where the operation of power plants is 

 

1

These three network interconnections are the western US and Canada, corresponding approximate

west of the Rocky Mountains; eastern US and Canada, not including most of Texas; and a third network 

operating in most of Texas. These are commonly referred to as the Western Interconnect Region, Eastern 

Interconnect Region, and ERCOT, respe

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4-4

316,480

National Electric Energy Data System (NEEDS) v.4.10

The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed 

weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher 

efficiency. Table is limited to coal-steam units online in 2010 or earlier, and excludes those 

units with planned retirements.

Fired Electricity Generating Facilities, by Size

National Electric Energy Data System (NEEDS) 4.10 

facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capa

his includes planned new builds and planned retirements. In areas with a dense 

concentration of facilities, some facilities may be obscured.

Transmission is the term used to describe the movement of electricity over a network of 

high voltage lines, from electric generators to substations where power is stepped down for 

In the US and Canada, there are three separate interconnected networks of 

each operating at a common frequency. Within each of these 

transmission networks, there are multiple areas where the operation of power plants is 

These three network interconnections are the western US and Canada, corresponding approximate

west of the Rocky Mountains; eastern US and Canada, not including most of Texas; and a third network 

operating in most of Texas. These are commonly referred to as the Western Interconnect Region, Eastern 

Interconnect Region, and ERCOT, respectively.

Do Not Cite, Quote, Or Release During Review ***

The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed 

A lower heat rate indicates a higher 

steam units online in 2010 or earlier, and excludes those 

facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on-line by the 

his includes planned new builds and planned retirements. In areas with a dense 

Transmission is the term used to describe the movement of electricity over a network of 

high voltage lines, from electric generators to substations where power is stepped down for 

nterconnected networks of 

Within each of these 

transmission networks, there are multiple areas where the operation of power plants is 

These three network interconnections are the western US and Canada, corresponding approximately to the area 

west of the Rocky Mountains; eastern US and Canada, not including most of Texas; and a third network 

operating in most of Texas. These are commonly referred to as the Western Interconnect Region, Eastern 
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monitored and controlled to ensure that electricity generation and load are kept in balance. In 

some areas, the operation of the transmission system is under the control of a single regional 

operator; in others, individual utilities coordinate the operations of their generation, 

transmission, and distribution systems to balance their common generation and load needs.

4.2.3 Distribution

Distribution of electricity involves networks of lower voltage lines and substations that 

take the higher voltage power from the transmission system and step it down to lower voltage 

levels to match the needs of customers. The transmission and distribution system is the classic 

example of a natural monopoly, in part because it is not practical to have more than one set of 

lines running from the electricity generating sources to substations or from substations to 

residences and business.

Transmission has generally been developed by the larger vertically integrated utilities 

that typically operate generation and distribution networks. Distribution is handled by a large 

number of utilities that often purchase and sell electricity, but do not generate it. Over the last 

couple of decades, several jurisdictions in the United States began restructuring the power 

industry to separate transmission and distribution from generation, ownership, and operation.

As discussed below, electricity restructuring has focused primarily on efforts to reorganize the 

industry to encourage competition in the generation segment of the industry, including 

ensuring open access of generation to the transmission and distribution services needed to 

deliver power to consumers. In many states, such efforts have also included separating 

generation assets from transmission and distribution assets to form distinct economic entities.

Transmission and distribution remain price-regulated throughout the country based on the cost 

of service.

4.3 Deregulation and Restructuring

The process of restructuring and deregulation of wholesale and retail electric markets 

has changed the structure of the electric power industry. In addition to reorganizing asset 

management between companies, restructuring sought a functional unbundling of the 

generation, transmission, distribution, and ancillary services the power sector has historically 

provided, with the aim of enhancing competition in the generation segment of the industry.

Beginning in the 1970s, government policy shifted against traditional regulatory 

approaches and in favor of deregulation for many important industries, including 

transportation (notably commercial airlines), communications, and energy, which were all 

thought to be natural monopolies (prior to 1970) that warranted governmental control of 
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pricing. However, deregulation efforts in the power sector were most active during the 1990s.

Some of the primary drivers for deregulation of electric power included the desire for more 

efficient investment choices, the economic incentive to provide least-cost electric rates through 

market competition, reduced costs of combustion turbine technology that opened the door for 

more companies to sell power with smaller investments, and complexity of monitoring utilities’ 

cost of service and establishing cost-based rates for various customer classes.

The pace of restructuring in the electric power industry slowed significantly in response 

to market volatility in California and financial turmoil associated with bankruptcy filings of key 

energy companies. By the end of 2001, restructuring had either been delayed or suspended in 

eight states that previously enacted legislation or issued regulatory orders for its 

implementation (shown as “Suspended” in Figure 4-2 below). Another 18 other states that had 

seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory 

activity in 2001 (EIA, 2003) (“Not Active” in Figure 4-2 below). Currently, there are 15 states 

where price deregulation of generation (restructuring) has occurred (“Active” in Figure 4-2 

below). Power sector restructuring is more or less at a standstill; there have been no recent 

proposals to the Federal Energy Regulatory Commission (FERC) for actions aimed at wider 

restructuring, and no additional states have recently begun retail deregulation activity.

Figure 4-2. Status of State Electricity Industry Restructuring Activities

Source: EIA 2010b. 
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4.4 Emissions of Greenhouse Gases from Electric Utilities

The burning of fossil fuels, which generates about 70 percent of our electricity 

nationwide, results in emissions of greenhouse gases. The power sector is a major contributor 

of CO2 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), CH4, and N2O.

In 2009, the power sector accounted for 33 percent of total nationwide greenhouse gas

emissions, measured in CO2 equivalent, a slight increase from its 30 percent share in 1990.

Table 4-5 and Figure 4-3 show the contributions of the power sector relative to other major 

economic sectors. Table 4-6 and Figure 4-4 show the contributions of CO2 and other GHGs from 

the power sector.

Table 4-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric 

tons of CO2 equivalent)

Implied Sectors 1990 1995 2000 2005 2009

Electric Power Industry 1,869 1,995 2,338 2,445 2,193

Transportation 1,545 1,695 1,932 2,017 1,812

Industry 1,564 1,591 1,544 1,442 1,323

Agriculture 429 465 485 493 490

Commercial 396 397 381 387 410

Residential 345 367 386 371 360

U.S. Territories 34 41 46 58 46

Total Emissions 6,182 6,551 7,113 7,214 6,633

Source: EPA 2011
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Figure 4-3. Domestic Emissions of Greenhouse Gases, 2009 (million metric tons of CO2

equivalent)

Source: EPA 2011

Table 4-6. Electricity Generation-Related Greenhouse Gas Emissions, 2009 (million metric 

tons of CO2 equivalent)

Source Total Emissions

CO2 2,170.1

CO2 from Fossil Fuel Combustion 2,154.0

Coal 1,747.6

Natural Gas 373.1

Petroleum 32.9

Geothermal 0.4

Incineration of Waste 12.3

Limestone and Dolomite Use 3.8

CH4 0.7

Stationary Combustion* 0.7

Incineration of Waste +

N2O 9.4

Stationary Combustion* 9.0

Incineration of Waste 0.4

SF6

** 12.8
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Electrical Transmission and Distribution

Total

Source: EPA 2011

* Includes only stationary combustion emissions related to the generation of electricity.

** SF6 is not covered by this rule, which specifically regulates GHG emissions from combustion.

+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.

The amount of CO2 emitted during the combustion of fossil fuels varies according to the 

carbon content and heating value of

carbon content than oil or natural gas and, thus, releases more CO

emits around 1.7 times as much carbon per unit of energy when burned as does natural gas and 

1.25 times as much as oil (EPA 2011

Figure 4-4. GHG Emissions from the Power Sector 

(2009)

Source: EPA 2011

Table 4-7. Fossil Fuel Emission Factor

Fuel Type

Coal 

Bituminous 

Subbituminous 

Lignite 

Natural Gas 

Fuel Oil 

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Electrical Transmission and Distribution 12.8

2,193.0

Includes only stationary combustion emissions related to the generation of electricity.

covered by this rule, which specifically regulates GHG emissions from combustion.

Eq. or 0.05 percent.

emitted during the combustion of fossil fuels varies according to the 

carbon content and heating value of the fuel used (EIA, 2000) (see Table 4-7). Coal has higher 

carbon content than oil or natural gas and, thus, releases more CO2 during combustion. C

emits around 1.7 times as much carbon per unit of energy when burned as does natural gas and 

EPA 2011).

from the Power Sector Relative to Total Domestic GHG Emissions 

Fuel Emission Factors in EPA Modeling Applications

Carbon Dioxide (lbs/MMBtu

205.2 – 206.6

212.7 – 213.1

213.5 – 217.0

117.1

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12.8

2,193.0

emitted during the combustion of fossil fuels varies according to the 

7). Coal has higher 

during combustion. Coal 

emits around 1.7 times as much carbon per unit of energy when burned as does natural gas and 

al Domestic GHG Emissions 

Carbon Dioxide (lbs/MMBtu)
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4-10

Distillate 161.4

Residual 161.4 – 173.9

Biomass* 195

Waste Fuels 

Waste Coal 205.7

Petroleum Coke 225.1

Fossil Waste 321.1

Non-Fossil Waste 0

Tires 189.5

Municipal Solid Waste 91.9

Source: Documentation for IPM Base Case v.4.10. See also Table 9.9 of IPM Documentation.

Note: CO2 emissions presented here for biomass account for combustion only and do not reflect lifecycle 

emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon 

source).

4.5 Pollution Control Technologies

There are several methods to reduce CO2 emissions from the power sector, including: 

(1) carbon capture and storage; (2) improved fuel efficiency; (3) switching to lower-emitting 

fuels; (4) increased generation share from lower-emitting sources; (5) decreased loss of power 

via transmission and distribution systems; and (6) improved end-use efficiency lowering 

electricity demand for the same level of service provided. The first three strategies are within 

the sphere of a generator’s decision-making, whereas the latter two strategies are only 

indirectly related to generators. The fourth strategy is an inherent property of the power 

system responding to the implicit value of emissions as grid operators make dispatch decisions 

to meet electricity demand at least cost (including the cost of harmful emissions). Increased 

construction of natural gas-fired EGU capacity will increase the number of lower-emitting 

sources from which grid operators may select to meet electricity demand.

4.5.1 Carbon Capture and Storage (CCS)

Carbon capture technology has been successfully applied since 1930 on various 

industrial facilities and is currently in the demonstration phase for large-scale power sector 

applications. CCS can be achieved through either pre-combustion or post-combustion capture 

of CO2 from a gas stream associated with the fuel combusted. For post-combustion capture, 

flue gas CO2 stripping with a liquid absorbent which selectively reacts with the gaseous carbon 

dioxide by removing it from the combustion gas stream. The absorbent, upon saturation, 

transfers to a downstream operation which regenerates the absorbent by desorbing the CO2

back to gaseous form. The absorbent recycles back into the process to repeat the capture cycle 
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while the removed carbon dioxide is compressed, sent to storage and sequestered. This process 

is illustrated for a pulverized coal power plant in Figure 4-5.

Figure 4-5. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant

Source: Interagency Task Force on Carbon Capture and Storage 2010

Pre-combustion capture is mainly applicable to IGCC facilities, where the fuel is 

converted into gaseous components (“syngas”) under heat and pressure and the carbon 

contained in the syngas is captured before combustion. These processes are energy intensive. 

For post-combustion, a station's net generating output will be notably lower due to the energy 

needs of the capture process. For pre-combustion technology, a significant amount of energy is 

needed to gasify the fuel(s). This process is illustrated in Figure 4-6. For more detail on the 

current state of CCS technology, see the “Report of the Interagency Task Force on Carbon 

Capture and Storage” (2010).
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Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant

Source: Interagency Task Force on Carbon Capture and Storage 2010

4.5.2 Thermal Efficiency Improvements

As the thermal (i.e. fuel) efficiency of a coal-fired EGU is increased, less coal is burned 

per kilowatt-hour (kWh) generated, and there is a corresponding decrease in CO2 and other 

emissions per unit of energy generated. Numerous alternatives are available for improving 

generating unit efficiency (Sargent & Lundy, 2009). Regular maintenance can achieve and 

sustain optimal operational conditions, such as minimizing leakage of heat, assuring all 

components are operating optimally, maintaining furnace operation near peak efficiency, 

ensuring furnace soot removal system are functioning properly, and repairing tube leaks. 

Efficiency gains can also be achieved through replacement of inefficient or obsolete equipment, 

which can reduce parasitic power loads.1There are many small actions that can be undertaken 

which, cumulatively, can result in notable efficiency improvements. Such improvements include 

optimizing air pre-heaters, installing heat recovery systems, reducing steam leaks, and 

refurbishing the steam turbine. In a 2010 white paper, EPA summarized the efficiency 

improvement techniques identified by the National Energy Technology Laboratory (NETL) 

 

1

Reducing parasitic power loads increases the amount of generation for sale and therefore, where economical, 

plant managers have an incentive to avoid these losses. However, reducing these loads does not necessarily 

lower the gross CO2 emission rate of a plant, and therefore the structure of the proposed rule may not 

significantly increase the incentive to reduce these losses.
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through a review of published articles and technical papers (EPA, 2010). The summary of these 

findings is shown in Table 6-8.

Table 4-8. Existing Coal-Fired EGU Efficiency Improvements Reported for Actual Efficiency 

Improvement projects

Efficiency 

Improvement 

Technology

Description

Reported

Efficiency

Increasea

Combustion 

Control 

Optimization

Combustion controls adjust coal and air flow to optimize steam production 

for the steam turbine/generator set. The technologies include instruments 

that measure carbon levels in ash, coal flow rates, air flow rates, CO levels, 

oxygen levels, slag deposits, and burner metrics as well as advanced coal 

nozzles and plasma assisted coal combustion. Combustion control for a coalfired EGU is complex and impacts a number of important operating 

parameters including combustion efficiency, steam temperature, furnace 

slagging and fouling, and NOxformation. 

0.15 to 0.84%

Cooling System 

Heat Loss 

Recovery

Controls are applied to recover a portion of the heat loss from the warm 

cooling water exiting the steam condenser prior to its circulation thorough a 

cooling tower or discharge to a water body. The identified technologies 

include replacing the cooling tower fill (heat transfer surface) and tuning the 

cooling tower and condenser.

0.2 to 1%

Flue Gas Heat 

Recovery

Flue gas exit temperature from the air pre-heater can range from 250- 350°F 

depending on the acid dew point temperature of the flue gas, which is 

dependent on the concentration of vapor phase sulfuric acid and moisture. 

For power plants equipped with wet FGD systems, the flue gas is further 

cooled to approximately 125°F as it is sprayed with the FGD reagent slurry. 

However, it may be possible to recover some of this lost energy in the flue 

gas to preheat boiler feedwater via use of a condensing heat exchanger.

0.3 to 1.5%

(continued)
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Table 4-8. Existing Coal-Fired EGU Efficiency Improvements Reported for Actual Efficiency 

Improvement projects (continued)

Efficiency 

Improvement 

Technology

Description

Reported

Efficiency

Increasea

Low-rank Coal 

Drying

Subbituminous and lignite coals contain relatively large amounts of moisture 

(15 to 40%) compared to bituminous coal (less than 10%). A significant 

amount of the heat released during combustion of low-rank coals is used to 

evaporate this moisture, rather than generate steam for the turbine. As a 

result, boiler efficiency is typically lower for plants burning low-rank coal. 

The technologies include using waste heat from the flue gas and/or cooling 

water systems to dry low-rank coal prior to combustion.

0.1 to 1.7%

Soot Blower

Optimization

Soot blowers intermittently inject high velocity jets of steam or air to clean 

coal ash deposits from boiler tube surfaces in order to maintain adequate 

heat transfer. Proper control of the timing and intensity of individual soot 

blowers is important to maintain steam temperature and boiler efficiency. 

The identified technologies include intelligent or neural-network soot 

blowing (i.e., soot blowing in response to real-time conditions in the boiler) 

and detonation soot blowing.

0.1 to 0.65%

Steam Turbine

Design

Recoverable energy losses can result from the mechanical design or physical 

condition of the steam turbine. For example, steam turbine manufacturers 

have improved the design of turbine blades and steam seals which can 

increase both efficiency and output (i.e., steam turbine dense pack 

technology).

0.84 to 2.6%

Source: EPA 2010, NETL 2008

a Reported efficiency improvement metrics adjusted to common basis by conversion methodology assuming 

individual component efficiencies for a reference plant as follows: 87 percent boiler efficiency, 40 percent

turbine efficiency, 98 percent generator efficiency, and 6 percent auxiliary load. Based on these assumptions, 

the reference power plant has an overall efficiency of 32 percent and a net heat rate of 10,600 Btu/kWh. As a 

result, if a particular efficiency improvement method was reported to achieve a 1 percentage point increase in 

boiler efficiency, it would be converted to a 0.37 percentage point increase in overall efficiency. Likewise, a 

reported 100 Btu/kWh decrease in net heat rate would be converted to a 0.30 percentage point increase in 

overall efficiency.

In addition to the techniques described above, new coal-fired EGU projects may use 

other methods to maximize thermal efficiency. Under constant energy input, a higher pressure 

and temperature for the water-steam cycle will increase the overall efficiency. Most existing 

boilers, however, are already operating at the maximum pressure and temperature that the

boiler is designed to withstand. Most existing coal-fired EGUs have subcritical boilers that 

typically operate at a pressure of 2,400 pounds per square inch (psi) and temperatures between 

1,000 to 1,050°F. “Supercritical” boilers are those that use steam pressures above 3200 psi and 

temperatures up to 1,100°F. Boilers that can operate above these conditions are considered 
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“ultra-supercritical.” Examples of ultra-supercritical coal-fired EGUs in Canada, Europe, and 

Japan are cited as representing the highest efficiency coal-fired EGUs in the world (EPA, 2010). 

4.5.3 Other Approaches to Reduce GHG Emissions

While CCS and fuel efficiency improvements are more closely related to potential NSPS 

regulatory frameworks, they are not the only options available for EGUs to reduce emissions of 

CO2. As discussed previously, the amount of CO2 emitted during the combustion of fossil fuels 

varies according to the carbon content and heating value of the fuel used (see Table 4-7). 

Switching from a higher-emitting to a lower-emitting fuel will reduce CO2 emissions from an 

EGU, all other things equal. Similarly, increasing the share of generation from lower-emitting 

sources will also lead to a reduction in CO2 emissions. As with increased generation efficiency, 

improvements to efficiency in transmission and electricity use will also result in reductions in 

CO2 emissions. Note that these types of strategies would further reduce need for construction 

of new units. 

4.6 GHG Regulation in the Power Sector

In April 2007, the Supreme Court concluded that GHGs met the CAA definition of an air 

pollutant, giving EPA the authority to regulate GHGs under the CAA based on the agency 

determination that GHG emissions from new motor vehicles cause or contribute to air pollution 

that may reasonably be anticipated to endanger public health or welfare. This decision to 

regulate GHG emissions for motor vehicles set the stage for the determination of whether 

other sources of GHG emissions, including stationary sources, would need to be regulated as 

well.

In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110–

161), EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which 

required reporting GHG data and other relevant information from fossil fuel suppliers and 

industrial gas suppliers, direct greenhouse gas emitters, and manufacturers of heavy-duty and 

off-road vehicles and engines. The purpose of the rule was to collect accurate and timely GHG 

data to inform future policy decisions. As such, it did not require that sources control 

greenhouse gases, only that sources above certain threshold levels monitor and report 

emissions.

In August 2007, EPA issued a PSD permit to Deseret Power Electric Cooperative, 

authorizing it to construct a new waste-coal-fired EGU near its existing Bonanza Power Plant, in 

Bonanza, Utah. The permit did not include emissions control requirements for CO2. EPA 

acknowledged the Supreme Court decision, but found that decision alone did not require PSD 
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4-16

permits to include limits on CO2 emissions. Sierra Club challenged the Deseret permit. In 

November 2008, the Environmental Appeals Board (EAB) remanded the permit to EPA to 

reconsider “whether or not to impose a CO2 BACT limit in light of the ‘subject to regulation’ 

definition under the CAA.” The remand was based in part on EAB’s finding that there was not 

an established EPA interpretation of the regulatory phrase “subject to regulation.” 

In December 2008, the Administrator issued a memo indicated that the PSD Permitting 

Program would apply to pollutants that are subject to either a provision in the CAA or a 

regulation adopted by EPA under the CAA that requires actual control of emissions of that 

pollutant. The memo further explained that pollutants for which EPA regulations only require 

monitoring or reporting, such as the provisions for CO2 in the Acid Rain Program, are not 

subject to PSD permitting. Fifteen organizations petitioned EPA for reconsideration, prompting 

the agency to issue a revised finding in March 2009. After reviewing comments, EPA affirmed 

the position that PSD permitting is not triggered for a pollutant such as GHGs until a final 

nationwide rule requires actual control of emissions of the pollutant. For GHGs, this meant 

January 2011 when the first national rule limiting GHG emissions for cars and light trucks was 

scheduled to take effect. Therefore, a permit issued after January 2, 2011, it would have to 

address GHG emissions.

The Administrator signed two distinct findings in December 2009 regarding greenhouse 

gases under section 202(a) of the Clean Air Act. The endangerment finding indicated that 

current and projected concentrations of the six key well-mixed greenhouse gases —CO2, CH4, 

N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF6 — in the atmosphere 

threaten the public health and welfare of current and future generations. These greenhouse

gases have long lifetimes and, as a result, become homogeneously distributed through the 

lower level of the Earth’s atmosphere (IPCC, 2001). This differentiates them from other 

greenhouse gases that are not homogeneously distributed in the atmosphere. The cause and 

contribute finding indicated that the combined emissions of these well-mixed greenhouse gases 

from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas 

pollution which threatens public health and welfare. Both findings were published in the 

Federal Register on December 15, 2009 (Docket ID EPA-HQ-OAR-2009-0171). These findings did 

not themselves impose any requirements on industry or other entities, but allowed EPA to 

regulate greenhouse gases under the Clean Air Act. This action was a prerequisite to 

implementing the EPA's proposed greenhouse gas emission standards for light-duty vehicles, 

which was finalized in January 2010. Once a pollutant is regulated under the Clean Air Act, it is 

subject to permitting requirements under the PSD and Title V programs.
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In May 2010, EPA issued the final Tailoring Rule which set thresholds for GHG emissions 

that define when permits under the New Source Review PSD and Title V Operating Permit 

programs are required for new and existing industrial facilities. Facilities responsible for nearly 

70 percent of the national GHG emissions from stationary sources, including EGUs, were 

subject to permitting requirements under the rule.

EPA entered into two proposed settlement agreements in December 2010 to issue rules 

that will address greenhouse gas emissions from fossil fuel-fired power plants and refineries.

These two industrial sectors make up nearly 40 percent of the nation’s greenhouse gas 

emissions. For natural gas, oil, and coal-fired EGUs this rule establishes NSPS for new and 

reconstructed sources, with the exception of combustion turbines.. Existing source standards 

will be addressed in a later action. Details of the settlement agreements can be found on the 

EPA website.1

4.7 Revenues, Expenses, and Prices

Due to lower retail electricity sales, total utility operating revenues declined in 2009 to 

$276 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 

levels in 2010, operating expenses were appreciably lower and as a result, net income also rose 

in comparison to both 2008 and 2009 (see Table 4-9). Recent economic events have put 

downward pressure on electricity demand, thus dampening electricity prices and consumption 

(utility revenues), but have also reduced the price and cost of fossil fuels and other expenses.

Electricity sales and revenues associated with the generation, transmission, and distribution of 

electricity are expected to rebound and increase modestly by 2015, when revenues are 

projected to be roughly $360 billion (see Table 4-10).

Table 4-9 shows that investor-owned utilities (IOUs) earned income of about 11.5

percent compared to total revenues in 2009. Based on EIA's Annual Energy Outlook 2011, Table 

4-10 shows that the power sector is projected to derive revenues of $360 billion in 2015.

Assuming the same income ratio from IOUs (with no income kept by public power), and using 

the same proportion of power sales from public power as observed in 2009, EPA projects that 

the power sector will expend over $320 billion in 2015 to generate, transmit, and distribute 

electricity to end-use consumers.

Over the past 50 years, real retail electricity prices have ranged from around 7 cents per 

kWh in the early 1970s, to around 11 cents, reached in the early 1980s. Generally, retail 

 

1

http://www.epa.gov/airquality/ghgsettlement.html
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electricity prices do not change rapidly and do not display the variability of other energy or 

commodity prices, although the frequency at which these prices change varies across different 

types of customers. Retail rate regulation has largely insulated consumers from the rising and 

falling wholesale electricity price signals whose variation in the marketplace on an hourly, daily, 

and seasonal basis is critical for driving lowest-cost matching of supply and demand. In fact, the 

real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 4-7).

Table 4-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities 

for 2010 ($millions)

2008 2009 2010

Utility Operating Revenues 298,962 276,124 284,373

Electric Utility 266,124 249,303 260,113

Other Utility 32,838 26,822 24,260

Utility Operating Expenses 267,263 244,243 250,122

Electric Utility 236,572 219,544 226,845

Operation 175,887 154,925 159,585

Production 140,974 118,816 128,808

Cost of Fuel 47,337 40,242 44,115

Purchased Power 84,724 67,630 67,284

Other 8,937 10,970 13,013

Transmission 6,950 6,742 6,948

Distribution 3,997 3,947 4,007

Customer Accounts 5,286 5,203 5,091

Customer Service 3,567 3,857 4,741

Sales 225 178 185

Admin. and 

General 14,718 15,991 17,115

Maintenance 14,192 14,092 14,962

Depreciation 19,049 20,095 20,930

Taxes and Other 26,202 29,081 27,646

Other Utility 30,692 24,698 23,277

Net Utility Operating Income 31,699 31,881 34,251

Source: EIA 2010a

Note: This data does not include information for public utilities.
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Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and Investor

Owned Utilities (billions)

Generation $195

Transmission 36

Distribution 129

Total $360

Source: EIA 2011

Note: Data are derived by taking either total electricity use (for generation) or sales (transmission and 

distribution) and multiplying by forecasted prices by service category from Table 8 

Supply, Disposition, Prices, and Emissions).

Figure 4-7. National Average Retail Electricity Price (1960 

Source: EIA 2010a

On a state-by-state basis, retail electricity prices vary considerably.

California have average retail prices that can be as much as double tho

Figure 4-8).

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Projected Revenues by Service Category in 2015 for Public Power and Investor

Owned Utilities (billions)

Data are derived by taking either total electricity use (for generation) or sales (transmission and 

distribution) and multiplying by forecasted prices by service category from Table 8 of EIA 2011 

Supply, Disposition, Prices, and Emissions).

National Average Retail Electricity Price (1960 – 2009)

state basis, retail electricity prices vary considerably. The Northeast and 

California have average retail prices that can be as much as double those of other states (see 

Do Not Cite, Quote, Or Release During Review ***

Projected Revenues by Service Category in 2015 for Public Power and InvestorData are derived by taking either total electricity use (for generation) or sales (transmission and 

of EIA 2011 (Electricity 

Northeast and 

se of other states (see 
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Figure 4-8. Average Retail Electricity Price by State (cents/kWh), 2009

Source: EIA 2009

4.7.1 Natural Gas Market

The natural gas market in the United States has historically experienced significant price 

volatility from year to year, between seasons within a year, and can undergo major price swings 

during short-lived weather events (such as cold snaps leading to short-run spikes in heating 

demand). Over the last decade, gas prices (both Henry Hub prices and delivered prices to the 

power sector) have ranged from $3 per mmBtu to as high as $9 on an annual average basis (see 

Figure 4-9). During that time, the daily price of natural gas reached as high as $15/mmBtu.

Recent forecasts of natural gas have also experienced considerable revision as new sources of 

gas have been discovered and have come to market, although there continues to be some 

uncertainty surrounding the precise quantity of the resource base.
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Figure 4-9. Natural Gas Spot Price, Annual Average (Henry Hub)

Source: EIA 2010c, EIA 2011

4.8 Electricity Demand and Demand Response

Electricity performs a vital and high-value function in the economy. Historically, growth 

in electricity consumption has been closely aligned with economic growth. Overall, the U.S. 

economy has become more efficient over time, producing more output (GDP) per unit of 

energy input, with per capita energy use fairly constant over the past 30 years (EIA, 2010d). The 

growth rate of electricity demanded has also been in overall decline for the past sixty years (see 

Figure 4-8), with several key drivers that are worth noting. First, there has been a significant 

structural shift in the U.S. economy towards less energy-intensive sectors, like services. Second, 

companies have strong financial incentives to reduce energy expenditures. Third, companies 

are responding to the marketplace and continually develop and bring to market new 

technologies that reduce energy consumption. Fourth, other policies, such as energy efficiency 

standards at the state and Federal level, have helped address certain market failures. These 

broader changes have altered the outlook for future electricity growth (see Figure 4-10). 
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Figure 4-10. Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual 

Energy Outlook 2011

Source: EIA 2009, EIA 2011

Energy efficiency initiatives have become more common, and investments in energy 

efficiency are projected to continue to increase for the next 5 to 10 years, driven in part by the 

growing number of states that have adopted energy efficiency resource standards.1These 

investments, and other energy efficiency policies at both the state and federal level, create 

incentives to reduce energy consumption and peak load. According to EIA, demand-side 

management provided actual peak load reductions of 31.7 GW in 2009. For context, the current 

coal fleet is roughly 320 GW of capacity.

Demand for electricity, especially in the short run, is not very sensitive to changes in 

prices and is considered relatively price inelastic, although some demand reduction does occur 

in response to price. With that in mind, EPA modeling does not typically incorporate a “demand 

response” in its electric generation modeling (Chapter 5) to the increases in electricity prices 

typically projected for EPA rulemakings. Electricity demand is considered to be constant in EPA 

modeling applications and the reduction in production costs that would result from lower 

demand is not considered in the primary analytical scenario that is modeled. This leads to some 

overstatement in the private compliance costs that EPA estimates for rules where compliance 

 

1

To the extent that EIA includes these measures in its baseline forecast from the Annual Energy Outlook, EPA has 

also incorporated them into the baseline for purposes of assessing the economic impacts of this proposed rule. 

See AEO 2011 and Chapter 7 of the IPM documentation for more detail.

-2%

0%

2%

4%

6%

8%

10%

12%
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costs are anticipated for a rulemaking. Note that this NSPS is not anticipated to create 

compliance costs for new EGU sources. 

4.9 References

Interagency Task Force on Carbon Capture and Storage. Report of the Interagency Task Force on 

Carbon Capture and Storage. August 2010. Available online at: 

http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf.

Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. 2001. 

Available online at: 

http://www.grida.no/publications/other/ipcc_tar/?src=/climate/ipcc_tar/wg1/218.htm.

National Energy Technology Laboratory (NETL). Reducing CO2 Emissions by Improving the 

Efficiency of Existing Coal-fired Power Plant Fleet. July 2008. Available online at: 

http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf. 

Pacific Northwest National Laboratory (PNNL). An Assessment of the Commercial Availability of 

Carbon Dioxide Capture and Storage Technologies as of June 2009. June 2009. Available 

online at: http://www.pnl.gov/science/pdf/PNNL-18520_Status_of_CCS_062009.pdf.

Sargent & Lundy, LLC. Coal-fired Power Plant Heat Rate Reductions. January 2009. Available 

online at: http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.

U.S. Energy Information Administration (U.S. EIA). Carbon Dioxide Emissions from the 

Generation of Electric Power in the United States. July 2000. Available online at: 

ftp://ftp.eia.doe.gov/environment/co2emiss00.pdf.

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2003. 2003. Available 

online at: http://www.eia.gov/electricity/annual/archive/03482003.pdf. 

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2009. 2009. Available 

online at: http://www.eia.gov/electricity/annual/archive/03482009.pdf. 

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2010. 2010a. Available 

online at: http://www.eia.gov/electricity/annual/.

U.S. Energy Information Administration (U.S. EIA). “Status of Electricity Restructuring by State.” 

2010b. Available online at: 

http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010c. 

Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Review 2010. 2010d. Available 

online at: http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.
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U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011. 2011. Available 

online at: http://www.eia.gov/forecasts/aeo/.

U.S. Environmental Protection Agency (U.S. EPA). Available and Emerging Technologies for 

Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units. October 

2010. Available online at: http://www.epa.gov/nsr/ghgdocs/electricgeneration.pdf. 

U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990–2009. April 2011. Available online at: 

http://epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-

Complete_Report.pdf.