***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 1 **CHAPTER 4**  **ELECTRIC POWER SECTO R 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 propos al , 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 t o 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Storage 151 20,538 22,160 N/A Other 48 1,042 888 N/A Total 17,876 1,121,686 1,025,400 44.9%***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 2 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. Actua l 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 el ectricity 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 20**  **10 (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 .0 % Transportation 8 0.2% **Direct Use** 135 3.5% **Total End Use 3,889**  100% Source: EIA 20 10 a In 20 10 , 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 20 10**  **(Billion kWh) Net Generation (Billion kWh)**  **Fuel Source Share** Coal 1,847 44. 8 % Petroleum 37 0 . 9 0% Natural Gas 988 2 3.9 % Other Gases 11 0.3% Nuclear 807 19.6 % Hydroelectric 260 6. 3 %***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 3 Other 175 4.2 % **Total 4,125**  **100%** Source: EIA 20 10 a 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 suppl ied “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 fo r electricity is reduced. T he 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 i mpact 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***E.O. 12866 Review– Draft

**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** S ource: 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. T his 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 separ 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 Draft– Do Not Cite, Quote, Or Release During Review ***

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 separ ate 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, respe ctively. 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 capa city 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 ate interconnected 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 approximate ly 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***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 5 monitored and controlled to ensure that elect ricity 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 t o 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 so urces 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 num ber 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 t ransmission 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 tra nsmission and distribution services needed to deliver power to consumers. In many state s , such efforts ha ve also included separating generation assets from transmission and distribution assets to form distinct economic entities. Transmission and distributi on 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 indust ry. 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 com petition 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 airline s), communications, and energy, which were all thought to be natural monopolies (prior to 1970) that warranted governmental control of***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 6 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 m ore 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 r esponse 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 issue d 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 Acti ve” in Figure 4 - 2 below). Currently, there are 15 states where price deregulation of generation (restructuring) ha s 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.***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 7 **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 cont ributor of CO 2 in particular, but also contributes to emissions of sulfur hexafluoride (SF 6 ), CH 4, and N 2 O . In 200 9 , the power sector accounted for 33 percent of total nationwide greenhouse gas emissions, measured in CO 2 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 CO 2 and other GHGs from the power sector. **Table 4** **- 5.**  **Domestic Emissions**  **of Greenhouse Gases, by Economic Sector (million metric**

**tons of CO 2**  **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***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 8 **Figure 4** **- 3**  **. Domestic Emissions**  **of Greenhouse Gases,**  **200 9 (million metric tons of CO**  **2**

**equivalent)** Sou rce: EPA 2011 **Table 4** **- 6.**  **Electricity Generation -**  **Related Greenhouse Gas Emissions ,**  **2009 (million metric**

**tons of CO 2**  **equivalent)**

**Source Total Emissions**  **CO 2**  **2,170.1** CO 2 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 **CH 4**  **0.7** Stationary Combustion* 0.7 Incineration of Waste + **N 2**  **O 9.4**  Stationary Combustion* 9.0 Incineration of Waste 0.4 **SF 6**  ****** **12.8*****E.O. 12866 Review– Draft

Electrical Transmission and Distribution **Total** Source: EPA 2011 * Includes only stationary combustion emissions related to the generation of electricity. ** SF 6 is not covered by this rule, which + Does not exceed 0.05 Tg CO 2 Eq. or 0.05 percent. The amount of CO 2 emitted during the combustion of fossil fuels varies according to the carbon content and heating value of the fuel used (EIA 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** 

**(200 9**  **)** Source: EPA 2011 **Table 4** **- 7**  **. Fossil**  **Fuel Emission Factor**

**Fuel Type** Coal Bituminous Subbituminous Lignite Natural Gas Fuel Oil Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 9 Electrical Transmission and Distribution 12.8 **2,193.0** Includes only stationary combustion emissions related to the generation of electricity. is not 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 CO 2 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 To**  **t al Domestic GHG Emissions** 

**Fuel Emission Factor s in EPA Modeling Applications**  **Carbon Dioxide (lbs/MMBtu)** 205.2 – 206.6 212.7 – 213.1 213.5 – 217.0 117.1 Do Not Cite, Quote, Or Release During Review *** 12.8 **2,193.0**

emitted during the combustion of fossil fuels varies according to the 7). Coal has higher during combustion. C oal 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)*****E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

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: CO 2 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 se veral methods to reduce CO 2 emissions from the power sector, including carbon capture and storage and improved fuel efficiency, which are discussed in more detail in the following sections . Additional methods for CO 2 reduction include switching to lower emitting fuels , increased generation share from lower- emitting sources , decreased loss of power via transmission and distribution systems , and 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 - emitti ng 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 several smaller scale industrial facilities and is currently in the demonstration phase for power sector applications . There are currently larger - scale projects under construction or in the advanced planning stages . CCS can be achieved through either pre - combustion or post - combustion capture of CO 2 from a gas stream associated with the fuel combusted. For post - combustion capture, flue gas CO 2 stripping with a liquid absorbent which selectively reacts with the gaseous carbon dioxide to remove it from the c ombustion gas stream. The absorbent, upon saturation,***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 11 transfers to a downstream operation which regenerates the absorbent by desorbing the CO 2 back to gaseous form. The absorbent recycles back into the process to repeat the capture cycle 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 CO**  **2 Capture for a Pulverized Coal Power Plant**  Source: Interagency Task Force on Carbo n Capture and Storage 2010 Pre - combustion capture is mainly applicable to I G CC 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 pr ocesses 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 p rocess 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).***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 12 **Figure 4 -**  **6. Pre**  **- Combustion CO**  **2 Capture for an IGCC Power Plant**  Source: Intera gency 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 CO 2 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 le akage 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 repla cement of inefficient or obsolete equipment, which can reduce parasitic power loads. 2 There are many small actions that can be undertaken which, cumulatively, can result in notable efficiency improvements. Such improvements include optimizing air pre - heate rs, 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)

2 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 CO 2 emission r ate of a plant, and therefore the structure of the proposed rule may not significantly increase the incentive to reduce these losses.***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 13 through a review of p ublished articles and technical papers (EPA, 2010) . The summary of these findings is shown in Table 4 - 8. **Table 4** **- 8.**  **Existing Coal -**  **Fired EGU Efficiency Improvements Reported for Actual Efficiency**

**Improvement projects Efficiency**  **Improvement Technology**  **Description Reported**  **Efficiency Increase**  **a** 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 coal fired EGU is complex and impacts a number of important operating parameters including combustion efficiency, steam temperature, furnace slagging and fouling, and NO x formation. 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 F GD 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 exchang er. 0.3 to 1.5%

(continued)***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 14 **Table 4 -**  **8. Existing Coal**  **- Fired EGU Efficiency Improvements Reported for Actual Efficiency** 

**Improvement projects (continued) Efficiency**  **Improvement Technology**  **Description Reported**  **Efficiency Increase**  **a** 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 t han 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 t o 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 s oot 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 3 2 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 eff iciency. 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 t hermal efficiency. Under constant energy input, a higher pressure and temperature for the water - steam cycle will increase the overall efficiency. Most existing boilers, h owever, 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 pressure s above 3200 psi and temperatures up to 1,100° F. Boilers that can operate above these conditions are considered***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 15 “ultra - supercritical.” Examples of ultra - supercritical coal -fired EGUs in Canada, Europe, and Japan are cited as representing the highest effici ency 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 CO 2 . As discussed previously, the amount of CO 2 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 - emittin g fuel will reduce CO 2 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 CO 2 emissions. As with increased generation efficiency, improvements to efficie ncy in transmission and electricity use will also result in reductions in CO 2 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 b e 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 requ ire that sources control greenhouse gases, only that sources above certain threshold leve ls 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 CO 2 . EPA acknowledged the Supreme Court decision, but found that decision alone did not require PSD***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 16 permits to include limits on CO 2 emis sions. 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 CO 2 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 indicat ing that the PSD Permitting Program would appl y 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 mo nitoring or reporting, such as the provisions for CO 2 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 comm ents, 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 G HG 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 — CO 2 , CH 4, N 2 O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF 6 — in the atmosphere thr eaten 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 fr om 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 . T his 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.***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 17 In May 2010, EPA issued the final Tailoring Rule which set thresholds for GHG emissions that define when permits under the New Sour ce Review PSD and T itle 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 requ irements 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 perce nt of the nation’s greenhouse gas emissions. For natural gas, oil, and coal -fired EGUs this rule establish es 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 agreement s can be found on the EPA website. 3 **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 compar ison 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 assoc iated with the generation, transmission, and distribution of electricity are expected to rebound and increase modestly by 2015, when revenues are projected to be ro ughly $360 billion (see Table 4 - 10 ). Table 4 - 9 shows that investor - owned utilities (IOUs) ea rned 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 cons umers. 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

3 http://www.epa.gov/airquality/ghgsettlement.html***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 18 electricity prices do not change rapidly and do not display the vari ability 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 sign als 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 ear ly 1960s and 1980s (see Figure 4 - 7 ). **Table 4** **- 9**  **. Revenue and Expense Statistics for Major U.S. Investor** **- Owned Electric Utilities** 

**for 20 10**  **($millions) 2008**  **200 9**  **20 10**  **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 20 10 a Note: This data does not include information for public utilities.***E.O. 12866 Review– Draft

**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 ) . Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 19 **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 tho se of other states (see Do Not Cite, Quote, Or Release During Review *** **Projected Revenues by Service Category in 2015 for Public Power and Investor**  

Data are derived by taking either total electricity use (for generation) or sales (transmission and of EIA 2011 (Electricity

The Northeast and other states (see** *E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 20 **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 pri ces to the power sector) have ranged from $3 per mmBtu to as high as $9 on an an nual 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 . EIA proje ctions of future natural gas prices assume trends that are consistent with historical and current market behavior, technological and demographic changes, and current laws and regulations . 4 Depending on actual conditions, there may be significant variation from the price projected in the reference case and the price observed. To address this uncertainty, EIA issues a range of alternative cases , including cases with higher and lower economic growth,

4 AEO 2010 Retrospective Review. http://www.eia.gov/forecasts/aeo/retrospective/***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 21 which address many of the uncertainties inherent in the long -term projections. EPA u ses the reference case and a number of alternative cases in its analyses.

**Fig ure**  **4 -**  **9 .**  **Natural Gas Spot Price, Annual Average (Henry Hub)** Source: EIA 2010 c , EIA 2011 , EIA 2012 **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) p er unit of energy input, with per capita energy use fairly constant over the past 30 years (EIA, 2010d) . The growth rate of electricity demand ed has also been in overall decline for the past sixty years (see Figure 4 - 8 ), with several key drivers that are w orth 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 expenditures, including those for energy . Third, companies are responding to the marketplace and continually develop and bring to 0 1 2 3 4 5 6 7 8 9 10

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035**2 0** **0 7** **d o** **l l** **a r** **s p** **e r** **m i** **l l** **i o** **n B** **t u** 

EIAH istor ical Na tur al Gas Spot Pr ice (Hen ryH ub) EIAP ro ject ed( 2011) N at ur al Gas Spot Pr ice (Hen ry H ub) EIAP ro ject ed( 2012) N at ur al Gas Spot Pr ice (Hen ry H ub) EIAP ro ject ed( 2010) N at ur al Gas Spot Pr ice (Hen ry H ub)***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 22 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 ).

**Figure 4** **- 10**  **. Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual** 

**Energy Outlook 2011** Source: EIA 2009 , EIA 2011 Note: Electricity demand projections in the AEO 2012 early release are very similar to those in AEO 2011 and would not be expected to change this figure notic e ably. 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. 5 These 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 5 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 thi s proposed rule. See AEO 2011 and Chapter 7 of the IPM documentation for more detail.

- 2% 0% 2% 4% 6% 8% 10% 12%***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 23 in response to price. With that in mind, EPA modeling does not typically incorpora te 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 product ion 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 costs are anticipated for a r ulemaking . 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. Availa ble 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- analy ses/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 Unite d 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.ei a.gov/electricity/annual/ .***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 - 24 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/a nnual/pdf/aer.pdf . U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011 . 2011. Available online at: http://www.eia.gov/forecasts/archive/aeo11/ . U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 201 2 (Early Release) . 2012. 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 .