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CHAPTER 2

ELECTRIC POWER SECTOR PROFILE

2.1 Introduction

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

MATS Rule, including the types of power-sector sources affected by the rule, and provides 

background on the power sector and electric generating units (EGUs). In addition, this chapter 

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

sector. The specific impacts of MATS are discussed in Chapter 3.

2.2 Power Sector Overview

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

segments: generation, transmission, and distribution.

2.2.1 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 2-1).

Table 2-1. Existing Electricity Generating Capacity by Energy Source, 2009

Energy Source Number of Generators

Generator Nameplate 

Capacity (MW)

Generator Net 

Summer Capacity 

(MW)

Coal 1,436 338,723 314,294

Petroleum 3,757 63,254 56,781

Natural Gas 5,470 459,803 401,272

Other Gases 98 2,218 1,932

Nuclear 104 106,618 101,004

Hydroelectric Conventional 4,005 77,910 78,518

Wind 620 34,683 34,296

Solar Thermal and Photovoltaic 110 640 619

Wood and Wood Derived Fuels 353 7,829 6,939

Geothermal 222 3,421 2,382

Other Biomass 1,502 5,007 4,317

Pumped Storage 151 20,538 22,160

Other 48 1,042 888

Total 17,876 1,121,686 1,025,402

Source: EIA (2009).
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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 2-2). 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 2-2. Total U.S. Electric Power Industry Retail Sales in 2009 (Billion kWh)

Sales/Direct Use (Billion kWh) Share of Total End Use

Retail Sales

Residential 1,364 37%

Commercial 1,307 35%

Industrial 917 25%

Transportation 8 0.2%

Direct Use 127 3%

Total End Use 3,723 100%

Source: EIA (2009).

In 2009, electric generating sources produced 3,950 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 2-3).

Table 2-3. Electricity Net Generation in 2009 (Billion kWh)

Net Generation (Billion kWh) Fuel Source Share

Coal 1,756 44.5%

Petroleum 39 1.0%

Natural Gas 921 23.3%

Other Gases 11 0.3%

Nuclear 799 20.2%

Hydroelectric 273 6.9%

Other 151 3.8%

Total 3,950 100%

Source: EIA (2009).

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.
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Coal-fired generating units typically supply “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 2-4). 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/airconditioning), versus late at night or very early in the morning, when demand for electricity is 

reduced. However, 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. Figure 2-1 shows the distribution and relative size of the fossil-fuel fired 

generating capacity across the United States.

Table 2-4. Coal Steam Electricity Generating Units, by Size, Age, Capacity, and 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

Total 1,266 316,480

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

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

units with planned retirements.
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Figure 2-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size

Source: National Electric Energy Data System (NEEDS) 4.10

Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on-line by the 

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

concentration of facilities, some facilities may be obscured.

2.2.2 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 interconnected networks of 

high voltage transmission lines,

1

each operating at a common frequency. Within each of these 

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

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.

 

1

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 

Interconnect Region, and ERCOT, respectively.
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2.2.3 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.

2.3 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 

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 
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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 2-2 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 2-2 below). Currently, there are 15 states 

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

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 2-2. Status of State Electricity Industry Restructuring Activities

Source: EIA (2010b).

2.4 Emissions of Mercury and Other Hazardous Air Pollutants from Electric Utilities

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

nationwide, results in air emissions of Hazardous Air Pollutants (HAPs): mercury, acid gasses, 

and non-mercury metallic particulates. Additionally, SO2 and NOx emissions from the power 
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sector are important precursors in the formation of fine particles and ozone (NOx only). The 

power sector is a major contributor of all of these pollutants.

The Emissions Overview Memorandum Technical Support Document (TSD) to the 

proposed air toxics standards (Docket number EPA-HQ-OAR-2009-0234) details the emissions 

of mercury and other HAPs emitted by EGUs. In 2005, EGU emissions of mercury accounted for 

approximately half of all anthropogenic mercury emissions in the U.S. Table 2-5 shows the 

trend in EGU and total anthropogenic mercury emissions from 1990–2005 and EGU mercury 

emissions reported in the Utility MACT Information Collection Request (ICR) in 2010.

Table 2-5. U.S. Anthropogenic Mercury Emissions, 1990–2010

1990

(tons)

1999

(tons)

2005

(tons)

2010a

(tons)

EGU Hg Emissions 59 49 53 29

Non-EGU Hg Emission 205 66 52 Not Availableb

Total U.S. Hg Emissions 264 115 105 Not Availableb

a

The estimate of the current level of Hg emissions based on the 2010 ICR database may underestimate total EGU 

Hg emissions due to targeting of the 2010 ICR on the best performing EGUs.

b

Information on recent U.S. EGU emissions was obtained using an ICR for EGUs only. This same information is not 

available for other sources, which were not covered by the ICR.

In 2005, EGUs contributed 82 percent of U.S. hydrogen chloride emissions. Table 2-6 

shows the total HCl emissions from EGU and non-EGU sources in 2005 and the EGU HCl 

emissions reported in the Utility MACT ICR in 2010.

Table 2-6. U.S. Hydrogen Chloride Emissions, 2005 and 2010

2005a

(tons)

2010b

(tons)

EGU HCl Emissions 350,000 106,000

Non-EGU HCl Emissions 78,000 Not Availablec

Total U.S. HCl Emissions 428,000 Not Availablec

a 2005 emissions from the National Air Toxics Assessment Inventory. Available online at 

http://www.epa.gov/ttn/atw/nata2005/. EGU emissions were extracted from the total using the MACT code 

field (1808).

b The estimate of the current level of Hg emissions based on 2010 may underestimate the total EGU emissions due 

to targeting of the 2010 ICR on the best performing EGUs.

c Information on recent U.S. EGU emissions was obtained using an ICR for EGUs only. This same information is not 

available for other sources, which were not covered by the ICR.
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Individual fossil fuel-fired units vary widely in their air emissions levels for HAPs, 

particularly when uncontrolled. In 2010, as reported in the Utility MACT ICR, mercury emissions 

range from less than 0.3 lb/trillion Btu (TBtu) to more than 20 lbs/TBtu. HCl emissions from 

coal-fired units range from less than 0.00002 lb/million Btu (mmBtu) (for a unit with a scrubber) 

to over 0.1 lb/mmBtu. Additionally, emissions of fine particulates less than or equal to 2.5 

microns (PM2.5) range from 0.002 lb/mmBtu to over 0.06 lb/mmBtu. For an uncontrolled plant, 

mercury, acid gas, and particulate emissions are directly related to the elemental profile and 

ash content of the coal burned.

Oil-fired units also have a wide range of HAP emissions. Based on the Utility MACT ICR, 

Mercury emissions range from less than 0.01 lb/TBtu to more than 60 lbs/TBtu. HCl emissions 

from oil-fired units range from less than 0.00001 lb/mmBtu (for a unit with a scrubber) to over 

0.003 lb/mmBtu. Emissions of PM2.5 range from less than 0.004 lb/mmBtu to over 0.07 

lb/mmBtu.

2.5 Pollution Control Technologies

Acid gas HAPs (e.g., hydrogen chloride (HCl), hydrogen fluoride (HF), sulfur dioxide 

(SO2)) from coal-fired power plants can be controlled by fuel selection, fuel blending, or post 

combustion controls. Fossil fuels, particularly coal, vary widely in the content of pollutants like 

chlorine (Cl), fluorine (F), sulfur (S) and other HAPs, making fuel blending and/or switching an 

effective method for reducing emissions of HAPs. In general, it is easier to switch fuels within a 

coal rank (rather than across a coal rank) due to similar heat contents and other characteristics.

Switching fuels across ranks tends to trigger more costly modifications. As a compromise, 

blending is employed when a complete fuel switch adversely affects the unit. EGUs may also 

choose to retrofit post combustion controls to achieve superior pollutant removal. Postcombustion controls typically remove larger proportions of HCl and HF than SO2 due to 

differences in molecular weight.

Acid gas emissions (including SO2) can be reduced with flue gas desulfurization (FGD, 

also known as “scrubbers”) or with dry sorbent injection (DSI). EGUs may choose either “wet”

or “dry” configurations of scrubbers. Wet scrubbers can use a variety of reagents including 

crushed limestone, quick lime, and magnesium-enhanced lime. The choice of reagent affects 

performance, size, capital and operating costs. Current wet scrubber technology is capable of 

removing at least 99 percent of HF and HCl emissions while simultaneously achieving 

96 percent SO2 removal. Modern dry FGD technology combines lime-based slurry with a 

downstream fabric filter to remove at least 93 percent SO2 while also capturing over 99 percent
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HCL and HF. An alternative to scrubber technology is dry sorbent injection (DSI), which injects 

an alkaline powdered material (post combustion) to react with the acid gases. The product of 

this reaction is removed by particulate matter (PM) control device. DSI technology is most 

efficient with a baghouse present downstream but can function with an electrostatic 

precipitator (ESP) downstream as well. Under these circumstances, the ESP requires more 

reagent per molecule of acid gas removed as compared to a similar operation with a baghouse.

Finally, DSI may employ a multitude of sorbents (trona,

2

sodium carbonate, calcium 

carbonate—and their bicarbonate counterparts) for a more tailored approach to reduce 

emissions based on the source, cost, and unit and fuel characteristics.

Mercury capture and removal requires multiple controls. Upon combustion, mercury 

exits the furnace in three forms: elemental, oxidized, and as a particulate. Elemental mercury is 

emitted out of the stack. The particulate form is bound to the ash and removed by PM control 

equipment such as ESP or fabric filter. A portion of mercury that has converted to oxidized 

compounds may be removed by either a wet scrubber or by activated carbon injection (ACI).

Each of these control devices uses a different method to remove the mercury compounds. The 

wet FGD system captures oxidized mercury because it is water soluble, while activated carbon 

injection provides a unique physical surface to which oxidized mercury can adhere. Mercury 

oxidation can occur at multiple locations within a unit as long as an oxidizing agent, generally a 

halogen, is present for reaction. This allows the unit operator some latitude in selecting a 

control method and injection point based on existing equipment at the particular source. A 

halogen can be introduced to the fuel prior to combustion, injected directly into the furnace, 

introduced upstream of a selective catalytic reduction (SCR) system,

3

or infused with the 

activated carbon injections. The unit operator may also increase halogens by blending in higher 

chlorine fuels (e.g., Powder River Basin fuel blended with bituminous coal). Operating a wet 

FGD for SO2 control alongside selective catalytic reduction (SCR) for NOx control with sufficient 

halogen present will remove more than 90 percent of the mercury within the flue gas stream.

Alternatively, in the absence of a wet FGD, activated carbon injection (ACI) can be employed for 

mercury capture with at least 90 percent removal using a downstream fabric filter. An ESP 

results in less efficient mercury removal with ACI.

Non-mercury heavy metals and organics are removed by PM control equipment such as 

fabric filters and ESP. Unlike mercury, the heavy metals (e.g., selenium and arsenic) are nonvolatile and affix to the ash. Likewise, any organics surviving the high temperature combustion 

 

2

Trona refers to the chemical compound sodium sesquicarbonate.

3

SCR is primarily used for NOx control, but can also be used to promote mercury oxidation.
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process are non-volatile and bind to the ash. Both control technologies are capable of removing 

more than 99 percent of PM2.5 mass from the emissions stream. ESPs sap relatively little energy 

from the flue gas but are less flexible for fuel switching, since they are designed for use with a 

specific intended fuel. Fuel switching or blending that increases gas flow rate, ash resistivity, or 

particle loading may render an existing ESP insufficient for removing particulate matter. ESPs 

also suffer from ash re-entrainment, which is the release of particulate matter from the last 

compartment due to the self cleaning action. On the other hand, an ESP with sufficient design 

margin may succeed with these fuel alterations. Conversely, a fabric filter does not suffer from 

these limitations. Moreover, the fabric filter readily lends itself to mercury and acid gas removal 

since DSI and ACI operate more efficiently with a baghouse. When considering retrofit PM 

control options, a unit with an existing ESP will examine upgrading the precipitator as an 

alternative to installing a new fabric filter to achieve emission reductions.

For more detail on the cost and performance assumptions of pollution controls, see the 

documentation for the Integrated Planning Model (IPM),

4

a dynamic linear programming model 

that EPA uses to examine air pollution control policies for various air emissions throughout the 

United States for the entire power system.

2.6 HAP Regulation in the Power Sector

2.6.1 Programs Targeting HAP

In 2000, EPA made a finding that it was appropriate and necessary to regulate coal- and 

oil-fired EGUs under CAA section 112 and listed EGUs pursuant to CAA section 112(c). This 

finding triggered a requirement for EPA to propose regulations to control air toxics emissions, 

including mercury, from these facilities.

On January 30, 2004, EPA proposed a rule with two basic approaches for controlling 

mercury from power plants. One approach would require power plants to meet emissions 

standards reflecting the application of the “maximum achievable control technology” (MACT) 

determined according to the procedure set forth in section 112(d) of the Clean Air Act. A 

second approach proposed by EPA would create a market-based “cap and trade” program that, 

if implemented, would reduce nationwide utility emissions of mercury in two phases under 

Section 111 or Section 112 of the Clean Air Act. EPA also proposed to revise its December 2000 

finding that it is “appropriate and necessary” to regulate utility hazardous air emissions using 

the MACT standards provisions (section 112) of the Clean Air Act.

 

4

Documentation for IPM can be found at www.epa.gov/airmarkets/epa-ipm.
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On March 15, 2005, EPA issued the final Clean Air Mercury Rule (CAMR). CAMR 

established “standards of performance” limiting mercury emissions from new and existing 

utilities and created a market-based cap-and-trade program to reduce nationwide utility 

emissions of mercury in two phases. In conjunction with CAMR, EPA published a final rule 

(Section 112(n) Revision Rule) that removed EGUs from the list of sources for which regulation 

under CAA section 112 was required.

The Section 112(n) Revision Rule was vacated on February 8, 2008, by the U.S. Court of 

Appeals for the District of Columbia Circuit. As a result of that vacatur, CAMR was also vacated 

and EGUs remained on the list of sources that must be regulated under CAA section 112. This 

action finalizes the rule EPA proposed on March 16, 2011 to replace CAMR in response to the 

court’s decisions.

2.6.2 Programs Targeting SO2 and NOx

Programs to reduce SO2 and NOx also impact emissions of mercury and other HAP. At 

the federal level, efforts to reduce emissions of SO2 have been occurring since 1970. Policy 

makers have recognized the need to address these harmful emissions, and incremental steps 

have been taken to ensure that the country meets air quality standards. The recently finalized 

Cross State Air Pollution Rule (CSAPR) is the next step toward attainment of the national 

standards for PM2.5 and ozone.

Even before widespread regulation of SO2 and NOX for the power sector, total 

suspended particulate matter (TSP) was a related target of state and federal action. Because 

larger particulates are visible as dark smoke from smokestacks, most states had regulations by 

1970 limiting the opacity of emissions. Requirements for taller smokestacks also mitigated local 

impacts of TSP. Notably, such regulations effectively addressed large-diameter, filterable 

particulate matter rather than condensable particulate matter (such as PM2.5) associated with 

SO2 and NOX emissions, which are not visible at the smokestack and have impacts far from their 

sources.

Federal regulation of SO2 and NOX emissions at power plants began with the 1970 Clean 

Air Act. The Act required the Agency to develop New Source Performance Standards (NSPS) for 

a number of source categories including coal-fired power plants. The first NSPS for power 

plants (subpart D) required new units to limit SO2 emissions either by using scrubbers or by 

using low sulfur coal. NOX was required to be limited through the use of low NOX burners. A 

new NSPS (subpart Da), promulgated in 1978, tightened the standards for SO2, requiring 

scrubbers on all new units.
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The 1990 Clean Air Act Amendments (CAAA) placed a number of new requirements on 

power plants. The Acid Rain Program, established under Title IV of the 1990 CAAA, requires 

major reductions of SO2 and NOX emissions. The SO2 program sets a permanent cap on the 

total amount of SO2 that can be emitted by electric power plants in the contiguous United 

States at about one-half of the amount of SO2 these sources emitted in 1980. Using a 

market-based cap and trade mechanism allows flexibility for individual combustion units to 

select their own methods of compliance with the SO2 reduction requirements. The program 

uses a more traditional approach to NOX emissions limitations for certain coal-fired electric 

utility boilers, with the objective of achieving a 2 million ton reduction from projected NOX

emission levels that would have been emitted in 2000 without implementation of Title IV.

The Acid Rain Program comprises two phases for SO2 and NOX. Phase I applied primarily 

to the largest coal-fired electric generating sources from 1995 through 1999 for SO2 and from 

1996 through 1999 for NOX. Phase II for both pollutants began in 2000. For SO2, it applies to 

thousands of combustion units generating electricity nationwide; for NOX it generally applies to 

affected units that burned coal during 1990 through 1995. The Acid Rain Program has led to 

the installation of a number of scrubbers on existing coal-fired units as well as significant fuel 

switching to lower sulfur coals. Under the NOX provisions of Title IV, most existing coal-fired 

units installed low NOX burners.

The CAAA also placed much greater emphasis on control of NOX to reduce ozone 

nonattainment. This led to the formation of several regional NOX trading programs as well as 

intrastate NOX trading programs in states such as Texas. The northeastern states of the Ozone 

Transport Commission (OTC) required existing sources to meet Reasonably Available Control 

Technology (RACT) limits on NOX in 1995 and in 1999 began an ozone-season cap and trade 

program to achieve deeper reductions. In 1998, EPA promulgated regulations (the NOX SIP Call) 

that required 21 states in the eastern United States and the District of Columbia to reduce NOX

emissions that contributed to nonattainment in downwind states using the cap and trade 

approach. This program began in May of 2003 and has resulted in the installation of significant 

amounts of selective catalytic reduction.

The Clean Air Interstate Rule (CAIR) built on EPA’s efforts in the NOX SIP call to address 

specifically interstate pollution transport for ozone, and was EPA’s first attempt to address 

interstate pollution transport for PM2.5. It required significant reductions in emissions of SO2

and NOX in 28 states and the District of Columbia (see Figure 6-4 below). EGUs were found to 

be a major source of the SO2 and NOX emissions which contributed to fine particle 

concentrations and ozone problems downwind. Although the D.C. Circuit remanded the rule to 
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EPA in 2008, it did so without vacatur, allowing the rule to remain in effect while EPA addressed

the remand. Thus, CAIR continued to help states address ozone and PM2.5 nonattainment and 

improve visibility by reducing transported precursors of SO2 and NOX through the 

implementation of three separate cap and trade compliance programs for annual NOX, ozone 

season NOX, and annual SO2 emissions from power plants.

Perhaps in anticipation of complying with CAIR, especially the more stringent second 

phase that was set to begin in 2015, several sources began installing or planning to install 

advanced controls for SO2 and NOX to begin operating in the 2010 to 2015 timeframe. Many 

EPA New Source Review (NSR) settlements also required controls in those years, as do state 

rules in Georgia, Illinois, and Maryland. States like North Carolina, New York, Connecticut, 

Massachusetts, and Delaware have also moved to control these emissions to address 

nonattainment. 

On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to replace 

CAIR. The rule requires states to eliminate the portion of their emissions defined as their 

“significant contribution” by setting a pollution limit (or budget) for each covered state. The 

rule allows air-quality-assured allowance trading among covered sources, utilizing an allowance 

market infrastructure based on existing, successful allowance trading programs. The final 

CSAPR allows sources to trade emissions allowances with other sources within the same 

program (e.g., ozone season NOx) in the same or different states, while firmly constraining any 

emissions shifting that may occur by requiring a strict emission ceiling in each state (the budget 

plus variability limit). It also includes assurance provisions that ensure each state will make the 

emission reductions necessary to fulfill the “good neighbor” provision of the Clean Air Act.

2.7 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. However, operating expenses were 

appreciably lower and as a result, net income actually rose modestly compared to 2008 (see 

Table 2-7). 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, where they are projected to be roughly $360 billion (see Table 2-8).

Based on EIA’s Annual Energy Outlook 2011, Table 2-8 shows that in the base case, the 

power sector is expected to derive revenues of $360 billion in 2015. Table 2-7 shows that 
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investor-owned utilities (IOUs) earned income of about 11.5% compared to total revenues in 

2009. 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 alone 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 

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 2-3).
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Table 2-7. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities 

for 2009 ($millions)

2008 2009

Utility Operating Revenues 298,962 276,124

Electric Utility 266,124 249,303

Other Utility 32,838 26,822

Utility Operating Expenses 267,263 244,243

Electric Utility 236,572 219,544

Operation 175,887 154,925

Production 140,974 118,816

Cost of Fuel 47,337 40,242

Purchased Power 84,724 67,630

Other 8,937 10,970

Transmission 6,950 6,742

Distribution 3,997 3,947

Customer Accounts 5,286 5,203

Customer Service 3,567 3,857

Sales 225 178

Administrative and General 14,718 15,991

Maintenance 14,192 14,092

Depreciation 19,049 20,095

Taxes and Other 26,202 29,081

Other Utility 30,692 24,698

Net Utility Operating Income 31,699 31,881

Source: EIA (2009).

Note: These data do not include information for public utilities.

Table 2-8. Projected Revenues by Service Category in 2015 for Public Power and InvestorOwned 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 (Electricity Supply, 

Disposition, Prices, and Emissions).
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Figure 2-3. National Average Retail Electricity Price (1960–2009)

Source: EIA (2009).

On a state-by-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 

Figure 2-4).

Figure 2-4. Average Retail Electricity Price by State (cents/kWh), 2009

Source: EIA (2009).
2-17

2.7.1 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 Hub5prices 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 2-5). 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.6

Figure 2-5. Natural Gas Spot Price, Annual Average (Henry Hub)

Source: EIA (2010a), EIA (2011).

 

5

The Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange. 

It is a point on the natural gas pipeline system that interconnects nine interstate and four intrastate pipelines.

6

In August, EIA announced it would lower its previous estimates of recoverable shale gas by nearly 80 percent. 

EPA’s modeling of the natural gas market is discussed in more detail in Chapter 7 of this RIA.
2-18

2.8 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. The growth rate 

of electricity demanded has also been in overall decline for the past sixty years (see Figure 2-8), 

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 2-6).

Figure 2-6. Electricity Growth Rate (3 Year Rolling Average) and Projections from the 

Annual Energy Outlook 2011

Source: EIA (2009), EIA (2011).
2-19

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.7These 

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 3) 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. Notably, the “compliance 

costs” are the changes in the electric power generation costs in the base case and pollution 

control options that are evaluated in Chapter 3. In simple terms, it is the resource costs of what 

the power industry will directly expend to comply with EPA’s requirements.

2.9 References

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

online at: http://www.eia.gov/oiaf/archive/aeo03/index.html.

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

online at: http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html.

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

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

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 2011. 2011. Available 

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

 

7

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 rule. See AEO 

2011 and Chapter 3 and the IPM documentation for more detail.