***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

1 EO12866EGUGHGNSPSRIA 2060-AQ9120111104CH4.DOC

**SECTION 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 affect ed by the propos al , 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. **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)**  C oal 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Other Biomass 1,502 5,007 4,317 Pumped Storage 151 20,538 22,160 Other 48 1,042 888***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

2 Total 17,876 1,121,686 1,025,400 Source: EIA 2009 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 res idential 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 2009 (Billion kWh) Sales/Direct Use (Billion**  **kWh) Share of T** **otal 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 3,724**  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 4 - 3). **Table 4** **- 3.**  **Electricity Net Generation in 2009 (B illion 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***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

3 Note: Retail sales a re 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 typically supply “base - load” electricity, the portion of electric ity 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 nota ble 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 ab le 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 peopl e 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. 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 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 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 **Totals 1,266**  **316,480** Source: National Electric Energy Data System (NEEDS) v.4.10***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

4 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 lo wer 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.

**Figure 4** **- 1.**  **Fossil Fuel -**  **Fired Electricity Generating Facilities, by Size** S ource : National Electric Energy Data System (NEEDS ) 4.10 Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capa city on - line by the end of 2011. T his includes planned new builds and planned retirements. In areas with a den se 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 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 op eration 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

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

5 operator; in others, individual utilit ies 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 ha ve 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 gene ration 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 p ower 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 transmission 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 distributio n 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 t he 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 im portant 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 pow er sector were most active during the 1990s. Some of the primary drivers for deregulation of electric power included the desire for more***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

6 efficient investment choices, the economic incentive to provide least - cost electric rates through market competition , r educed 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 o f 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 o r 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) ha s occurred (“Active” in Figure 4 - 2 below). Power sector restructuring i s 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 .

**F igure**  **4 -**  **2. Status of State Electricity Industry Restructuring Activities**  Source: EIA 2010b. **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***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

7 of CO 2 in particular, but also contributes to emissions of sulfur hexafluoride (SF 6 ), methane (CH 4 ), and nitrous oxide (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 sh ow 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

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

**equivalent)** Sou rce: EPA 2011***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

8 **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** 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 **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** Electrical Transmission and Distribution 12.8 **Total 2,193.0**  Source: EPA 2011 * Includes only stationary combustion emission s related to the generation of electricity. ** SF 6 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 CO 2 emitted during the combustion of fossil fuels v aries 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 oal 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 (EIA 2004).***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

9 **Figure 4** **- 4.**  **GHG Emissions from the Power Sector**  **Relative to To t**  **al Domestic GHG Emissions**

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

**Fuel Type Carbon Dioxide (lbs/MMBtu)**  Coal Bituminous 205.2 – 206.6 Subbituminous 212.7 – 213.1 Lignite 213.5 – 217.0 Natural Gas 117.1 Fuel Oil Distillate 161.4 Residual 161.4 – 173.9 Biomass* 195 Waste Fuels Waste Coa l 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 ac count for combustion only and do not reflect lifecycle emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon source).***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

10 **4 .5**  **Pollution Control Technologies** There are several methods to reduce CO 2 emissions fr om 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 s ystems; 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). Incr eased 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 CO 2 from a gas stream associated wit h the fuel combusted. For post - combustion capture, flue gas CO 2 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 downstr eam 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. Pre combustio n capture is mainly applicable to Integrated Gasification Combined Cycle (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 p rocesses 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). For m ore detail on the current state of CCS technology, see the “Report of the 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 CO 2 and other emissions per unit of energy generated . Numerous alternatives are available for improving***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

11 generating unit efficiency (Sargent & Lundy 2009). Regular mainten ance 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 prope rly, and repairing tube leaks. Efficiency gains can also be achieved through replacement of inefficient or obsolete equipment, which can reduce parasitic power loads. 1 There are many small actions that can be undertaken which, cumulatively, can result in n otable 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 id entified by the National Energy Technology Laboratory (NETL) through a review of published articles and technical papers. The summary of these findings is shown in Table 6 - 8. **Table 4** **- 8.**  **Existing Coal -**  **Fired EGU Efficiency Improvements Reported for Actual E fficiency** 

**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 t echnologies 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 c oal 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 r ecover 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 su rface) and tuning the cooling tower and condenser. 0.2 to 1%

1 Reducing parasitic power loads increases the amount of generation for sale a nd 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 rate 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 ***

12 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 concentr ation 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 en ergy in the flue gas to preheat boiler feedwater via use of a condensing heat exchanger. 0.3 to 1.5%

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

**Improvement projects (continued) Efficiency**  **Improve ment**  **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 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 blow ing 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 ma nufacturers 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% boiler efficiency, 40% turbine efficiency, 98% generator efficiency, and 6% auxiliary load. Based on these assumptions, the reference power plant has an overall efficiency of 32% 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% point increase in boiler efficiency, it would be converted to a 0.37 % point increa se in overall efficiency. Likewise, a reported 100 Btu/kWh decrease in net heat rate would be converted to a 0.30% point increase in overall efficiency. In addition to the techniques described above, new coal - fired EGU projects may use other methods to max imize thermal efficiency. Under constant energy input, increasing the pressure and temperature for the water- steam cycle will increase the overall efficiency. However, there is a limit the maximum pressure and temperature that a typical boiler can***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

13 withstan d. Most coal -fired EGUs currently 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. Subcritical boilers can be designed to operate at a pressure of up to 3,200 psi and temperatures up to 1,050° F. “Supercritical” boilers are those that use steam pressures of 3,500 psi and temperatures of 1,075 ° F, but can be designed to operate at pressures as high as 3,600 psi and temperatures up to 1,100° F. Boilers that can operate above these conditions are considered “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 .6**  **GHG Regulation in the P ower 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 contr ibute 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 s ources, 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 rele vant 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 futur e policy decisions. As such, it did not require that sources control greenhouse gases, only that sources above certain threshold leve ls monitor and report emissions. In August 2007, EPA issued a Prevention of Significant Deterioration (PSD) permit to Deser et 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, b ut found that decision alone did not require PSD permits to include limits on CO 2 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 impo se a CO2 BACT limit in light of the ‘subject to regulation’ definition under the CAA.” The remand was based in part on EAB’s***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

14 finding that there was not an established EPA interpretation of the regulatory phrase “subject to regulation.” In December 2008, t he 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. T he memo further explained that pollutants for which EPA regulations only require monitoring 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 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 p ollutant. 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 Administra tor 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 — carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 ) — 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 . T his action was a pre requisite 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 T itle V programs. 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 T itle V Operating Permit***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

15 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 these rules would est ablish new source performance standards (NSPS) for EGUs. This RIA describes the economic impact analysis performed for the rule proposal that responds to the EGU settlement agreement. Details of the settlement agreement 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. However, operating expenses were appreciably lower and as a result, net i ncome actually rose modestly compared to 2008 (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, where they are projected to be ro ughly $360 billion (see Table 4 - 10 ). Based on EIA's Annual Energy Outlook 2011, Table 4 - 10 shows that in the base case, the power sector is expected to derive revenues of $360 billion in 2015. Table 4 - 9 shows that investor- owned utilities (IOUs) earned income of about 11.5% compared to t otal 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 2 015 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

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

16 types of customers . Retail rate regulation has largely insul ated 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 electric ity today is lower than it was in the ear ly 1960s and 1980s (see Figure 4 - 5 ). **Table 4** **- 9**  **. 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 8,9 37 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 26,2 02 29,081 Other Utility 30,692 24,698 **Net Utility Operating Income 31,699**  **31,881** Source: EIA 2009 Note: This data does not include information for public utilities. **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** ***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

17 Source: EIA 2011 Note: Data are derived by taking either total electricity use (for generation) or sales (transmission and distribution) and multiplying by forecast ed prices by service category from Table 8 (Electricity Supply, Disposition, Prices, and Emissions).

**Figure 4** **- 5**  **. National Average Retail Electricity Price (1960**  **– 2009)**  Source: EIA 2009 On a state - by- state basis, retail electricity prices vary considera bly. The Northeast and California have average retail prices that can be as much as double tho se of other states (see Figure 4 - 6 ) .***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

18 **Figure 4 -**  **6. Average Retail Electricity Price by State (cents/kWh), 2009**  Source: EIA 2009 **4 .7.1**  **Natural Gas Market**  The nat ural 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 s pikes 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 an nual average basis (see Figure 4 - 7 ). During that time, the daily price of nat ural 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 q uantity of the resource base .***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

19 **Fig ure**  **4 -**  **7 .**  **Natural Gas Spot Price, Annual Average (Henry Hub)** Source: EIA 2010a, EIA 2011 **4 .8**  **Electricity Demand and Demand Response** Electricity performs a vital and high - value function in the economy. Historically, growt h 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 yea rs. 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 worth noting. First, there has been a significant structural shift in the U.S. economy towards less en ergy- 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 cons umption. 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 - 8 ).***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

20 **Figure 4** **- 8**  **. 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 incre ase for the next 5 to 10 years, driven in part by the growing number of states that have adopted energy efficiency resource standards. 1 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 in response to price. With that in mind, EPA modeling does not typically incorporate a “demand response” in its electric generat ion 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 and the IPM documentation for more detail.***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

21 costs are anticipated for a rulemaking . Note that this NSPS is not anticipa ted 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 Improvin g 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 . Pac ific 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/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.htm . 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 Elec tricity Restructuring by State.” 2010b. Available online at: http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html . U.S. Energy Informatio n Administration (U.S. EIA). Annual Energy Outlook 2011 . 2011. Available online at: http://www.eia.gov/forecasts/aeo/ .***E.O. 12866 Review– Draft– Do Not Cite, Quote, Or Release During Review ***

22 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 P rotection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–

2009 . April 2011. Available online at: http://epa.gov/climatec hange/emissions/downloads11/US - GHG - Inventory- 2011 - Complete_Report.pdf .